OFFERING MEMORANDUM CONFIDENTIAL

E.ON International Finance B.V. Amsterdam, The Netherlands U.S. $3,000,000,000 consisting of U.S.$2,000,000,000 5.80% Notes due 2018 U.S.$1,000,000,000 6.65% Notes due 2038 With an unconditional and irrevocable guarantee as to payment of principal and interest from E.ON AG

The notes due 2018 (the “2018 Notes”) will bear interest at a rate of 5.80% per year and the notes due 2038 (the “2038 Notes” and, together with the 2018 Notes, the “Notes”) will bear interest at a rate of 6.65% per year. Interest on the Notes will be payable semi-annually in arrears on October 30 and April 30 of each year, commencing on October 30, 2008. The 2018 Notes and 2038 Notes will mature on April 30, 2018, and April 30, 2038, respectively. The Notes will be issued by E.ON International Finance B.V. (the “Issuer”) and will be unconditionally guaranteed by E.ON AG (the “Guarantor”). See “Description of the Notes.” The Issuer may, at its option, redeem the Notes in whole or in part at any time by paying a “make whole premium” as specified herein. See “Description of the Notes — Optional Redemption.” The Issuer may also redeem the Notes at the Issuer’s (or, if applicable, the Guarantor’s) option, in whole but not in part, at 100% of their principal amount then outstanding plus accrued interest if certain tax events occur as described in this offering memorandum. Upon the occurrence of certain change of control events, each holder of Notes (a “Holder”) may require the Issuer to repay all or a portion of its Notes as more particularly described under “Description of the Notes — Holders’ Option to Repayment upon a Change in Control”. The Issuer does not intend to apply to list the Notes on any securities exchange.

Investing in the Notes involves risks. See “Risk Factors” beginning on page 22. The Notes have not been and will not be registered under the U.S. Securities Act of 1933, as amended (the “Securities Act”). The Notes may be offered or sold in the United States only to Qualified Institutional Buyers as defined in, and in reliance on, Rule 144A under the Securities Act (“Rule 144A”) or outside the United States to non-U.S. persons in reliance on Regulation S under the Securities Act (“Regulation S”). Prospective investors that are Qualified Institutional Buyers are hereby notified that sellers of Notes may be relying on the exemption from the provisions of Section 5 of the Securities Act provided by Rule 144A. The Notes are not transferable except in accordance with the restrictions described under “Transfer Restrictions.”

Issue Price: 99.578% of the principal amount of the 2018 Notes and 99.572% of the principal amount of the 2038 Notes. The Notes will be represented by one or more global notes registered in the name of the nominee of The Depositary Trust Company (“DTC”), as depositary. Beneficial interests in the Notes will be shown on, and transfers thereof will be effected through, records maintained by DTC, Clearstream Banking, société anonyme (“Clearstream”) and Euroclear Bank S.A/N.V. (“Euroclear”), and their respective participants. See “Transfer Restrictions.” The Initial Purchasers (as defined in “Plan of Distribution”) expect to deliver the Notes against payment in immediately available funds on or about April 22, 2008. Joint Book-Running Managers Banc of America Securities LLC Deutsche Bank Securities Goldman, Sachs & Co. JPMorgan

Co-Managers Lehman Brothers Merrill Lynch & Co. RBS Greenwich Capital The date of this offering memorandum is April 15, 2008.

TABLE OF CONTENTS

Page CERTAIN DEFINITIONS ...... 4 PRESENTATION OF FINANCIAL DATA ...... 5 AVAILABLE INFORMATION ...... 6 FORWARD-LOOKING STATEMENTS ...... 7 SUMMARY ...... 8 RISK FACTORS ...... 22 USE OF PROCEEDS ...... 35 EXCHANGE RATE INFORMATION ...... 36 CAPITALIZATION ...... 37 OPERATING AND FINANCIAL REVIEW AND PROSPECTS ...... 38 BUSINESS ...... 90 DIRECTORS AND SENIOR MANAGEMENT ...... 180 DESCRIPTION OF THE NOTES ...... 189 BOOK-ENTRY; DELIVERY AND FORM ...... 199 TAXATION ...... 204 PLAN OF DISTRIBUTION ...... 212 TRANSFER RESTRICTIONS ...... 216 LEGAL MATTERS ...... 220 INDEPENDENT ACCOUNTANTS ...... 221 LIMITATIONS ON ENFORCEMENT OF U.S. LAWS AGAINST THE GUARANTOR, THE ISSUER, THEIR MANAGEMENT, AND OTHERS ...... 222 GENERAL INFORMATION ABOUT THE ISSUER ...... 234 INDEX TO FINANCIAL STATEMENTS ...... F-1

You should rely on the information contained in this offering memorandum. We have not, and the Initial Purchasers have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should assume that the information appearing in this offering memorandum is accurate as of the date on the front cover of this offering memorandum only. Our business, financial condition, results of operations and prospects may have changed since that date.

This offering memorandum is confidential. You are authorized to use this offering memorandum solely for the purpose of considering the purchase of the Notes described in this offering memorandum. You may not reproduce or distribute this offering memorandum, in whole or in part, and you may not disclose any of the contents of this offering memorandum or use any information herein for any purpose other than considering a purchase of the Notes. You agree to the foregoing by accepting delivery of this offering memorandum.

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES (“RSA”) WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE IMPLIES THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT ANY EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

1 This offering memorandum has been prepared on the basis that any offer of Notes in any Member State of the European Economic Area which has implemented the Prospectus Directive (2003/71/EC) (each, a “Relevant Member State”) will be made pursuant to an exemption under the Prospectus Directive, as implemented in that Relevant Member State, from the requirement to publish a prospectus for offers of Notes. Accordingly any person making or intending to make an offer in that Relevant Member State of Notes which are the subject of the offering contemplated in this offering memorandum may only do so in circumstances in which no obligation arises for the Issuer or any of the Initial Purchasers to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive, in each case, in relation to such offer. Neither the Issuer nor the Initial Purchasers have authorised, nor do they authorise, the making of any offer of Notes in circumstances in which an obligation arises for the Issuer or the Initial Purchasers to publish or supplement a prospectus for such offer.

Each Initial Purchaser, other than Goldman, Sachs & Co., represents and agrees with the Issuer that it has not offered or sold and will not offer or sell any of the Notes in The Netherlands other than through one or more investment firms acting as principals and having the Dutch regulatory capacity to make such offers or sales.

Each investor in the Notes will be deemed to make certain representations, warranties and agreements regarding the manner of purchase and subsequent transfers of the Notes. These representations, warranties and agreements are described in “Transfer Restrictions.”

The Initial Purchasers make no representation or warranty, expressed or implied, as to the accuracy or completeness of such information, and nothing contained in this offering memorandum is, or shall be relied upon as, a promise or representation by the Initial Purchasers. Neither we, nor the Initial Purchasers, nor any of our or their respective representatives make any representation to any offeree or purchaser of the Notes offered hereby regarding the legality of an investment by such offeree or purchaser under applicable legal investment or similar laws. You should consult with your own advisors as to legal, tax, business, financial and related aspects of a purchase of the Notes. Notwithstanding anything herein to the contrary, investors may disclose to any and all persons, without limitation of any kind, the U.S. federal or state income tax treatment and tax structure of the offering and all materials of any kind (including opinions or other tax analyses) that are provided to the investors relating to such tax treatment and tax structure. However, any information relating to the U.S. federal income tax treatment or tax structure shall remain confidential (and the foregoing sentence shall not apply) to the extent reasonably necessary to enable any person to comply with applicable securities laws. For this purpose, “tax structure” means any facts relevant to the U.S. federal or state income tax treatment of the offering but does not include information relating to the identity of the issuer of the securities, the issuer of any assets underlying the securities, or any of their respective affiliates that are offering the securities.

IN CONNECTION WITH THE OFFERING, BANC OF AMERICA SECURITIES LLC, ACTING FOR THE BENEFIT OF THE INITIAL PURCHASERS, MAY PURCHASE AND SELL NOTES IN THE OPEN MARKET. THESE TRANSACTIONS MAY INCLUDE OVER-ALLOTMENT, SYNDICATE COVERING AND STABILIZING TRANSACTIONS. OVER-ALLOTMENT INVOLVES SALES OF NOTES IN EXCESS OF THE PRINCIPAL AMOUNT OF THE NOTES TO BE PURCHASED IN THE OFFERING, WHICH CREATES A SHORT POSITION. SYNDICATE COVERING INVOLVE PURCHASES OF THE NOTES IN THE OPEN MARKET AFTER THE DISTRIBUTION HAS BEEN COMPLETED IN ORDER TO COVER SHORT POSITIONS CREATED. STABILIZING TRANSACTIONS CONSIST OF CERTAIN BIDS OR PURCHASES OF NOTES MADE FOR THE PURPOSE OF PEGGING, FIXING OR MAINTAINING THE PRICE OF THE NOTES. ANY STABILIZATION ACTION OR OVER-ALLOTMENT MUST BE CONDUCTED BY THE RELEVANT STABILIZING MANAGER(S) (OR PERSON(S) ACTING ON BEHALF OF ANY STABILIZING MANAGER(S)) IN ACCORDANCE WITH ALL APPLICABLE LAWS AND RULES.

2 IN CONNECTION WITH THIS OFFERING, THE INITIAL PURCHASERS ARE NOT ACTING FOR ANYONE OTHER THAN THE ISSUER AND WILL NOT BE RESPONSIBLE TO ANYONE OTHER THAN THE ISSUER FOR PROVIDING THE PROTECTIONS AFFORDED TO THEIR CLIENTS NOR FOR PROVIDING ADVICE IN RELATION TO THE OFFERING.

NOTICE TO INVESTORS IN THE UNITED KINGDOM

This offering memorandum is for distribution within the United Kingdom only to persons who (i) have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (as amended, the “Financial Promotion Order”), (ii) are persons falling within Article 49(2)(a) to (d) of the Financial Promotion Order, (iii) are outside the United Kingdom or (iv) are persons to whom an invitation or inducement to engage in investment activity (within the meaning of section 21 of the Financial Services and Markets Act 2000) in connection with the issue or sale of any Notes may otherwise lawfully be communicated or caused to be communicated (all such persons together being referred to as “Relevant Persons”). This document is directed only at Relevant Persons and must not be acted on or relied on by persons who are not Relevant Persons. Any investment or investment activity to which this document relates is available only to Relevant Persons and will be engaged in only with Relevant Persons.

NOTICE TO INVESTORS IN THE EUROPEAN ECONOMIC AREA

In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each Initial Purchaser has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), it has not made and will not make an offer of Notes to the public in that Relevant Member State, except that it may, with effect from and including the Relevant Implementation Date, make an offer of Notes to the public in that Relevant Member State: • to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities; • to any legal entity which has two or more of: (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43,000,000; and (iii) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; • to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the Initial Purchasers for any such offer; or • in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of Notes shall require the Issuer or any of the Initial Purchasers to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of Notes to the public” in relation to any Notes in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe to the Notes, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

3 CERTAIN DEFINITIONS

“E.ON,” the “Company,” “we”, “us”, “our”, the “E.ON Group” or the “Group” refers to E.ON AG and its consolidated subsidiaries. The “Guarantor” refers to E.ON AG.

“VEBA” refers to VEBA AG and its consolidated subsidiaries prior to its merger with VIAG AG and the name change from VEBA AG to E.ON AG. “VIAG” or the “VIAG Group” refers to VIAG AG and its consolidated subsidiaries prior to its merger with VEBA.

“PreussenElektra” refers to PreussenElektra AG and its consolidated subsidiaries, which merged with Bayernwerk AG and its consolidated subsidiaries to form E.ON’s German and continental European energy business in the Central Europe market unit, consisting of E.ON Energie AG and its consolidated subsidiaries (“E.ON Energie”).

“E.ON Ruhrgas” refers to E.ON Ruhrgas AG (formerly Ruhrgas AG or “Ruhrgas”) and its consolidated subsidiaries, which collectively comprise E.ON’s gas business in the Pan-European Gas market unit.

“E.ON UK” refers to E.ON UK plc (formerly Powergen UK plc or “Powergen”) and its consolidated subsidiaries, which collectively comprise E.ON’s U.K. energy business in the U.K. market unit. Until December 31, 2003, Powergen and its consolidated subsidiaries, including LG&E Energy LLC (“LG&E Energy”), which was held by Powergen until its transfer to a direct subsidiary of E.ON AG in March 2003, formed E.ON’s former Powergen division (“Powergen Group”).

“E.ON Sverige” refers to E.ON Sverige AB (formerly Sydkraft AB or “Sydkraft”) and its consolidated subsidiaries, and “E.ON Finland” refers to E.ON Finland Oyj and its consolidated subsidiaries, which collectively comprised E.ON’s Nordic energy business in the Nordic market unit until the disposal of E.ON Finland.

“E.ON U.S.” refers to E.ON U.S. LLC (formerly LG&E Energy) and its consolidated subsidiaries, which collectively comprise E.ON’s U.S. energy business in the U.S. Midwest market unit. Until December 31, 2003, E.ON U.S. formed the U.S. business of the Powergen Group.

“Viterra” refers to Viterra AG and its consolidated subsidiaries, which collectively comprised E.ON’s real estate business in the other activities segment.

“Degussa” refers to Degussa AG and its consolidated subsidiaries, which collectively comprised E.ON’s chemicals business in the other activities segment.

“VEBA Oel” refers to VEBA Oel AG and its consolidated subsidiaries, which collectively comprised E.ON’s former oil division.

“VAW” refers to VAW aluminium AG and its consolidated subsidiaries, which collectively comprised E.ON’s former aluminum division.

As used in this offering memorandum, “euro” or “€” means the single unified currency that was introduced in Germany on January 1, 1999; “U.S. dollar,” “U.S.$,” “USD” or “$” means the lawful currency of the United States of America; “GBP” means the lawful currency of the United Kingdom; and “CHF” means the lawful currency of Switzerland. “Germany” means the Federal Republic of Germany.

A watt is a standard measure of electric power. “kW” means kilowatt, which is equal to 1,000 watts, “MW” means megawatt, which is equal to 1,000 kilowatts, or one million watts, “GW” means gigawatt, which is equal to 1,000 megawatts, and “TW” means terawatt, which is equal to 1,000 gigawatts. MW is a standard measure of electric power plant generating capacity. “kWh” means kilowatt-hour and is a standard unit of energy. “MWh” means megawatt-hour, which is equal to 1,000 kilowatt-hours, “GWh” means gigawatt-hour, which is equal to 1,000 megawatt-hours, and “TWh” means terawatt-hour, which is equal to 1,000 gigawatt-hours.

4 PRESENTATION OF FINANCIAL DATA

Accounting Principles In 2002, the European Parliament and the European Council mandated the adoption of International Financial Reporting Standards (“IFRS”), as adopted by the European Union (“EU”), by companies whose securities are publicly traded on a regulated market in an EU member state, in respect of fiscal years beginning on or after January 1, 2005. E.ON made use of the option available under German law for companies that had been preparing their consolidated financial statements in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and whose stock was officially listed for public trading in a non-EU member state to defer the mandatory adoption of IFRS until 2007. Until December 31, 2006, E.ON prepared its financial statements in accordance with U.S. GAAP. E.ON’s American Depositary Shares (“ADSs”) were listed on the New York Stock Exchange until September 7, 2007. The Company deregistered and terminated its reporting obligations with the U.S. Securities and Exchange Commission (the “SEC”) as of December 2007.

E.ON’s consolidated financial statements for the year ended December 31, 2007, as included in this offering memorandum, have been prepared in accordance with IFRS 1, First-time Adoption of International Financial Reporting Standards (“IFRS 1”). These consolidated financial statements have also been prepared in accordance with Article 315a (1) of the German Commercial Code (Handelsgesetzbuch, or “HGB”) and with those IFRS and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations that had been adopted by the European Commission for use in the EU as of the end of the fiscal year, and whose application was mandatory as of December 31, 2007. In addition, E.ON has elected the voluntary early adoption of IFRS 8, Operating Segments (“IFRS 8”). E.ON’s consolidated financial statements through the year ended December 31, 2006 were prepared in accordance with U.S. GAAP. For information about the effects of the transition from U.S. GAAP to IFRS, see Note 35 of the Notes to Consolidated Financial Statements.

The analysis of E.ON’s consolidated results and those of its individual market units in 2007 and 2006 presented in this offering memorandum under “Operating and Financial Review and Prospects” has been prepared using the financial statements prepared in accordance with IFRS. As E.ON has not prepared any financial statements for 2005 in accordance with IFRS, the parallel year-on-year analysis of our results for 2005 and 2006 (see “Operating and Financial Review and Prospects — Year Ended December 31, 2006 Compared with Year Ended December 31, 2005”) has been prepared on the basis of E.ON’s U.S. GAAP consolidated financial statements (included in our Annual Report on Form 20-F for the fiscal year ended December 31, 2006 and incorporated herein by reference). Unless otherwise indicated, financial data for 2006 appearing outside of such year-on-year analysis (e.g., in the analysis of Liquidity and Capital Resources and that of Cash Flow and Capital Expenditures) (see “Operating and Financial Review and Prospects — Liquidity and Capital Resources”), has been prepared in accordance with IFRS.

Sales Unless otherwise indicated, sales are presented net of electricity and energy taxes.

Non-GAAP Measures E.ON uses “adjusted EBIT” as the measure pursuant to which the Group evaluates the performance of its segments and allocates resources to them. Adjusted EBIT is an adjusted figure derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment basis) before income taxes and interest income. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and other non-operating earnings of an exceptional nature. In addition, net interest income is adjusted using economic criteria and excluding certain special items, (i.e., the portions of interest expense that are non-operating). During all relevant periods, E.ON has used adjusted EBIT as its primary segment reporting measure, originally in accordance with Statement of Financial Accounting Standards

5 (“SFAS”) No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS 131”) under U.S. GAAP, and now in accordance with IFRS 8. However, on a consolidated Group basis, adjusted EBIT is considered a non-GAAP measure that should be reconciled to the most directly comparable GAAP measure. Adjusted EBIT should not be considered in isolation as a measure of E.ON’s profitability and should be considered in addition to, rather than as a substitute for the most directly comparable GAAP measures. In particular, there are material limitations associated with the use of Adjusted EBIT as compared with such GAAP measures, including the limitations inherent in E.ON’s determination of each of the adjustments noted above. E.ON seeks to compensate for those limitations by providing below a detailed reconciliation of adjusted EBIT to income from continuing operations before income taxes and minority interests and net income, the most directly comparable GAAP measures, as well as the more detailed textual analysis of year-on-year changes in the key components of each of the reconciling items appearing under the caption “Operating and Financial Review and Prospects — Results of Operations — E.ON Group — Reconciliation of Adjusted EBIT” for each of the relevant periods. As a result of these limitations and other factors, adjusted EBIT as used by E.ON may differ from, and not be comparable to, similarly titled measures used by other companies. For further details, see Note 33 of the Notes to Consolidated Financial Statements.

E.ON has calculated operating data for Group companies appearing in this document using actual amounts derived from Group books and records. The Company has obtained market-related data such as the market position of Group companies from publicly available sources such as industry publications. The Company has relied on the accuracy of information from publicly available sources without independent verification, and does not accept any responsibility for the accuracy or completeness of such information.

Incorporation of Certain Financial Statements by Reference We incorporate by reference herein our consolidated financial statements, and accompanying notes and report of independent registered public accounting firm, at December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004, filed as part of our annual report on Form 20-F for the fiscal year ended December 31, 2006 filed with the SEC on March 7, 2007 (the “Form 20-F for 2006”). No materials from the SEC website or any other source other than those specifically identified above are incorporated by reference into this offering memorandum.

Any statement contained in the information that is incorporated by reference will be modified or superseded for all purposes to the extent that a statement contained in this offering memorandum modifies or is contrary to that previous statement. Any statement so modified or superseded will not be deemed a part of this offering memorandum except as so modified and superseded.

AVAILABLE INFORMATION

For so long as any of the Notes remain outstanding and are “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act and during any period in relation thereto during which the Guarantor is neither subject to sections 13 or 15(d) of the Exchange Act nor exempt from reporting pursuant to Rule 12g3- 2(b) under the Exchange Act, the Issuer and the Guarantor will make available on request to each holder in connection with any resale thereof and to any prospective purchaser of such Notes from such holder, in each case upon request, the information specified in and meeting the requirements of Rule 144A(d)(4) under the Securities Act.

A copy of the Fiscal and Paying Agency Agreement is available to prospective investors in the Notes upon request, at no charge, from HSBC Bank USA, N.A., at 10 East 40th Street, New York, NY10016.

6 FORWARD-LOOKING STATEMENTS

This offering memorandum contains certain forward-looking statements and information relating to E.ON that are based on beliefs of its management, as well as assumptions made by and information currently available to E.ON. When used in this offering memorandum, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “project” and similar expressions, as they relate to E.ON or its management, are intended to identify forward-looking statements. Such statements reflect the current views of E.ON with respect to future events and are subject to certain risks, uncertainties and assumptions. Many factors could cause the actual results, performance or achievements of E.ON to be materially different from any future results, performance or achievements that may be expressed or implied by such forward-looking statements, including, among others, strong competition in our core energy operations that could depress margins, changes in applicable laws and regulations as well as the introduction of new laws and regulations, rising fuel prices, unreliable gas supplies from Russia, revenues that fluctuate by season and according to the weather, volume and price risks inherent in our long-term gas supply contracts, cancellation of contracts due to government action, unsuccessful acquisitions and investments, environmental liabilities, power outages or shutdowns involving our electricity operations, litigation, actions by regulators and competition authorities and actions by credit rating agencies, and various other factors, both referenced in this offering memorandum, including under “Risk Factors”, and not referenced in this offering memorandum. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in this offering memorandum as anticipated, believed, estimated, expected, intended, planned or projected. E.ON does not intend or assume any obligation to update or revise these forward-looking statements after the date of this offering memorandum in light of developments which differ from those anticipated.

7 SUMMARY

This summary highlights some information from this offering memorandum, and it may not contain all of the information that is important to you. You should read the following summary together with the more detailed information regarding E.ON and the Notes being sold in this offering included in this offering memorandum.

BUSINESS OVERVIEW

Our Business We are the largest industrial group in Germany, measured on the basis of our market capitalization of approximately €92 billion at December 31, 2007. For the year ended December 31, 2007, we had sales of €68.7 billion, having sold 471 TWh of power and 1,212 TWh of gas. At year end, we employed 87, 815 people.

As of December 31, 2007, our core energy business was organized into the following five market units: Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest.

Central Europe. E.ON Energie AG (“E.ON Energie”) is the lead company of our Central Europe market unit. E.ON Energie is one of the largest non-state-owned European power companies in terms of electricity sales. E.ON Energie’s core business consists of the ownership and operation of power generation facilities and the transmission, distribution and sale of electricity and, to a lesser extent, gas and heat, to interregional, regional and municipal utilities, traders and industrial, commercial and residential customers. Furthermore, E.ON Energie operates waste incineration facilities. The Central Europe market unit owns interests in and operates power stations with a total installed capacity of approximately 37,200 MW, of which Central Europe’s attributable share is approximately 28,500 MW (not including mothballed, shutdown and cold reserve plants). In 2007, E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in Germany. In 2007, the Central Europe market unit recorded revenues of €32.0 billion and an adjusted EBIT of €4.7 billion. For a definition of adjusted EBIT, see “— Summary Consolidated Financial Data.”

Pan European Gas. E.ON Ruhrgas AG (“E.ON Ruhrgas”) is the lead company of the Pan-European Gas market unit and is responsible for all of E.ON’s non-retail gas activities in continental Europe. E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas company in Germany in terms of gas sales, with 712.8 billion kilowatt hours (“kWh”) of gas sold in 2007. E.ON Ruhrgas’ principal business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas purchases nearly all of its natural gas from producers in six countries: Russia, Norway, the Netherlands, Germany, the United Kingdom and Denmark. E.ON Ruhrgas sells this gas to supra-regional and regional distributors, municipal utilities and industrial customers in Germany and increasingly also delivers gas to customers in other European countries. In addition, E.ON Ruhrgas is active in gas transmission within Germany via a network of approximately 11,611 kilometers (“km”) of gas pipelines and operates a number of underground storage facilities in Germany. E.ON Ruhrgas also holds numerous stakes in German and other European gas transportation and distribution companies, as well as a 6.4 percent shareholding in OAO Gazprom, Russia’s main natural gas exploration, production, transportation and marketing company. In 2007, the Pan-European Gas market unit recorded revenues of €22.7 billion and adjusted EBIT of €2.6 billion.

U.K. E.ON UK plc (formerly Powergen UK plc) (“E.ON UK”) is the lead company of the U.K. market unit and is one of the leading integrated electricity and gas companies in the United Kingdom. E.ON UK and its associated companies are involved in electricity generation, distribution, retail and trading. As of December 31, 2007, E.ON UK owned or through joint ventures had an attributable interest in 10,581 MW of generation capacity. E.ON UK served approximately 8.0 million electricity and gas customer accounts at December 31, 2007 and its Central Networks business served 4.9 million customer connections. In 2007, the U.K. market unit recorded sales of €12.6 billion and an adjusted EBIT of €1.1 billion.

8 Nordic. E.ON Nordic AB (“E.ON Nordic”) is the lead company of the Nordic market unit. E.ON Nordic’s principal business, carried out mainly through E.ON Sverige AB (“E.ON Sverige”), is the generation, distribution, sale and trading of electricity, gas and heat and waste, mainly in Sweden. E.ON Sverige is the second-largest Swedish utility (on the basis of electricity sales and production capacity). E.ON Nordic is the largest shareholder in E.ON Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent voting interest. Statkraft (“Statkraft” refers to Statkraft AS and its consolidated subsidiaries), the other shareholder in E.ON Sverige and E.ON AG have on October 12, 2007 signed a letter of intent stating that E.ON AG will take over Statkraft’s 44.6 percent interest in E.ON Sverige’s share capital in the second or third quarter of 2008. As of December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power stations with a total installed capacity of approximately 18,300 MW, of which its attributable share was approximately 7,400 MW (not including mothballed and shutdown power plants). In 2007, E.ON Nordic recorded sales of €3.3 billion, and adjusted EBIT of €670 million.

U.S. Midwest. E.ON U.S. LLC (“E.ON U.S.”) is the lead company of the U.S. Midwest market unit. E.ON U.S. is a diversified energy services company with businesses in power generation, retail gas and electric utility services, as well as asset-based energy marketing. E.ON U.S.’s power generation and retail electricity and gas services are located principally in Kentucky, with a small customer base in Virginia and Tennessee. As of December 31, 2007, E.ON U.S. owned or controlled aggregate generating capacity of approximately 7,500 MW. In 2007, E.ON U.S. served more than one million customers. In 2007, the U.S. Midwest market unit recorded sales of €1.8 billion, and adjusted EBIT of €388 million.

Corporate Center. The Corporate Center consists of E.ON AG itself, those interests owned directly and indirectly by E.ON AG that have not been allocated to any of the other segments, including its remaining telecommunications interests (until their disposal), and for 2007 the newly acquired companies Airtricity Inc. and Airtricity Holdings (Canada) Ltd. (collectively “Airtricity”), ENERGI E2 Renovables Ibéricas S.L.U. (“E2-I”) and OAO OGK-4 (“OGK-4”). The Corporate Center’s results also reflect consolidation effects at the Group level, including the elimination of intersegment sales.

The following table sets forth the sales of E.ON’s market units (as well as the Corporate Center) for 2007 and 2006:

2007 2006 (€ in millions) % (€ in millions) % Central Europe ...... 32,029 46.6 27,197 42.5 Pan-European Gas ...... 22,745 33.1 22,947 35.8 U.K...... 12,584 18.3 12,518 19.5 Nordic(1) ...... 3,339 4.9 2,827 4.4 U.S. Midwest(1) ...... 1,819 2.6 1,930 3.0 Corporate Center(1)(2)(3) ...... (3,785) (5.5) (3,328) (5.2) Total Sales ...... 68,731 100.0 64,091 100.0

(1) Excludes the sales of certain activities now accounted for as discontinued operations. For more details, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions” and Note 4 of the Notes to Consolidated Financial Statements. (2) Includes primarily the parent company and effects from consolidation, as well as the results of certain other interests, as noted above. (3) Excludes intercompany sales.

Most of E.ON’s operations are in Germany. German operations produced 59.1 percent of E.ON’s revenues (measured by location of operation) in 2007 (2006: 60.8 percent). E.ON also has a significant presence outside

9 Germany representing 40.9 percent of revenues by location of operation for 2007 (2006: 39.2 percent). In 2007, 53.7 percent (2006: 54.5 percent) of E.ON’s revenues were derived from customers in Germany and 46.3 percent (2006: 45.5 percent) from customers outside Germany. For more details about the segmentation of E.ON’s revenues by location of operation and customers for the years 2007 and 2006, see Note 33 of the Notes to Consolidated Financial Statements. At December 31, 2007, E.ON had 87,815 employees, approximately 39.4 percent of whom were employed in Germany. For more information about employees, see “Business — Employees.”

Recent Developments New Market Units Since January 1, 2008, E.ON has been organized into nine different market units having added the Energy Trading, Italy, Russia and Climate & Renewables market units. After completing the acquisition of Viesgo and additional generation capacity from Endesa in Spain, these operations are expected to be organized in a new tenth market unit. For information about the planned acquisition, see “Business — History and Development of the Company.” Until the end of 2008, the results of each of the new market units other than Energy Trading will be reported as part of the Corporate Center segment; Energy Trading’s results will be reported separately. The detailed discussion of each of the five existing market units that follows is based on their operations as of year-end 2007, and thus does not fully reflect intra-Group transfers of assets or operations to the new market units.

Energy Trading. E.ON Energy Trading AG (“EET”) is the lead company of the Energy Trading market unit. EET began operations in January 2008, and combines all our European trading activities, including those relating to electricity, gas, coal, oil and CO2 emission allowances. We have created EET with the goal of taking advantage of the opportunities created by the increasing integration of Europe’s power and gas markets and those present in global commodity markets.

Russia. E.ON Russia Power (“E.ON Russia”) is the lead company of the E.ON Russia market unit. E.ON Russia oversees our power business in Russia. In October 2007, we acquired a majority stake in the Russian power generation company OGK-4. E.ON now holds 76.1 percent of OGK-4’s capital stock. OGK-4 operates five conventional power stations at different locations with a total installed capacity of 8.6 gigawatts (“GW”). For additional details on the OGK-4 acquisition, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions.”

Italy. E.ON Italia S.p.A. (“E.ON Italia”) is the lead company of the Italy market unit. E.ON Italia manages our power and gas business in Italy, and is active in Italy’s wholesale power and gas markets and in natural gas sales. The expected acquisition of 80% of Endesa Italia, with approximately 7.200 MW of generating capacity in Italy will further enhance our generation portfolio. For information about the planned acquisition, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions”

Climate & Renewables. E.ON Climate & Renewables GmbH (“C&R”) is the lead company of the Climate & Renewables market unit. C&R is responsible for managing and expanding our global renewables business and for coordinating climate-protection projects. C&R has about 760 MW of generating capacity in Europe and approximately 250 MW in North America.

Valuation of Viesgo and Endesa assets On March 28, 2008, our Board of Management and Supervisory Board approved the acquisition from Acciona S.A. and Enel S.p.A. of a substantial package comprising the Enel subsidiary Enel Viesgo in Spain and power plants and other shareholdings of Endesa in Spain, France and Italy (such acquired Endesa operations, “Endesa Europe”). The valuation process of the assets, which was agreed on April 2, 2007 as the basis for

10 determining the final enterprise value of the asset package, has now been completed on schedule. The transaction value totals approximately €11.8 billion: €2 billion for Viesgo, €750 million for the additional Spanish generation assets, and €9.1 billion for Endesa Europe. On the basis of a consolidated net debt of approximately €2.9 billion, the equity purchased would amount to approximately €8.9 billion. The final net debt figure still has to be determined according to the provisions of the agreement of April 2, 2007. The completion of the transaction is likely to take place in the third quarter of 2008 once all permits are available.

Our Strategy Introduction We have five key beliefs about sustainable market success: • Vertical integration — Being present in all parts of the value chain in Generation/Gas Exploration & Production (Upstream), Supply & Trading (Midstream) and Sales (Downstream) will be the long-term winning business model for energy utilities. • Convergence of power & gas — Since convergence of the power and gas markets creates economies of scope, a strong presence in both markets will be a key competitive advantage and driver for value creation. • Strong market positions in a competitive market environment — In liberalized markets, scale is a key competitive edge. Competitive markets with strong integrated players with a long-term view provide the best reliability and security of supply. • Growth — Organic growth is a prerequisite for continuous value creation. Given rather moderate growth rates in mature markets, external growth is required to create above-average value. • Value from experience — A leading player can create more value from holding energy assets even in disconnected markets based on its experience and expertise of managing a broad range of assets in different energy markets.

Based on these beliefs, we pursue a clear strategic direction and business model.

An Integrated Power and Gas Business. We pursue an integrated power and gas business model that builds on leading positions in our respective markets. In doing so, we seek to develop positions throughout the energy value chain, including positions in infrastructure where they are seen as enhancing our access to markets and customers.

A Clear Geographical Focus. We seek to strengthen our leading positions and performance in our existing markets (Central Europe, Pan European Gas, U.K., Nordic and U.S. Midwest) as well as in our new markets in Russia, Spain and Italy. We also see further growth opportunities in neighboring markets in Southeast Europe and in Turkey. We also seek to grow our renewables and Joint Implementation/Clean Development Mechanism (“JI/CDM”) business in attractive global markets.

Clear Strategic Priorities. Our first priority is to strengthen and grow our position in our core European markets. In generation we seek to expand our generation capacity in Europe by 50 percent by 2010, as compared to May 2007. We intend to integrate and strengthen the assets we expect to acquire in Spain, Italy and France from Enel/Acciona. We also seek to significantly expand our renewables portfolio and our climate protection efforts in the JI/CDM framework. We have set ourselves the objective to reduce our specific CO2 emissions by 50 percent by 2030 compared to the levels of 1990. We aim to strengthen our gas supply position through our own production and potentially through liquefied natural gas (“LNG”).

Strict Investment Criteria. In following this model, we apply strict strategic and financial criteria to each potential investment, focusing on those which management believes exhibit the potential for material value creation.

11 Strategy Building on this model, our corporate strategy is to maximize the value of our portfolio of focused energy businesses through: • Creating value from the further increasing convergence of European energy markets (e.g., as the United Kingdom becomes a net importer of gas and can take advantage of greater pipeline capacity connecting it to continental Europe, we will be able to supply its retail gas business in the United Kingdom from our Pan European Gas supply business); • Creating value from vertical integration (i.e., establishing a presence in all parts of the value chains for both power and gas); • Creating value from the convergence of the electricity and gas value chains (e.g., offering retail electricity and gas customers energy from a single source), thus providing us with opportunities to realize economies of scale in servicing costs while increasing customer loyalty; • Enhancing operational performance through identifying and transferring best practice for common activities throughout our different market units (e.g., effective programs for enhancing our electricity generation, distribution and retailing businesses); • Improving our competitive position in our target markets, through both organic and external growth by pursuing selective investments which contribute to these objectives or provide stand alone value- creation opportunities, as described below; • Creating a common corporate culture under the One E.ON initiative, which seeks to enhance integration of all market units and their subsidiaries under the E.ON banner so as to help us realize our vision and strategic goals, while maintaining our commitment to corporate social responsibilities; and • Tapping value-enhancing growth potential in new markets such as Southeast Europe and Turkey.

The investment plan 2008-2010 focuses on growth in conventional power generation, renewables and gas. Investments will amount to approximately €50 billion within that period.

The financial strategy of E.ON consists of the following four elements: (1) E.ON’s target rating is a single A flat/A2 rating. This rating target was already determined in the context of the offer for the Endesa takeover and was confirmed in May 2007. In comparison to the previous rating target of a strong single A, the new rating target allows for a higher level of indebtedness and thus improves the efficiency of E.ON’s capital structure, whilst at the same time ensuring access to the capital markets. (2) For the future management of the capital structure, E.ON has introduced a new steering measure, the Debt Factor, which is the ratio between Economic Net Debt (a new key figure which supplements net financial position with provisions for pensions and provisions for waste management and asset retirement obligations (less prepayments)) and adjusted EBITDA. E.ON is targeting a Debt Factor of 3, which is derived from the target rating. (3) Going forward, E.ON intends to actively manage its capital structure. Based on the Debt Factor, the capital structure will be monitored continuously and optimized if necessary. If the Debt Factor is significantly above 3, strict discipline regarding investments will be required. In case of investments with strategic importance, financing measures with a countereffect or capital increases will be carried out. If it becomes apparent that the Debt Factor will sustainably fall below 3, E.ON will return more capital to its shareholders, for example by paying out higher dividends or buying back stock. However, priority will be given to value- creating investments. (4) The target for the dividend payout ratio and thus for regular dividends continues to be a range between 50 and 60 percent of adjusted net income.

12 E.ON has been conducting a share buyback program with a volume of approximately €7 billion. The share buyback program is planned to be completed by the end of 2008, by which time we will also be able to achieve the targeted Debt Factor. As of December 31, 2007, we had repurchased 27,974,944 of our shares under this program. In December 2007, we cancelled 25,000,000 shares, thereby reducing E.ON’s capital stock.

Apart from the overall strategy, we have set a number of specific objectives for our market units in implementing our corporate strategy within each of our target markets, namely: Central Europe — Fortifying strong market position and developing new growth potential through: • Preparing for generation reinvestments. • Broadening scope of power generation. • Hedging retail positions in Eastern Europe with generation assets. • Realizing regional and power/gas downstream synergies. • Integrating and strengthening assets acquired under our agreement with Enel/Acciona in France and Poland. • Participating in privatization processes in Southeast Europe providing new growth opportunities.

Pan European Gas — Strengthening and diversifying E.ON Ruhrgas’ current position through: • Expanding own gas production to at least 10 billion m3/year. • Examining entry possibilities into the LNG business. • Strengthening cooperation and partnership with producers. • Further expansion of our pan-European gas supplier role. • Investing in selected infrastructure projects to secure European gas supply: import infrastructure, interconnectors, storage investments.

U.K. — Strengthening our U.K. businesses through:

• Investing in more diverse and less CO2-intensive generation, including renewables. • Continued cost improvements in distribution and retail. • Investing in flexible gas storage assets and gas supply infrastructure as the U.K. shifts to a net-importer gas position.

Nordic — Strengthening our position through: • Growth through opportunities for consolidation in the fragmented Nordic market. • Further developing a diversified generation portfolio. • Identifying acquisition opportunities providing synergies in distribution, retail and heating in Sweden, Denmark and Finland.

U.S. Midwest — Focusing on optimizing E.ON U.S.’s current operations through: • Maintaining a sustainable competitive position through a stable regulatory environment in Kentucky and strong local market coverage.

13 • Continuing performance improvement of existing business. • Making focused capital investments in generation. • Growth in the long-term through consolidation opportunities in a fragmented market.

14 SUMMARY CONSOLIDATED FINANCIAL DATA Through the fiscal year ending December 31, 2006, we prepared our consolidated financial statements in accordance with U.S. GAAP, but have adopted IFRS as our primary set of accounting principles as of January 1, 2007. We have restated our consolidated financial statements for the year ended and as at December 31, 2006, in accordance with IFRS for comparative purposes. The summary consolidated financial data presented below as of and for each of the years in the two-year period ended December 31, 2007 has been excerpted from or is derived from, and should be read in conjunction with, our consolidated financial statements and related notes, prepared in accordance with IFRS, as of and for each of the years in the two-year period ended December 31, 2007, included herein. Year Ended December 31, IFRS IFRS 2007 2006 (in millions, except share amounts) Statement of Income Data: Sales including electricity and energy taxes ...... € 70,761 € 67,653 Sales excluding electricity and energy taxes(1) ...... 68,731 64,091 Income/(Loss) from continuing operations before income taxes ...... 9,683 5,347 Income/(Loss) from continuing operations after income taxes(2) ...... 7,394 5,307 Income/(Loss) from discontinued operations(3) ...... 330 775 Net income ...... 7,724 6,082 Attributable to shareholders of E.ON AG ...... 7,204 5,586 Attributable to minority interests ...... 520 496 Basic earnings/(Loss) per share from continuing operations ...... 10.55 7.31 Basic earnings (Loss) per share from discontinued operations, net(3) ...... 0.51 1.16 Basic earnings per share from net income ...... 11.06 8.47 Balance Sheet Data: Total assets ...... € 137,294 € 127,575 Liquid Funds ...... 7,075 6,189 Financial liabilities (non-current and current) ...... 21,464 13,472 Non-current financial liabilities ...... 15,915 10,029 Equity attributable to shareholders of E.ON AG ...... 49,374 48,712 Number of authorized shares ...... 667,000,000 692,000,000 Other Financial Data: Adjusted EBIT(4) ...... 9,208 8,356

(1) Laws in Germany and other European countries in which E.ON operates require the seller of electricity to collect electricity taxes and remit such amounts to tax authorities. Similar laws also require the seller of natural gas to collect and remit natural gas taxes to tax authorities. (2) Before minority interest of €520 million for 2007, as compared with €496 million for 2006. (3) For more details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for each period and Note 4 of the Notes to Consolidated Financial Statements. (4) Adjusted EBIT is the measure pursuant to which we have evaluated the performance of our segments and allocated resources to them. Adjusted EBIT is derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment basis) before income taxes and minority interests, excluding interest income, and adjusted for items that management believes are non- recurring items. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and other non-operating earnings of a non-recurring nature. In addition, interest income is adjusted using economic criteria. In particular, the interest portion of additions to provisions for pensions and nuclear waste management is allocated to adjusted interest income. On a consolidated Group basis adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable IFRS measure, net income. Adjusted EBIT should not be considered in isolation as a measure of our profitability and should be considered in addition to, rather than as a substitute for, net income. In particular, there are material limitations associated with the use of adjusted EBIT as compared with such IFRS measure, including the limitations inherent in our determination of each of the adjustments noted above. We seek to compensate for these limitations by providing a detailed reconciliation of adjusted EBIT to net income, the most directly comparable IFRS measure, in “Operating and Financial Review and Prospects” on page 52. As a result of these limitations and other factors, adjusted EBIT as used by us may differ from, and not be comparable to, similarly titled measures used by other companies.

15 The summary consolidated financial data presented below as of and for each of the years in the two-year period ended December 31, 2006 has been excerpted from or is derived from and should be read in conjunction with, our consolidated financial statements and related notes, prepared in accordance with U.S. GAAP, as of and for each of the years in the two-year period ended December 31, 2006, incorporated herein by reference.

Year Ended December 31, U.S. GAAP U.S. GAAP 2006 2005 (in millions, except share amounts) Statement of Income Data: Sales ...... € 67,759 € 56,141 Sales excluding electricity and petroleum taxes(1) ...... 64,197 51,616 Income/(Loss) from continuing operations before income taxes ...... 5,133 7,152 Income/(Loss) from continuing operations after income taxes and before minority interests(2) ...... 5,456 4,891 Income/(Loss) from continuing operations after income taxes ...... 4,930 4,355 Income/(Loss) from discontinued operations, net applicable income taxes(3) .... 127 3,059 Net income ...... 5,057 7,407 Basic earnings/(Loss) per share from continuing operations ...... 7.48 6.61 Basic earnings (Loss) per share from discontinued operations, net(3) ...... 0.19 4.64 Basic earnings per share from net income(4) ...... 7.67 11.24 Balance Sheet Data: Total assets ...... € 127,232 € 126,562 Non-current financial liabilities ...... 9,959 10,555 Shareholder’s equity(5) ...... 47,845 44,484 Number of authorized shares ...... 692,000,000 692,000,000 Other Financial Data: Adjusted EBIT(6) ...... 8,150 7,293

(1) Laws in Germany and other European countries in which E.ON operates require the seller of electricity to collect electricity taxes and remit such amounts to tax authorities. Similar laws also require the seller of natural gas to collect and remit natural gas taxes to tax authorities. (2) Before minority interest of €526 million for 2006 according to U.S. GAAP, and €536 million for 2005 according to U.S. GAAP. (3) For more details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for each period and Note 4 of the Notes to Consolidated Financial Statements. (4) Includes earnings per share from the first-time application of new U.S. GAAP standards of negative €0.01 in 2005. There was no such effect on 2006. (5) Under U.S. GAAP equal to stockholders’ equity, after minority interests. (6) Adjusted EBIT is the measure pursuant to which we have evaluated the performance of our segments and allocated resources to them. Adjusted EBIT is derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment basis) before income taxes and minority interests, excluding interest income, and adjusted for items that management believes are non- recurring items. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and other non-operating earnings of a non-recurring nature. In addition, interest income is adjusted using economic criteria. In particular, the interest portion of additions to provisions for pensions and nuclear waste management is allocated to adjusted interest income. On a consolidated Group basis adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable U.S. GAAP measure, net income. Adjusted EBIT should not be considered in isolation as a measure of our profitability and should be considered in addition to, rather than as a substitute for, net income. In particular, there are material limitations associated with the use of adjusted EBIT as compared with such U.S. GAAP measure, including the limitations inherent in our determination of each of the adjustments noted above. We seek to compensate for these limitations by providing a detailed reconciliation of adjusted EBIT to net income, the most directly comparable U.S. GAAP measure, in “Operating and Financial Review and Prospects” on page 65. As a result of these limitations and other factors, adjusted EBIT as used by us may differ from, and not be comparable to, similarly titled measures used by other companies.

16 THE OFFERING

The following summary contains basic information about the Notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the Notes, please refer to the section of this offering memorandum entitled “Description of the Notes”.

Issuer ...... E.ON International Finance B.V. (the “Issuer”).

Guarantor ...... E.ON AG (the “Guarantor”).

Securities offered ...... $2,000,000,000 aggregate principal amount of 5.80% senior notes due 2018 (the “2018 Notes”)

$1,000,000,000 aggregate principal amount of 6.65% senior notes due 2038 (the “2038 Notes” and, together with the 2018 Notes, the “Notes”). The Notes will be unconditionally and irrevocably guaranteed by the Guarantor. The Notes will mature on April 30, 2018 and April 30, 2038, respectively, and are redeemable prior to maturity as described in “Description of the Notes — Optional Redemption” and “Description of the Notes — Optional Tax Redemption”.

Issue price ...... 99.578% of the principal amount of the 2018 Notes and 99.572% of the principal amount of the 2038 Notes.

Ranking of the Notes ...... The Notes will be the direct, unconditional, unsecured and unsubordinated general obligations of the Issuer. The Notes will rank pari passu among themselves, without any preference of one over the other by reason of priority of date of issue or otherwise, and at least equally with all other unsecured and unsubordinated general obligations of the Issuer from time to time outstanding.

Ranking of the guarantees ...... Each Note will benefit from an unconditional and irrevocable guarantee by the Guarantor (each a “Guarantee” and collectively the “Guarantees”). The Guarantees will be the direct, unconditional, unsecured and unsubordinated general obligations of the Guarantor. The Guarantees will rank pari passu among themselves, without any preference of one over the other by reason of priority of date of issue or otherwise, and at least equally with all other unsecured and unsubordinated general obligations of the Guarantor from time to time outstanding.

Minimum denomination ...... The Notes will be issued in denominations of $1,000 and integral multiples of $1,000 in excess thereof.

Interest ...... The2018 Notes will bear interest at the rate per annum of 5.80% and the 2038 Notes will bear interest at the rate per annum of 6.65%, in each case from April 22, 2008. Interest on the Notes will be payable semiannually in arrears on October 30 and April 30 of each year, commencing on October 30, 2008 (or, if any such date is not a business day, on the next succeeding business day) until the principal

17 of the Notes is paid or duly made available for payment. Interest on the Notes will be calculated on the basis of a 360-day year consisting of twelve 30-day months. Interest on the Notes will be paid to the persons in whose names the Notes (or one or more predecessor Notes) are registered on the October 15 and April 15, as the case may be, immediately preceding the applicable interest payment date, whether or not such date is a business day.

Business day ...... Theterm“businessday”meansanydayotherthana dayonwhich commercial banks or foreign exchange markets are permitted or required to be closed in New York City, London, Frankfurt am Main or Amsterdam. If the date of payment of interest on or principal of the Notes or the date fixed for redemption of any Note is not a business day, then payment of interest or principal need not be made on such date, but may be made on the next succeeding business day with the same force and effect as if made on the date of payment of interest on or principal of the Notes or the date fixed for redemption, and no interest shall accrue for the period after such date.

Additional amounts ...... TheIssuer (and/or the Guarantor) will make all payments in respect of the Notes without withholding or deduction for or on account of any present or future taxes or duties of whatever nature imposed or levied by way of withholding or deduction at source by or on behalf of any jurisdiction in which the Issuer or Guarantor is incorporated, organized, or otherwise tax resident or any political subdivision or any authority thereof or therein having power to tax (the “Relevant Taxing Jurisdiction”) unless such withholding or deduction is required by law. In such event, the Issuer or, as the case may be, the Guarantor will pay to the Holders such additional amounts (the “Additional Amounts”) as shall be necessary in order that the net amounts received by the holders of the Notes (the “Holders” and each a “Holder”), after such withholding or deduction, shall equal the respective amounts of principal and interest which would otherwise have been receivable in the absence of such withholding or deduction; except that no such Additional Amounts shall be payable on account of any taxes or duties in the circumstances described below under “Description of the Notes — Additional Amounts.”

References to principal or interest in respect of the Notes include any Additional Amounts, which may be payable as set forth in the Fiscal and Paying Agency Agreement.

Optional redemption ...... TheNotes may be redeemed at any time, at the Issuer’s option, as a whole or in part, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to the greater of: • 100% of the aggregate principal amount of the Notes to be redeemed; and • as determined by the Independent Investment Banker (as defined below), the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed

18 (not including any portion of such payments of interest accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate described herein plus 35 basis points,

plus, in each case described above, accrued and unpaid interest on the principal amount being redeemed to (but excluding) the redemption date.

Optional tax redemption ...... The Notes may be redeemed at any time, at the Issuer’s (or, if applicable, the Guarantor’s) option, as a whole, but not in part, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the principal amount of the Notes then outstanding plus accrued and unpaid interest on the principal amount being redeemed (and all Additional Amounts, if any) to (but excluding) the redemption date, if (i) as a result of any change in, or amendment to, the laws, treaties, regulations or rulings of a Relevant Taxing Jurisdiction or in the interpretation, application or administration of any such laws, treaties, regulations or rulings (including a holding, judgment or order by a court of competent jurisdiction) which becomes effective on or after the issue date (any such change or amendment, a “Change in Tax Law”), the Issuer or (if a payment were then due under the guarantee, the Guarantor) would be required to pay Additional Amounts and (ii) such obligation cannot be avoided by the Issuer (or the Guarantor) taking reasonable measures available to it.

No notice of redemption may be given earlier than 90 days prior to the earliest date on which the Issuer (or the Guarantor) would be obligated to pay the additional amounts if a payment in respect of the Notes were then due.

Holders’ option to repayment upon a Change in Control ...... As is described in detail below under “Description of the Notes — Holders’ Option to Repayment upon a Change in Control,” in the event that (i) a Change of Control of the Guarantor occurs, and, within the Change of Control Period (as defined below), a Ratings Downgrade (as defined below) in respect of that Change of Control occurs or is announced, any Holder may, by submitting a redemption notice, demand from the Issuer repayment as of the Effective Date (as defined below) of any or all of its Notes which have not otherwise been declared due for early redemption, at their principal amount plus interest accrued until (but excluding) the effective date (and all Additional Amounts, if any).

Negative Pledge ...... Solong as any of the Notes remains outstanding neither the Issuer nor the Guarantor will create or permit to subsist any mortgage, charge, pledge, lien or other encumbrance upon any or all of its present or future assets to secure for the benefit of the holders of any present or future Bond Issue the repayment of such present or future Bond Issue without at the same time, or prior thereto, securing such Notes or the

19 Guarantees, as the case may be, equally and rateably therewith. “Bond Issue” means any indebtedness of the Issuer or the Guarantor which is, in the form of, or is represented by, any bond, security, certificate or other instrument which is or is capable of being listed, quoted or traded on any stock exchange or in any securities market (including any over-the-counter market) and any guarantee or other indemnity in respect of such indebtedness.

Use of proceeds ...... The Issuer intends to on-lend substantially all of the net proceeds from the sale of the Notes to the Guarantor and/or entities owned directly or indirectly by the Guarantor for general corporate purposes, which may include financing of recently announced acquisitions.

Book-entry form ...... The Notes will initially be issued to investors in book-entry form only. Fully-registered Global Notes (as defined below) representing the total aggregate principal amount of the Notes will be issued and registered in the name of a nominee for DTC, the securities depositary for the Notes, for credit to accounts of direct or indirect participants in DTC, including Euroclear and Clearstream. Unless and until Notes in definitive certificated form are issued, the only Holder will be Cede & Co., as nominee of DTC, or the nominee of a successor depositary. Except as described in this offering memorandum, a beneficial owner of any interest in a Global Note will not be entitled to receive physical delivery of definitive Notes. Accordingly, each beneficial owner of any interest in a global Note must rely on the procedures of DTC, Euroclear, Clearstream, or their participants, as applicable, to exercise any rights under the Notes.

Governing law ...... The Notes, the Guarantees and the fiscal and paying agency agreement related thereto, will be governed by, and construed in accordance with, the laws of the State of New York.

Selling restrictions ...... TheNotes have not been registered under the U.S. Securities Act of 1933 (the “Securities Act”) or any state securities law. Unless they are registered, the Notes may not be offered or sold except pursuant to an exemption from or in a transaction not subject to the registration requirements of the Securities Act and applicable state securities laws and may only be transferred in accordance with the restrictions set out in “Transfer Restrictions.” See, also, “Plan of Distribution”.

Additional Notes ...... TheIssuer may, from time to time, without notice to or the consent of the Holders, create and issue Additional Notes, maturing on the same maturity date and having the same terms and conditions as the previously outstanding Notes of that series (the 2018 Notes or the 2038 Notes) in all respects (or in all respects except for the issue date and the amount and the date of the first payment of interest thereon) in accordance with applicable laws and regulations and pursuant to the Fiscal and Paying Agency Agreement (including with respect to the Guarantor and the Guarantees). Additional Notes issued in this manner shall be consolidated with and form a single series with previously outstanding Notes.

20 Listing and trading ...... TheNotes will not be listed on any securities exchange.

Ratings ...... A2/A (Moody’s/Standard & Poor’s).

Fiscal agent, principal paying agent, transfer agent and registrar ...... Thefiscal agent, principal paying agent, transfer agent and registrar is HSBC Bank USA, N.A.

CUSIPs ...... 2018 Notes: 268789 AA2 (Rule 144A). 2018 Notes: N 3033QAT9 (Regulation S). 2038 Notes: 268789 AB0 (Rule 144A). 2038 Notes: N 3033QAU6 (Regulation S).

ISINs ...... 2018 Notes: US 268789 AA24 (Rule 144A). 2018 Notes: USN 3033QAT96 (Regulation S). 2038 Notes: US 268789 AB07 (Rule 144A). 2038 Notes: USN3033QAU69 (Regulation S).

21 RISK FACTORS

Prospective investors in the Notes should carefully consider the following information in conjunction with the other information contained or incorporated by reference into this document.

External Risks Our core energy operations face strong competition, which could depress margins. Since 1998, liberalization of the electricity markets in the EU has greatly altered competition in the German electricity market, which was formerly characterized by numerous strong competitors. Following liberalization, significant consolidation has taken place in the German market, resulting in four major interregional utilities: E.ON, RWE AG (“RWE”), Vattenfall Europe AG (“Vattenfall Europe”) and EnBW Energie Baden-Württemberg AG (“EnBW”). In addition, the market for electricity trading has become more liquid and competitive, with a total trading volume of approximately 1,273 terrawatt hours (“TWh”) on the European Energy Exchange (EEX) spot and futures market in 2007, and additional volumes being traded on the over-the-counter market. Liberalization of the German electricity market also caused prices to decrease beginning in 1998, although prices have increased since 2001. Retail prices now exceed 1998 levels, and prices for sales to distributors and industrial customers have also increased. These price increases have generally been driven by increases in the price of fuel, as well as regulatory and other costs, with the result that competitive pressure on margins continues to exist. Higher wholesale prices are also expected to lead to the construction of new generation facilities, thereby increasing competition and the pressure on margins when such facilities come into operation. Although we intend to compete vigorously in the changed German electricity market, we cannot be certain that we will be able to develop our business as successfully as our competitors. For information about regulatory changes that are affecting the German electricity market, see the discussion on changes in laws and regulations below.

Outside Germany, the electricity markets in which we operate are also subject to strong competition. We have significant U.K. and Swedish operations in electricity generation, distribution and supply, on both the wholesale and retail levels. Increased competition from new market entrants and existing market participants could adversely affect our U.K. or Swedish market share in both the retail and wholesale sectors. We cannot guarantee we will be able to compete successfully in the United Kingdom, the Nordic countries, Eastern Europe, Italy, Russia or other electricity markets where we are already present or in new electricity markets we may enter. E.ON Ruhrgas also faces risks associated with increased competition in the gas sector.

Changes in applicable laws and regulations as well as the introduction of new laws and regulations could materially and adversely affect our financial condition and results of operations. In each of our operations, we must comply with a number of laws and government regulations. For more information on laws and regulations affecting our core energy business, including additional details on each of the regulatory regimes discussed below, see “Business — Regulatory Environment.” From time to time, regulatory changes or new laws, including applicable tax laws, and regulations may be introduced, which may negatively affect our businesses, financial condition and results of operations.

For example, the EU adopted new electricity and gas directives in 2003 which required changes to the electricity and gas industries of some EU member states, including Germany. One of the requirements was that an independent regulatory authority be established in each member state to oversee access to the electricity and gas networks. According to the directives, this regulatory body should have the authority to set or approve network charges or, alternatively, the methodologies used for calculating them, as well as the power to control compliance with the charges or methodologies once they are set. In Germany, the relevant legislation came into force in July 2005 and the German legislature authorized the Federal Network Agency (Bundesnetzagentur,or the “BNetzA,” previously called the Regulatory Authority of Telecommunications and Post) to act as the required independent regulatory body. The new German energy legislation and the appointment of the BNetzA to oversee access to German electricity and gas networks has changed the previous system of negotiated third-party

22 network access in the electricity and gas industries in Germany. Although the new legislation has already come into force, we cannot yet predict all of the consequences of the new system, as the exact interpretation of some of the new regulatory rules is still pending. However, the BNetzA has interpreted some of the new regulatory rules and ordinances to reach conclusions that are different than those reached by, and in some cases less favorable to, us as well as other German utilities. For example, the new German energy law contains two phases of regulation, and in the initial phase, the BNetzA and the state level regulators had to approve those network charges that were calculated by the network operators using a cost-based rate-of-return model unless certain exemptions apply. Thus the BNetzA and the state level regulators effectively set the network charges for network operators ex-ante. In 2006, the BNetzA reduced the allowed network charges submitted for its approval by the E.ON Energie electricity and gas distribution network operators, as described in “Regulatory Environment — Germany: Electricity — Electricity Network Charges.” In doing so, the BNetzA used a different interpretation of the new ordinance than that used by the E.ON Energie network operators (and the majority of German network operators) to calculate their network charges. In 2006, the BNetzA also announced that the reduced charges would be applicable from earlier dates than those which we believe should apply, so that German network operators (including E.ON Energie’s) would need to reduce network charges in an amount equal to the difference between the calculated network charges as submitted to the BNetzA and the allowed network charges approved by the BNetzA for the time period in dispute. While some of the BNetzA’s interpretations have now been formalized through a revision of the network charges ordinance, others, as well as the question of applicable dates, will have to be decided by the German courts, and no assurance can be given as to the outcome of those proceedings.

By the end of June and September 2007, respectively, our electricity and gas network operators entered into the second round of cost-based network tariff regulation by submitting applications to the regulatory authority. Approval of these applications was expected by January 1, 2008 in respect of electricity and April 1, 2008 in respect of gas, but approval has been delayed. For further information see “Regulatory Environment — Germany: Electricity” and “— Germany: Gas.” No assurance can be given that new tariffs will not have a negative effect on our results of operations or it may, in individual cases, be necessary to record impairment charges on our network operators.

The current cost-based rate-of-return model for network tariffs in Germany will be replaced by an incentive regulation system, which was established by a new ordinance that came into force on November 6, 2007. The approved revenues for network operators set under the incentive regulation system will initially be based upon the costs recognized by the regulatory authority in the second round of cost-based network tariff regulation and will start on January 1, 2009. It is expected that approved revenues will be reset at the beginning of 2014 in respect of electricity and at the beginning of 2013 in respect of gas. By January 1, 2019, network operators will be expected to reduce their costs to the level of the most efficient operator along individual cost reduction paths, reflected by reduced approved revenues. Efficiency will be measured by means of a complicated benchmarking system. Moreover, a general efficiency factor of 1.25 percent per year in the first five-year period (a four-year period for gas) and 1.5 percent in the second five-year-period, will be added. As an incentive to achieve improved efficiency under the incentive regulation system, it is expected that if operators reduce their costs at a rate greater than the required rate, operators will be able to retain the additional amounts saved by such cost reductions. We plan to compensate for the negative impact of revenue caps by further reducing operating costs through various efficiency-raising programs.

In the gas market, the gas industry developed an industry-wide gas network access model in order to comply with the new legislation, and the agreed model, with two variants for gas transportation, was finalized in mid-2006. Shortly thereafter, one of the variants for gas transportation was challenged in legal proceedings and in November 2006 the BNetzA issued an industry-wide decision requiring a so-called two-contract-model for all gas transportation and distribution companies, forcing them to offer customers only two contracts, one for the entry and one for the exit-point in their market area, thus requiring related changes in all transportation and sales contracts and in the gas network operators’ cooperation agreement, which have since come into effect.

In addition, in November 2006 a new network connection ordinance came into force in Germany which increases potential liability for network operators for damages caused by energy supply disturbances.

23 Sweden has enacted new legislation concerning electricity distribution which requires customer compensation for power blackouts lasting more than 12 hours. As discussed below, in early 2007 a severe storm resulted in a power outage in Sweden that affected approximately 170,000 E.ON Sverige customers, and many of these customers are entitled to compensation under the new law.

In 2005, the EU adopted a directive requiring member states to establish a greenhouse gas emissions allowance trading scheme, under which emissions are capped and permits to emit a specified amount of carbon dioxide (“CO2 emission certificates”) are allocated to affected power stations and other industrial installations. All EU member states have already passed the required legislation and allocated the necessary CO2 emission certificates for the first phase of the scheme, mostly free of charge. The trial phase (2005-2007) of the trading scheme has ended and market has moved into the Kyoto phase which will run from 2008-2012. In this current phase, the European Commission has reduced the total amount of emissions certificates given compared to 2005-07. By using the actual emissions from 2005 as a reference point, the European Commission has decided to allocate 2,080 million CO2 emission certificates annually, which is more than 200 million certificates/year fewer than in the initial phase of the trading scheme. Member states have developed national allocation plans for the

Kyoto phase that will result in a reduced number of CO2 emission certificates being issued, which could further impact our operations. The German national allocation plan has now been accepted by the EC (after rejection in November 2006) and passed as the Allocation Act 2008-20012 (Zuteilungsgesetz 2008-2012, or “ZUG 2012”) by both houses of the German Parliament in the summer of 2007. The total allocation amount in Germany has been 2 reduced by 50 million CO emission certificates/year to 453 million CO2 emission certificates/year, which means a significant shortage, especially for the energy sector, as the reduction is taken almost completely from the budget for the energy sector. Out of the total allocation amount of 453 million CO2 emission certificates/year, 40 million CO2 emission certificates/year will be released by a government agency according to market prices from 2008 on; from 2010 on it will be auctioned. These 40 million CO2 emissions certificates/year are taken from the budget of the energy sector as well. This reduction in the volume of authorized emissions available to the energy sector has meant that E.ON’s free allocation of certificates has been reduced, and E.ON has therefore to purchase a potion of its required certificates in Germany on the market.

The European Commission published as part of a package of measures on climate and energy policy the proposal of a new directive for the EU Emissions Trading Scheme for the period after 2012 on January 23, 2008. For more information, see “Business — Environmental Matters — Europe” and “Business — Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas) — New European Energy Policy.”

In the United States, possible federal or state energy legislation or industry initiatives could include mandatory or voluntary targets for the production and use of renewable energy and limits or charges on the emission of greenhouse gases, though we are unable to predict if any such legislation or initiatives will be established. If established, such legislation and/or initiatives could have a material negative effect on our financial condition and results of operations including increased capital expenditures or operating costs, reduced customer demand or changed prices and availabilities of key input or output goods, services or commodities.

In addition, in the summer of 2005 the Competition Directorate-General of the European Commission launched a sector inquiry concerning the electricity and gas markets in the EU. This investigation is based on Article 17 of Regulation 1/2003 and assesses the competition conditions in European gas and electricity markets. It cannot be excluded that this inquiry could result in individual antitrust proceedings against us and/or legislative initiatives (at the EU or national level) in the electricity sector that would seek to increase the current level of competition in the EU energy market. In its final report issued on January 10, 2007, the European Commission has identified the following barriers to a fully functioning internal energy market: market concentration, vertical foreclosure, lack of market integration and transparency and price formation.

The findings in the final report of the sector inquiry in January 2007 led the European Commission to focus its activities on the concerns identified in the report, such as: achieving adequate unbundling of network and supply activities, removing the regulatory gaps, in particular for cross-border issues, addressing market

24 concentration and barriers to entry, as well as increasing transparency in market operations. For more information on legal proposals of the European Commission (including ownership unbundling) see also “Business — Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas) — New European Energy Policy.”

In July 2007, the European Commission decided to open formal antitrust proceedings against us, E.ON Ruhrgas, E.ON Gastransport, MEGAL and Gaz de France for an alleged infringement of Article 81 of the EC Treaty involving alleged anti-competitive behavior in connection with the MEGAL pipeline operated jointly by E.ON Ruhrgas with Gaz de France. No assurance can be given as to the outcome of these proceedings.

The European Commission also carried out investigations at the premises of several energy companies in Europe, including E.ON AG and some of its affiliates, in May and December 2006, followed by requests for information regarding different regulatory and energy market-related issues relating to E.ON Energie and E.ON Ruhrgas. The European Commission is currently analyzing the respective data and has recently issued additional requests for information. The European Commission investigated the circumstances under which a seal installed by investigators at one of the E.ON Energie’s facilities failed and, in January 2008, fined E.ON Energie €38 million for allegedly breaching the seal. E.ON Energie is of the opinion that the allegations are unjustified, and therefore intends to challenge the fine in court. However, no assurance can be given that such challenge will be successful. To settle pending investigations in the electricity sector, E.ON is prepared to divest its 380 kilovolt and 220 kilovolt extra-high-voltage transmission system and 4,800 MW of generating capacity in Germany. After conducting a market test, the European Commission will make a legally binding decision and not continue any antitrust proceedings against E.ON’s electricity operations in this respect.

Regulatory and legal actions can also affect the prices we may charge customers. For example: • In March 2008, the BNetzA launched an investigative procedure against the German power transmission system operators, including E.ON subsidiary E.ON Netz GmbH, Bayreuth (“E.ON Netz”). E.ON Netz is charged by market participants (Lichtblick/bne) to have purchased excessive amounts of balancing power over the past two years and to have overcharged grid customers accordingly. • In December 2007, an amendment of the German law against restraints on competition (Gesetz gegen Wettbewerbsbeschränkungen, or “GWB”) entered into force. • As noted above, in Germany the BNetzA has reduced the allowed network charges which were submitted for approval by our electricity and gas distribution network operators in 2006. The approved network charges were based on a different interpretation of Germany’s new energy law by the BNetzA than that used by our network operators (and the majority of German network operators) to calculate their network charges. • In Germany, the state antitrust authorities as well as the German Federal Cartel Office (Bundeskartellamt, or “FCO”) regularly examine gas tariffs of utilities for household customers to determine whether these prices constitute market abuse. Our companies have always delivered any information requested in connection with such inquiries, and no formal proceedings are currently pending. • The FCO has opened proceedings against E.ON Energie and RWE with respect to an alleged abuse of a

dominant position in the energy market by including the costs for CO2 emission certificates obtained at no charge in the calculation of their energy prices for industrial customers. In December 2006, RWE received a statement of objections but has since settled the proceedings with the FCO by entering into binding agreements to auction generation capacity to industrial customers in the years 2008 to 2011 for delivery in the years 2009 to 2012. E.ON Energie has also conducted negotiations with the FCO and is finalizing a settlement with the FCO on the basis of the auction of generation capacity, combined with the option to sell off an interest in a generation plant. At present, the parties involved have been given the opportunity by the FCO to comment on the settlement findings in the first quarter of 2008. We cannot provide any assurance that the result of these negotiations will not harm our business or results of operations.

25 • Electricity and gas prices and sales practices throughout the German energy sector have also been subject to certain legal proceedings. Currently, fifty-four customers of E.ON Hanse AG (“E.ON Hanse”) have brought a claim asserting that recent price increases violate certain provisions of the German Civil Code (Bürgerliches Gesetzbuch). In order to support its case that the price increases were reasonable within the meaning of applicable law, E.ON Hanse has disclosed the basis on which it calculates prices for household customers to the District Court (Landgericht) in Hamburg. The court is currently examining E.ON Hanse’s submissions in this respect. In an unrelated proceeding, E.ON Westfalen Weser AG (“E.ON Westfalen Weser”) has brought suit against a group of customers that have refused to pay the increased prices. No assurances can be given as to the outcome of either of these proceedings. In November 2007, the Superior Court of Schleswig Holstein ruled against E.ON Hanse, resulting in a decision for 30,000 customers with respect to price increases of electricity used for residential heating. The Court found that terms and conditions for the price increases were not sufficiently transparent and were too vague, but has not yet issued a ruling with any binding effect on our business practices. However, no assurance can be given as to the outcome of these or similar proceedings. • With effect from April 2005, regulators in the United Kingdom renewed a price control framework for electricity distribution customers that is in effect through the five-year period ending March 2010. • In the United States, the rates for E.ON U.S.’s retail electric and gas customers in Kentucky, its principal area of operations, are set by state regulators and remain in effect until such time as an adjustment is sought and approved. E.ON U.S.’s affected utilities applied for and received increases in regulated tariffs effective as of July 1, 2004.

For additional information on these developments, see “Business — Regulatory Environment.” For all of our operations, adverse changes in price controls, rate structures or the level of competition could have an adverse effect on our financial condition and results of operations.

Rising fuel prices could materially and adversely affect our results of operations and financial condition. A significant portion of the expenses of our regional market units are made up of fuel costs, which are heavily influenced by prices in the world market for oil, natural gas, fuel oil and coal. Similarly, the majority of E.ON Ruhrgas’ expenses are for purchases of natural gas under long-term take-or-pay contracts that link the gas prices to that of fuel oil and other competing fuels. The prices for such commodities have historically been volatile and there is no guarantee that prices will remain within projected levels. The price of oil in particular rose in 2006 and reached a new all-time high of over 110 U.S. dollars per barrel in early 2008. Our electricity operations do maintain some flexibility to shift power production among different types of fuel, and we are also partially hedged against rising fuel prices. However, increases in fuel costs could have an adverse effect on our operating results or financial condition if we are not able (or not permitted by regulatory authorities) to shift production to lower-cost fuel or to adjust our rates to offset such increases in fuel prices on a timely or complete basis.

For more information about E.ON Ruhrgas’ take-or-pay contracts, see “— Operational Risks — E.ON Ruhrgas’ long-term gas supply contracts expose it to volume and price risks, and it has had to terminate certain of its long-term sales contracts due to a negative decision by the FCO” below. We could also incur losses if our hedging strategies are not effective. For more information about our hedging policies and the instruments used, see “— Financial Risks” below; also see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about Market Risk.” E.ON Ruhrgas is also currently involved in two international arbitration proceedings against producers with respect to price adjustments in the period between 1998 and 2005.

In addition, as our fuel costs increase, we seek, to the extent possible, to pass along such increased costs to our customers. Such increased costs alone or together with a worsening of the overall economic situation, including the retail credit environment, in any of our markets, may make it more difficult for our customers to make required payments to us, which typically increases our bad debt expense and damages our financial condition and results of operations.

26 Recent events have heightened concerns about the reliability of Russian gas supplies, on which E.ON Ruhrgas depends. E.ON Ruhrgas currently obtains nearly thirty percent of its total gas supply from Russia pursuant to long- term supply contracts it has entered into with OOO Gazexport (now Gazprom export), a subsidiary of OAO Gazprom (“Gazprom”) (in which E.ON Ruhrgas holds a 3.5 percent direct interest and an additional stake of 2.9 percent). Recent events in some countries of the former Soviet Union have heightened concerns in parts of Western Europe about the reliability of Russian gas supplies. Historically cold temperatures in Russia in the winter of 2005-2006 increased gas consumption, leading some Western European countries to report declines in pressure in gas pipelines and shortfalls in the volume of gas they received from Russia. In addition, a dispute between Russia and Ukraine over the imposition of significant price increases on Russian gas delivered to Ukraine at the beginning of 2006 led to interruptions in the supply of Russian gas to Ukraine (and through Ukraine to other countries) in the early days of January 2006. In late 2006, a similar price dispute between Russia and Belarus led to Belarus blocking the transit of gas and oil through that country, while in early 2007 Poland attempted to raise transit fees charged to Gazprom for Russian gas and oil being shipped to Western Europe through Poland, leading to speculation that Gazprom might retaliate by halting gas and oil shipments. Economic or political instability or other disruptive events in any “transit country” through which Russian gas must pass before it reaches its final destination in Western Europe can have a material adverse effect on the supply of such gas, and all such events are completely outside the control of E.ON Ruhrgas. Although E.ON Ruhrgas has to date not experienced any interruptions in supply or declines in delivered gas volumes below those which are guaranteed to it under its long-term contracts, no assurance can be given that such interruptions or declines will not occur. The terms of E.ON Ruhrgas’ long-term supply contracts for Russian gas require that the contracted volumes of gas be delivered to E.ON Ruhrgas at the German border, with the risk of ownership only passing to E.ON Ruhrgas at that point, but provide that such obligations can be suspended due to events of force majeure. Any prolonged interruption or decline in the amount of gas delivered to E.ON Ruhrgas under its contracts with Gazprom, its subsidiaries or any other party would result in E.ON Ruhrgas having to use its storage reserves to make up the shortfall with respect to amounts it is contracted to deliver to customers, and could have a material adverse effect on E.ON’s results of operations and financial condition.

Our revenues and results of operations fluctuate by season and according to the weather, and we expect these fluctuations to continue. The demand for electric power and natural gas is seasonal, with our operations generally experiencing higher demand during the cold weather months of October through March and lower demand during the warm weather months of April through September. The exception to this is our U.S. power business, where hot weather results in an increased demand for electricity to run air conditioning units. As a result of these seasonal patterns, our revenues and results of operations are higher in the first and fourth quarters and lower in the second and third quarters, with the U.S. power business having its highest revenues in the third quarter and secondary peaks in the first and fourth quarters. Revenues and results of operations for all of our energy operations can be negatively affected by periods of unseasonably warm weather during the autumn and winter months, as occurred at certain of our market units in both 2006 and 2007. Our Nordic operations could be negatively affected by a lack of precipitation (which would lead to a decline in hydroelectric generation, as occurred in 2006) and our European energy operations could also be negatively affected by a summer with higher than average temperatures to the extent our plants were required to reduce or shut down operations due to a lack of water needed for cooling the plants. We expect seasonal and weather-related fluctuations in revenues and results of operations to continue. Particularly severe weather can also lead to power outages, as discussed in more detail below.

Operational Risks Our core energy businesses operate technologically complex production facilities and transmission systems. Operational failures or extended production downtimes could negatively impact our financial condition and results of operations. Our businesses are also subject to risks in the ordinary course of business such as the loss of

27 personnel or customers, and losses due to bad debts. We believe we have appropriate risk control measures in effect to counteract and address these types of risks. The following are additional operational risks we face:

E.ON Ruhrgas’ long-term gas supply contracts expose it to volume and price risks, and it has had to terminate certain of its long-term sales contracts due to a negative decision by the FCO. As is typical in the gas industry, E.ON Ruhrgas enters into long-term gas supply contracts with natural gas producers to secure the supply of almost all the gas E.ON Ruhrgas purchases for resale. These contracts, which generally have terms of around 20 to 25 years, require E.ON Ruhrgas to purchase minimum amounts of natural gas over the period of the contract or to pay for such amounts even if E.ON Ruhrgas does not take the gas, a standard industry practice known as “take or pay.” The minimum amounts are generally about 80 percent of the firmly contracted quantities. Historically, E.ON Ruhrgas has also entered into long-term gas sales contracts with its customers, although these contracts are shorter than gas supply contracts with natural gas producers. Aspects of E.ON Ruhrgas’ long-term gas sales contracts have been challenged by the FCO, as described in more detail below. In addition, the majority of these gas sales contracts do not include fixed take-or-pay provisions. Since E.ON Ruhrgas’ gas supply contracts have significantly longer terms than its gas sales contracts, and commit E.ON Ruhrgas to paying for a minimum amount of gas over a long period, E.ON Ruhrgas is exposed to the risk that it will have an excess supply of natural gas in the long term should it have fewer committed purchasers for its gas in the future and be unable to otherwise sell its gas on favorable terms. Such a shortfall could result if a significant number of E.ON Ruhrgas’ customers (or their end customers) shifted from natural gas to other forms of energy or if E.ON Ruhrgas’ customers began to acquire increased volumes of gas from other sources. The ministerial approval we obtained for the acquisition of Ruhrgas required E.ON Ruhrgas to divest its stakes in two gas distributors, as well as granting these distributors the right to terminate their gas sales contracts with E.ON Ruhrgas. The ministerial approval also gave most of E.ON Ruhrgas’ distribution customers the right to reduce the amounts of natural gas purchased from E.ON Ruhrgas. However, the majority of E.ON Ruhrgas’ customers have decided not to exercise these options.

In January 2006, the FCO issued a decision prohibiting E.ON Ruhrgas from enforcing its existing long-term gas sales contracts with regional and local distribution companies after October 1, 2006 and from entering into new sales contracts with those customers that are identical or similar in nature. For details on this decision and the effect on E.ON Ruhrgas, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions — Pan-European Gas.” E.ON Ruhrgas believes that the FCO is overlooking the negative impact its decision would have on security of supply and that by excluding suppliers from competing to supply additional volume, the FCO has inadmissibly interfered with freedom of contract. Therefore, E.ON Ruhrgas has appealed against the decision issued by the FCO. In June 2006, the State Superior Court (Oberlandesgericht) in Düsseldorf decided in summary proceedings that E.ON Ruhrgas would not be granted temporary relief. Consequently, E.ON Ruhrgas had to terminate the supply contracts with regional and local distribution companies that were covered by the FCO decision as of October 2006. In the summer of 2007, E.ON Ruhrgas concluded new contracts having a duration of only one or two years with virtually all of the regional and local distribution companies whose prior contracts it had been required to cancel. In October 2007, the State Superior Court of Düsseldorf decided in a full proceeding that the FCO decision was lawful. E.ON Ruhrgas is currently challenging the State Superior Court’s decision before the Federal Supreme Court of Justice (Bundesgerichtshof). This appeal proceeding is expected to last through 2009. No assurance can be given that E.ON Ruhrgas will be successful in the appeal proceeding, or otherwise be allowed to conclude contracts that exceed the combination of supply share and duration set by the decision of the FCO and/or bid for the remaining volumes.

If these or other developments were to cause the volume of gas E.ON Ruhrgas is able to sell to fall below the volume it is required to purchase, the take-or-pay provisions of some of E.ON Ruhrgas’ gas supply contracts may become applicable, which would negatively affect its results of operations. In addition, due to increasing competition linked to the liberalization of the gas market and the entry of new competitors, E.ON Ruhrgas may not be able to renew some of its existing gas sales contracts as they expire, or to gain new contracts. This may also have the effect of leaving E.ON Ruhrgas with an excess supply of natural gas and/or decrease margins.

28 As is standard in the gas industry, the price E.ON Ruhrgas pays for gas under its long-term gas supply contracts is calculated on the basis of complex formulas incorporating variables based on current market prices for fuel oil, gas oil, coal and/or other competing fuels, with prices being automatically re-calculated periodically, usually quarterly, by reference to market prices of the relevant fuels during a prior period. Price terms in E.ON Ruhrgas’ gas sales contracts are generally pegged to the price of competing fuels and provide for automatic quarterly price adjustments based on fluctuations in underlying fuel prices, again by reference to market prices during a prior period. Since E.ON Ruhrgas’ supply and sales contracts are generally indexed to different types of oil and related fuels, in different proportions and are adjusted according to different formulas, E.ON Ruhrgas’ margins for natural gas may be significantly affected in the short term by variations in the price of oil or other fuels, which are generally reflected in prices payable under its supply contracts before they are reflected in prices paid under sales contracts, the so-called “time lag” effect. Although E.ON Ruhrgas seeks to manage this risk by matching the general terms of its portfolio of sales contracts with those of its supply contracts, there can be no assurance that it will always be successful in doing so, particularly in the short term. For more information on E.ON Ruhrgas’ gas supply and sales contracts, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions — Pan-European Gas.”

If our plans to make selective acquisitions and investments to enhance our core energy business are unsuccessful, our future earnings and share price could be materially and adversely affected. Our business strategy involves selective acquisitions and investments in our core business area of energy. This strategy depends in part on our ability to successfully identify and acquire companies that enhance our business on acceptable terms. In order to obtain the necessary approvals for acquisitions, we may be required to divest other parts of our business, or to make concessions or undertakings which materially affect our operations. We may not be able to make required divestments on acceptable terms, which could interfere with our declared business strategy and/or adversely affect our business. For example, our efforts to obtain control of Ruhrgas through a series of purchases from the holders of Ruhrgas interests were initially blocked by the FCO and then by a series of plaintiffs who succeeded in convincing the State Superior Court in Düsseldorf to issue a temporary injunction preventing us from completing the transaction. In order to receive the ministerial approval of the German Economics Ministry that overruled the initial decision of the FCO, we were required to make significant concessions, including committing to divest certain operations, to have E.ON Ruhrgas sell a significant quantity of natural gas at auction (with opening bids set at below-market prices) and to offer certain customers the option of reducing the volume of gas they had contracted for. In addition, in settling the claims of the plaintiffs who had received the temporary injunction, we agreed to divest certain of our operations, to provide certain of the plaintiffs with energy supply contracts and network access, and to make certain infrastructure improvements, as well as making financial payments. Each of these matters delayed completion of the Ruhrgas acquisition and had the effect of increasing the cost of the transaction to us. Legal challenges and competing bids also had a significant effect on our proposed acquisition of Endesa, S.A. (“Endesa”), which we were unable to complete on the terms we originally contemplated.

In addition, there can be no assurances that we will be able to achieve the benefits we expect from any acquisition or investment. For example, we may fail to retain key employees, may be unable to successfully integrate new businesses with our existing businesses, may incorrectly judge expected cost savings, operating profits or future market trends and regulatory changes, or may spend more on the acquisition, integration and operations of new businesses than anticipated. Legal challenges may also have an impact. Especially large acquisitions present particularly difficult challenges. Investments and acquisitions in new geographic areas or lines of business require us to become familiar with new markets and competitors and expose us to commercial and other risks, as well as additional regulatory regimes relating to the acquired businesses that may be stricter than the ones we are currently subject to. Because of the risks and uncertainty associated with acquisitions and investments, any acquired businesses or investments may not achieve the profitability we expect.

29 We could be subject to environmental liability associated with our nuclear and conventional power operations that could materially and adversely affect our business. In addition, new or amended environmental laws and regulations may result in significant increases in costs for us. Under German law, the owner of an electric power generation facility is subject to liability provisions that guarantee comprehensive compensation to all injured parties in the event of environmental damages caused by the facility. In addition, there has been some relaxation in the evidence required under the German Environmental Liability Law (Umwelthaftungsgesetz) to establish, prove and quantify environmental claims. Under German law and in accordance with contractual indemnities, we may still be subject to future environmental claims with respect to alleged historical environmental damage arising from certain of our discontinued and disposed of operations, including, but not limited to, the VEBA Oel oil business, the VAW aluminum operations and the Klöckner & Co AG distribution and logistics businesses, as well as Degussa’s chemicals operations. If claims were to be asserted against us in relation to environmental damages and plaintiffs were successful in proving their claims, such claims could result in material losses to us.

German law also provides that in the case of a nuclear accident in Germany, the owner of the reactor, the factory or the nuclear material storage facility is subject to liability provisions that guarantee comprehensive compensation to all injured parties. Under German nuclear power regulations, the owner is strictly liable, and the geographical scope of its liability is not limited to Germany. E.ON’s Swedish nuclear power stations also expose us to liability under applicable Swedish law. In 2006, an inquiry opened by the Swedish government proposed both unlimited liability for nuclear plant operators and that such operators be obligated to purchase additional insurance coverage, although it is unclear what effect the inquiry’s proposals of new legislation will have. We do not operate or have interests in nuclear power plants outside of Germany, Sweden and Switzerland, including in the United Kingdom, the United States, Russia or the countries in Eastern Europe in which we operate. We take extensive safety and risk management measures in the operation of our nuclear power operations, and have mandatory insurance with respect to our nuclear operations. However, any claims against us arising in the case of a nuclear power accident could exceed the coverage of such insurance, and cause material losses to us.

We expect that we will incur costs associated with future environmental compliance, especially compliance with clean air laws. For example, the U.S. Environmental Protection Agency (“EPA”) has introduced regulations regarding the reduction of nitrogen oxide (“NOx”) and sulphur dioxide (“SO2”) emissions from electricity generating units. These regulations require E.ON U.S. to make significant additional capital expenditures in pollution control equipment. E.ON U.S. expects to incur total costs of $0.8 billion in installing these pollution controls during the 2008 through 2010 time period, and expects to recover a significant portion of these costs over time from customers of its regulated utility businesses. In the United Kingdom, legislation to implement the EU Large Combustion Plants Directive has been adopted, which requires E.ON UK to make decisions as to whether it will invest in enhanced pollution control devices, reduce operating time at certain of its plants or consider closing certain plants in the future.

Similarly, the German government has amended an ordinance of the German Federal Pollution Control Act (Bundesimmissionsschutzgesetz, or “BImSchG”) to introduce lower emission limits for air pollutants such as carbon monoxide and NOx. This amendment requires both E.ON Energie and E.ON Ruhrgas to make investments in pollution control devices. In addition, a draft for the 37th BImSchV has been published that foresees a further tightening of NOX-emissions limit values. The new emission limits could come into force in 2013 and could have an impact on the design of new power plants and the maintenance of our existing ones.

Currently, none of our market units can predict the extent to which their respective operations will be affected by the new legislation and/or regulations. Revisions to existing environmental laws and regulations and the adoption of new environmental laws and regulations may result in significant increases in our costs. Any such increase in costs that cannot be fully recovered from customers may adversely affect our operating results or financial condition.

The German government has decided on an extensive national package to reduce greenhouse gas emissions by increasing the share of renewable resources in power and heat generation and promoting energy savings. The

30 package contemplates the amendment of existing laws and/or the creation of new laws. We cannot predict the effects of any such amendments or new laws, which will depend in large measure on the behavior of consumers. The national package is designed to incentivize consumers to act with more awareness of environmental issues and to invest more into environmental-friendly, but more expensive, technology to cover their final energy needs. Our current expectation is that such national package will not come into force before early 2009. We can give no assurances that consumers will act in the manner contemplated by such national package and that such national package, if implemented, will not harm our business and results of operations through a reduction in sales volumes or otherwise.

Although environmental laws and regulations have an increasing impact on our activities in almost all the countries in which we operate, it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. For example, the EU has published a package of measures for a new energy policy which includes ambitious targets for cutting greenhouse gas emissions, but we cannot predict when or in what form these measures might be passed into law, or how we might be impacted. For additional detail, see the discussion on changes in laws and regulations above. Some risk of environmental costs and liabilities is inherent in our particular operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. For more information on environmental matters, see “Business — Environmental Matters.”

If power outages or shutdowns involving our electricity operations occur, our business and results of operations could be negatively affected. Significant parts of Europe and North America have experienced major power outages in recent years. The reasons for these blackouts vary, although generally they involved a locally or regionally inadequate balance between power production and consumption, with single failures triggering a cascade-like shutdown of lines and power plants following overload or voltage problems. The likelihood of this type of problem has increased in recent years following the liberalization of EU electricity markets, partly due to an emphasis on unrestricted cross-border physically-settled electricity trading that has resulted in a substantially higher load on the international network, which was originally designed mainly for purposes of mutual assistance and operations optimization. As a result, there are transmission bottlenecks at many locations in Europe, and the high load has resulted in lower levels of safety reserves in the network. In Germany, where power plants are located in closer proximity to population centers than in many other countries, the risk of blackouts is lower due to shorter transmission paths and a strongly meshed network. In addition, the spread of a power failure is less likely in Germany due to the organization of the German power grid into four balancing zones. Nevertheless, our German or international electricity operations could experience unanticipated operating or other problems leading to a power failure or shutdown. For example: • On January 8-9, 2005, a severe storm hit Sweden, destroying the electricity distribution grid in some areas in the south of the country. Approximately 250,000 E.ON Sverige customers were affected by the resulting power outage, and some customers were left without electricity for several weeks. In 2005, E.ON Sverige recorded related costs for rebuilding its distribution grid and compensating customers of €142 million. • In July 2006, a transmission-related incident at the Forsmark nuclear power plant in Sweden (in which E.ON Sverige owns a minority interest) resulted in an emergency shutdown of the plant and subsequent modifications to the plant’s transmission infrastructure. Reviews of similar infrastructure at other reactors following the Forsmark incident took a number of Swedish reactors out of service for a period of several weeks and revealed the need for a significant overhaul at the Oskarshamn I reactor operated by E.ON Sverige, which was only restarted in January 2007. • On November 4, 2006, an overload in the northwestern German power transmission grid occurred, leading to disturbances in other parts of the continental European power grid and an interruption of the power supply for more than 15 million European households located in parts of Germany, France,

31 Belgium, the Netherlands, Italy and Spain. According to initial findings, the overload occurred after the E.ON Netz GmbH (“E.ON Netz”, a subsidiary of E.ON Energie) control center made an erroneous estimation in its planned interruption of a high voltage power line across the Ems river in Germany to allow the passage of a Norwegian cruise liner. Functioning safety mechanisms and close cooperation among European transmission system operators ensured that a full reconnection of the power grids and stabilization of the system occurred within 38 minutes after the grid separated into three “islands”, thus avoiding an uncontrolled blackout. E.ON Netz does not expect claims related to this incident to have any material impact on its financial results or operations. • On January 14, 2007, another severe storm hit southern Sweden. Approximately 170,000 E.ON Sverige customers were affected by the resulting power outage, and some customers were left without electricity for up to ten days. The costs to E.ON Sverige for rebuilding its distribution grid and compensating affected customers amounted to €95 million. • On January 18 and 19, 2007, a severe storm hit several European countries, damaging the electricity distribution grid of E.ON Energie in some areas of Germany, the Czech Republic, Hungary and Romania. In Germany, approximately 750,000 customers were disconnected from the grid (in the Czech Republic: approximately 500,000 customers; in Hungary: approximately 90,000 customers; in Romania: approximately 5,000 customers). Approximately 80 percent of the affected customers were reconnected within one day, and nearly all customers were reconnected within three days. The costs of repairing the damages were not significant. • On June 28, 2007, the German nuclear power plant Krümmel was shut-down because a transformer caught fire. Since then, the renovations at the transformer building have been completed. In addition to this, in agreement with the authorities and independent experts, wall anchors and valves are also being examined. E.ON Kernkraft GmbH (“E.ON Kernkraft”) holds a 50 percent stake in the power plant which is operated by Vattenfall Europe. • On July 18, 2007, the German nuclear power plant Brunsbüttel was shut-down due to an oil change at the house load transformer. Further, discrepancies were noticed in connection with the mounting plates. In agreement with the authorities and independent experts, an extensive renovation plan is being compiled regarding wall anchors and valves. E.ON Kernkraft only holds a minority stake in the power plant which is operated by Vattenfall Europe. Both Krümmel and Brunsbüttel are expected remain out of service for the next several months.

The areas of the United States in which E.ON U.S. operates are also from time to time subject to severe weather, such as ice storms, which could cause power outages. In Germany, about 40 percent of the country’s wind turbines are connected to the power grid of E.ON Energie, mostly in the north of Germany. In the case of a power grid failure, older wind power plants may switch off automatically, possibly causing a chain reaction and thus increasing the impact of the original power failure in the grid. We can give no assurances that power failures or shutdowns involving our operations will not occur in the future, or that any such power failure or shutdown would not have a negative effect on our business and results of operations.

Financial Risks We are exposed to financial risks that could have a material effect on our financial condition. During the normal course of our business, we are exposed to the risk of energy price volatility, as well as interest rate, commodity price, currency and counterparty risks. These risks are partially hedged on a Group-wide (or market unit-wide) basis, but we may incur losses if any of the variety of instruments and strategies we use to hedge exposures are not effective. For more information about these risks and our hedging policies and instruments, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about Market Risk.” For more information about E.ON Ruhrgas’ take-or-pay contracts, see the discussion on E.ON Ruhrgas’ long-term gas contracts above.

32 We are also exposed to other financial risks. For example, we hold certain stock investments which may expose us to the risk of stock market declines. Financial markets have experienced volatility in recent years, and markets may decline again or become even more volatile. In addition, a significant portion of our outstanding debt bears interest at floating rates; our interest expense will therefore increase if the relevant base rates rise. The value of our investments in fixed rate bonds will be adversely affected by a rise in market interest rates. We also expect the overall level of our debt to increase as we implement our new financial strategy and seek to fund our investment plan. See “Summary — Our Business — Strategy.”

Future adverse changes in a reporting unit’s economic and regulatory environment could adversely affect both estimated future cash flows and discount rates and could result in impairment charges to goodwill which could materially and adversely affect E.ON’s future financial position and net income.

We also face risks arising from our energy trading operations. In general, we seek to hedge risks associated with volatile energy-related prices (including the prices of CO2 emission certificates) by entering into fixed-price bilateral contracts, fuel-price indexed bilateral contracts, futures and options contracts traded on commodities exchanges, and swaps and options traded in over-the-counter financial markets. To the extent we are unable to hedge these risks, or enter into hedging contracts that fail to address our exposure or incorrectly anticipate market movements, we may suffer losses, some of which could be material. In addition to the risks associated with adverse price movements, credit risk is also a factor in our energy marketing, trading and treasury activities, where loss may result from the non-performance of contractual obligations by a counterparty. We maintain credit policies and control procedures with respect to counterparties to protect us against losses associated with such types of credit risk, although there can be no assurance that these policies and procedures will fully protect us. The marking to market of many of our hedging instruments required by Financial Instruments: “Recognition and Measurement” (“IAS 39”), has also increased the volatility of our results of operations, though it has not had a material effect on our overall risk exposure. For example, in 2007, unrealized gains from the marking to market of derivatives, primarily at the U.K. market unit, increased other non-operating income by €564 million. For more information about our energy trading operations, our hedging policies and the instruments used, see “Business — Central Europe — Trading,” “— Pan-European Gas — Trading,” “— U.K. — Energy Wholesale — Energy Trading,” “— Nordic — Trading,” “— U.S. Midwest — Power Generation — Asset-Based Energy Marketing” and “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about Market Risk.”

Risks Related to the Notes There is no public market for the Notes. The Notes comprise a new issue of securities for which there is currently no public market. There is no established trading market for the Notes. The Notes are not listed or admitted for trading on any securities exchange and we have no plans to effect such listing or admission. There can be no assurance as to the liquidity of any market that may develop for the Notes, the ability of holders to sell their Notes, or the prices at which holders might be able to sell their Notes.

The Notes have not been registered under the securities laws of any jurisdiction and the Notes may not be publicly offered, sold, pledged or otherwise transferred in any jurisdiction where such registration may be required.

Any substitution of the Issuer (as defined under “Description of the Notes”) may trigger adverse tax consequences for the Holders of the Notes. The Issuer will be entitled, without the consent of the Holders, at any time to substitute the Guarantor or any Affiliate for the Issuer in accordance with the provisions, and subject to the conditions, set forth under “Description of the Notes-Substitution of Issuer: Consolidation, Merger and Sale of Assets”. Such a substitution may in certain circumstances be treated as a taxable exchange for U.S. federal income tax purposes. Such an

33 exchange would require Holders to recognize taxable gain or loss for U.S. federal income tax purposes. Neither the Issuer nor the Guarantor will be liable to indemnify the Holders for any taxes payable in connection with such substitution. Holders should consult their own tax advisers regarding the possible tax consequences of a substitution of the Issuer.

The Notes are subject to restrictions on transfer. The Notes are being offered in reliance upon an exemption from registration under the Securities Act and applicable state securities laws of the United States. As such, the Notes may be transferred or resold only in a transaction registered under or exempt from the Securities Act and applicable U.S. state securities laws. These restrictions on transfer may have a material adverse effect on the ability of any holder of the Notes to transfer such Notes.

Investors may experience difficulties in enforcing civil liabilities. E.ON AG is incorporated in Germany. The majority of its directors and management (and certain of the parties named in this document) reside outside the United States, and all, or a substantial portion of, E.ON AG’s and such persons’ assets are located outside the United States. As a result, it may not be possible for investors to effect service of process upon E.ON AG or such persons within the United States, or to enforce against E.ON AG or such persons in the United States judgments obtained in the U.S. courts, including judgments predicated upon the civil liability provisions of the federal securities laws of the United States.

Corporate disclosure in Germany may differ from that in the United States. There may be less publicly available information about German public companies, such as E.ON, than is regularly made available by public companies in the United States and in other jurisdictions. We ceased to be an SEC registrant effective December 9, 2007 and, in connection therewith, ceased making filings with the SEC on September 10, 2007.

34 USE OF PROCEEDS

We estimate that the net proceeds from the issuance and sale of the Notes will be approximately U.S.$2,969 million after deducting underwriting discounts and commissions and other expenses of the offering that are to be borne by the Issuer. We intend that substantially all of the net proceeds will be on-lent by the Issuer to the Guarantor and/or entities owned directly or indirectly by the Guarantor for general corporate purposes, which may include financing of recently announced acquisitions.

35 EXCHANGE RATE INFORMATION

We publish our consolidated financial statements in euros. As used in this offering memorandum, the term “noon buying rate” refers to the rate of exchange for euros, expressed in U.S. dollars per euro, as announced by the Federal Reserve Bank of New York for customs purposes as the rate in The City of New York for cable transfers payable in foreign currencies.

The table below shows noon buying rates for the periods and dates indicated. The average for each period is computed using the noon buying rate on the last business day of each month during the period.

On April 14, 2008, the noon buying rate between euro and U.S. dollars was €1.00 = $1.58.

Year ended December 31, High Low Year-end Average 2003 ...... 1.26 1.04 1.26 1.14 2004 ...... 1.36 1.18 1.35 1.25 2005 ...... 1.35 1.17 1.18 1.24 2006 ...... 1.33 1.19 1.32 1.27 2007 ...... 1.49 1.29 1.46 1.38 2008 (through April 14) ...... 1.58 1.44 — 1.51

The following table shows the high and low noon buying rate for U.S. dollars per euro for each month since September 1, 2007.

Month High Low October 2007 ...... 1.45 1.41 November 2007 ...... 1.49 1.44 December 2007 ...... 1.48 1.43 January 2008 ...... 1.49 1.46 February 2008 ...... 1.45 1.52 March 2008 ...... 1.58 1.52 April 2008 (through April 14) ...... 1.58 1.56

36 CAPITALIZATION

The following table sets forth, on a consolidated basis, (i) the cash and cash equivalents and capitalization of the Guarantor and its consolidated subsidiaries at December 31, 2007, in accordance with IFRS; (ii) relevant adjustments to show the effect of this offering of Notes; and (iii) the cash and cash equivalents of the Guarantor and its consolidated subsidiaries at December 31, 2007 as adjusted solely for the effect of this offering of Notes. You should read this table together with our consolidated IFRS financial statements and related discussion and analysis included herein.

As at December 31, 2007 Actual Adjustments As adjusted (in € millions)(3) Cash and cash equivalents ...... € 2,887 €1,879 € 4,766 Financial liabilities(1) ...... €21,464 €1,899(4) € 23,363 Shareholders’ equity: Capital stock(2) ...... 1,734 — 1,734 Additional paid-in capital ...... 11,825 — 11,825 Retained earnings ...... 26,828 — 26,828 Accumulated other comprehensive income ...... 10,656 — 10,656 Treasury stock ...... (616) — (616) Reclassification related to put options on treasury stock ...... (1,053) — (1,053) Total equity attributable to shareholders ...... 49,374 — 49,374 Total capitalization ...... €70,838 €1,899(4) € 72,737

(1) Includes current and non-current financial liabilities. See Note 26 of the Notes to our Consolidated Financial Statements on page F-68. Subsequent to December 31, 2007, there has not been a material change in our consolidated financial liabilities. There has been no other material change since December 31, 2007 in our consolidated capitalization or indebtedness. (2) As of December 31, 2007, the Guarantor’s authorized share capital amounted to €1.73 billion divided into 631,622,782 registered ordinary shares with no par value. (3) The euro equivalent of Notes offered hereby is based on a euro/U.S. dollar exchange rate of U.S. $1.58 = €1.00, which was the noon buying rate for cable transfers payable in euro, as reported by the Federal Reserve Bank of New York on April 14, 2008. (4) The adjustment of €1,899 million reflects the euro equivalent of the $3,000 million principal amount of the Notes based on a euro/U.S. dollar exchange rate of U.S. $1.58 = €1.00. The principal amount of the Notes would not have been the financial liability recorded on our consolidated balance sheet under IFRS. Non- derivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at amortized cost, using the effective interest method. Initial measurement takes place at fair value plus transaction costs. In subsequent periods, the amortization and accretion of any premium or discount is included in financial results.

37 OPERATING AND FINANCIAL REVIEW AND PROSPECTS

This section should be read in conjunction with our consolidated financial statements for the years ended and as at December 31, 2007 and 2006, prepared in accordance with IFRS and contained herein beginning on page F-3, and our consolidated financial statements for the years ended and as at December 31, 2006 and 2005, prepared in accordance with U.S. GAAP and incorporated herein by reference. See “Presentation of Financial Data — Incorporation of Certain Financial Statements by Reference”.

Overview On June 16, 2000, the Company completed the merger between VEBA and VIAG. The VEBA-VIAG merger was accounted for under the purchase method of accounting. The operations of VIAG have been included in E.ON’s financial data since July 1, 2000. For more information on the VEBA-VIAG merger, see “Business — History and Development of the Company.”

In March 2003, E.ON completed the acquisition of all of the outstanding shares of the former Ruhrgas and has fully consolidated Ruhrgas’ results since February 2003. The total cost of the transaction to E.ON, including settlement costs and excluding dividends acquired, amounted to €10.2 billion. Goodwill in the amount of €2.9 billion resulted from the purchase price allocation. In late January 2003, E.ON completed the first step of the two-step RAG/Degussa transaction. In the first step, E.ON acquired RAG’s Ruhrgas stake and tendered 37.2 million of its shares in Degussa to RAG at the price of €38 per share, receiving total proceeds of €1.4 billion. A gain of €168 million was realized from the sale. Following this transaction and the completion of the tender offer to the other Degussa shareholders, RAG and E.ON each held a 46.5 percent interest in Degussa, with the remainder being held by the public. In the second step, E.ON sold a further 3.6 percent of Degussa to RAG on May 31, 2004, reducing its stake to 42.9 percent of Degussa. Total proceeds from this transaction amounted to €283 million, resulting in a gain of €51 million. In December 2005, E.ON AG and RAG signed a framework agreement on the sale of E.ON’s 42.9 percent stake in Degussa to RAG. As part of the implementation of that framework agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft in March 2006 and agreed on the forward sale of that entity to RAG for a purchase price of €2.8 billion (equal to €31.50 per Degussa share). The transaction closed in July 2006, with E.ON recording a book gain of €596 million on the forward sale. Until the completion of this transaction, E.ON and RAG operated Degussa under joint control, and E.ON accounted for its 42.9 percent interest in Degussa under the equity method. E.ON owns a 39.2 percent interest in RAG. For additional material on acquisitions and dispositions during the period under review, see “— Acquisitions and Dispositions” below.

Basis Of Presentation Accounting Principles. In 2002, the European Parliament and the European Council mandated the adoption of IFRS, as adopted by the EU, by companies whose securities are publicly traded on a regulated market in an EU member state, in respect of fiscal years beginning on or after January 1, 2005. E.ON made use of the option available under German law for companies that had been preparing their consolidated financial statements in accordance with U.S. GAAP and whose stock was officially listed for public trading in a non-EU member state to defer the mandatory adoption of IFRS until 2007. Until December 31, 2006, E.ON prepared its financial statements in accordance with U.S. GAAP. E.ON’s American Depositary Shares were listed on the New York Stock Exchange until September 7, 2007, and the Company was deregistered and terminated its reporting obligations with the Securities and Exchange Commission as of December 2007.

E.ON’s consolidated financial statements for the year ended December 31, 2007, as included in this offering memorandum, have been prepared in accordance with IFRS 1. These consolidated financial statements have been prepared in accordance with Article 315a (1) of the HGB and with those IFRS and IFRIC interpretations that had been adopted by the European Commission for use in the EU as of the end of the fiscal year, and whose application was mandatory as of December 31, 2007. In addition, E.ON has elected the voluntary early adoption

38 of IFRS 8. For information about the changes in the Group’s accounting policies as compared with the accounting principles used in the annual consolidated financial statements for prior years, i.e., U.S. GAAP, see Note 1 of the Notes to Consolidated Financial Statements. For information about the effects of the transition from U.S. GAAP to IFRS, see Note 35 of the Notes to Consolidated Financial Statements.

In connection with the transition to IFRS, E.ON’s financial statements for the fiscal year 2006 have been prepared according to IFRS, and the consolidated financial statements included in this offering memorandum therefore contain comparable information for 2006 prepared on the basis of IFRS. Accordingly, the analysis of E.ON’s consolidated results and those of its individual market units in 2007 and 2006 presented below has been prepared using the financial statements prepared in accordance with IFRS. As E.ON has not prepared any financial statements for 2005 in accordance with IFRS, the parallel year-on-year analysis of our results for 2005 and 2006 has been prepared on the basis of E.ON’s U.S. GAAP consolidated financial statements (included in our Annual Report on Form 20-F for the fiscal year ended December 31, 2006 and incorporated herein by reference), which are not included in this offering memorandum. Unless otherwise indicated, financial data for 2006 appearing outside of such year-on-year analysis (e.g., in the analysis of Liquidity and Capital Resources and that of Cash Flow and Capital Expenditures), has been prepared in accordance with IFRS.

Sales. Unless otherwise indicated, sales are presented net of electricity and energy taxes.

Non-GAAP Measures. E.ON uses “adjusted EBIT” as the measure pursuant to which the Group evaluates the performance of its segments and allocates resources to them. Adjusted EBIT is an adjusted figure derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment basis) before income taxes and interest income. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and other non-operating earnings of an exceptional nature. In addition, net interest income is adjusted using economic criteria and excluding certain special items, i.e., the portions of interest expense that are non-operating. Management believes that adjusted EBIT is the most useful segment performance measure because it better depicts the performance of individual business units independent of changes in interest income and taxes. During all relevant periods, E.ON has used adjusted EBIT as its primary segment reporting measure, originally in accordance with SFAS 131 under U.S GAAP, and now in accordance with IFRS 8. However, on a consolidated Group basis, adjusted EBIT is considered a non-GAAP measure that should be reconciled to the most directly comparable GAAP measure. Adjusted EBIT should not be considered in isolation as a measure of E.ON’s profitability and should be considered in addition to, rather than as a substitute for the most directly comparable GAAP measures. In particular, there are material limitations associated with the use of Adjusted EBIT as compared with such GAAP measures, including the limitations inherent in E.ON’s determination of each of the adjustments noted above. E.ON seeks to compensate for those limitations by providing below a detailed reconciliation of adjusted EBIT to income from continuing operations before income taxes and minority interests and net income, the most directly comparable GAAP measures, as well as the more detailed textual analysis of year-on-year changes in the key components of each of the reconciling items appearing under the caption “— Results of Operations — E.ON Group — Reconciliation of Adjusted EBIT” for each of the relevant periods. As a result of these limitations and other factors, adjusted EBIT as used by E.ON may differ from, and not be comparable to, similarly titled measures used by other companies. For further details, see Note 33 of the Notes to Consolidated Financial Statements.

Segment Reporting. Until December 31, 2007, E.ON’s core energy business was divided into five regional market units (Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest), plus the Corporate Center. The lead company of each market unit reports directly to E.ON AG. E.ON’s financial reporting mirrors this structure, with each of the five market units and the results of the enhanced Corporate Center (including consolidation effects) constituting a separate segment for financial reporting purposes. Until its disposal, E.ON also reported its only remaining telecommunications interest, a 50.1 percent stake in the Austrian mobile telecommunications network operator ONE GmbH (“ONE”), which was accounted for at equity in E.ON’s consolidated financial statements, under Corporate Center. For the period between Degussa’s deconsolidation and E.ON’s disposal of its interest in July 2006, E.ON’s proportionate share of Degussa’s after-tax earnings

39 continued to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which was reported as a separate segment under U.S GAAP.

Since January 1, 2008, E.ON has been organized into nine different market units, having added the Energy Trading, Italy, Russia and Climate & Renewables market units. If and when we will be able to close the acquisition of Viesgo and additional generation capacity in Spain from Endesa, these operations are expected to be organized in the new market unit Spain. For information about the planned acquisition, see “Business — History and Development of the Company.” Until the end of 2008, the results of each of the new market units other than Energy Trading will be reported as part of the Corporate Center segment; Energy Trading’s results will be reported separately. For information about the new market unit structure, see “Summary — Business Overview.”

Acquisitions And Dispositions The following discussion summarizes each of the principal acquisitions and dispositions made by E.ON since January 1, 2005, and is organized by business segment according to E.ON’s market unit structure as of December 31, 2007.

Central Europe. In 2005, E.ON Energie acquired the remaining interests of 1.0 percent and 1.3 percent, respectively, in the Czech regional electricity utilities Jihomoravská energetika a.s. and Jihoceská energetika a.s. for a total of €5 million. As of January 1, 2005, E.ON Energie re-organized the entities and fulfilled legal unbundling requirements by transferring the businesses of JME and JCE to three new subsidiaries. E.ON Energie now holds 100.0 percent of each of E.ON Ceská republika, a.s., E.ON Distribuce, a.s. and E.ON Energie, a.s. No goodwill resulted from the purchase price allocation.

In February 2005, E.ON Energie acquired 67.0 percent stakes in each of the two Bulgarian electricity distribution companies Varna and Gorna Oryahovitza. The aggregate purchase price of €141 million, which was subsequently reduced to €138 million, had already been paid in 2004. Goodwill of €16 million resulted from the purchase price allocation. The companies were fully consolidated as of March 1, 2005.

In 2005, E.ON Energie increased its stake in the Hungarian gas distribution and supply company KÖGÁZ from 31.2 percent to 98.1 percent in several steps for aggregate consideration of €27 million. No goodwill resulted from the purchase price allocation. KÖGÁZ was consolidated as of April 1, 2005. As of December 31, 2007 E.ON Energie held 99.6 percent.

In July 2005, E.ON Energie transferred its 51.0 percent interest (49.0 percent voting interest) in Gasversorgung Thüringen GmbH (“GVT”) and its 72.7 percent interest in Thüringer Energie AG (“TEAG”) to Thüringer Energie Beteiligungsgesellschaft mbH (“TEB”). Municipal shareholders also transferred to TEB interests in GVT totaling 43.9 percent. Consequently, GVT was merged into TEAG and the merged entity was renamed E.ON Thüringer Energie AG (“ETE”). Following this reorganization, E.ON Energie held an 81.5 percent interest in TEB and TEB held a 76.8 percent interest in ETE. The consolidation of GVT as of July 1, 2005, with an acquisition cost of €168 million, led to goodwill of €58 million as a result of the purchase price allocation. The transfer of the stakeholding in TEAG resulted in a gain of €90 million. As of December 31, 2007, E.ON Energie held 77.0 percent of ETE.

In September 2005, E.ON Energie completed the acquisition of 100.0 percent of the Dutch electricity and gas distributor NRE. The purchase price amounted to €79 million, with €46 million in goodwill resulting from the purchase price allocation. NRE was consolidated as of September 1, 2005.

In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution company Electrica Moldova — renamed E.ON Moldova — and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. The total consideration for the 51.0 percent

40 interest amounted to €102 million, with no goodwill resulting from the purchase price allocation. E.ON Moldova was consolidated as of September 30, 2005.

In June 2005, the general meeting of Contigas passed a resolution authorizing E.ON Energie to use a squeeze-out procedure to acquire any remaining Contigas stock still held by minority shareholders. In July 2005, E.ON Energie acquired an additional 0.9 percent interest in Contigas through a public offer. Following the completion of the squeeze-out in November 2005, E.ON Energie acquired the remaining 0.2 percent and now owns 100.0 percent of Contigas. Total consideration was €45 million (of which €36 million was attributable to the transfer of E.ON shares), resulting in goodwill from the purchase price allocation of €36 million.

In August 2006, E.ON Energie and RWE swapped certain of their respective shareholdings in Hungary and the Czech Republic. In Hungary, E.ON Energie acquired — in addition to its existing interest of 50.02 percent — 49.9 percent of the shares of DDGÁZ, a gas distribution company (fully consolidated in 2005). RWE acquired E.ON Energie’s interest of 16.3 percent in Fövárosi Gázmüvek Részvénytársaság. In the Czech Republic, E.ON Energie gave up certain minority shareholdings and increased its interest in JCP (a gas distribution company) in two steps, first acquiring additional shares from RWE to increase its existing interest of 13.1 percent to 59.8 percent, and then in September 2006 acquiring an additional 39.2 percent interest in JCP from Oberösterreichische Ferngas AG and other minority shareholders. As of December 31, 2006, E.ON Energie held a 99.0 percent interest in JCP, which was consolidated as of September 1, 2006. In January 2007, E.ON Energie acquired the remaining 1.0 percent in JCP in a squeeze-out proceeding and now holds 100.0 percent of JCP. The total consideration (for JCP and DDGÁZ) including the fair value of the swapped E.ON interest amounted to €104 million, of which €30 million was paid in cash, with €3 million in goodwill resulting from the purchase price allocation for DDGÁZ (the allocation for JCP resulted in no goodwill). As part of the asset swap, E.ON Energie acquired in the Czech Republic a 25.0 percent interest in PPH and a 49.3 percent interest in PP for €63 million.

In December 2006, E.ON Energie acquired a 49.9 percent minority interest in the waste incineration company SOTEC GmbH. In January 2008, E.ON Energie acquired the remaining shares. Total consideration amounted to €120 million.

In December 2006, E.ON Energie acquired 75.0 percent of the share capital of Dalmine, an Italian company that focuses on the wholesale of electricity and gas, primarily to industrial customers. The purchase price amounted to €47 million. The remaining shares were acquired in October 2007 for €17 million. Dalmine has been consolidated since December 1, 2006. Goodwill of €9 million was recorded following the final purchase price allocation.

Pan-European Gas. In November 2004, ERI signed an agreement with the Hungarian oil and gas company MOL RT. (“MOL”) for the acquisition of interests of 75.0 percent minus one share in each of MOL’s gas trading and gas storage units and its 50.0 percent interest in the gas importer Panrusgáz Zrt. (“Panrusgáz”). In December 2005, the European Commission approved the acquisitions of the gas trading and storage businesses subject to certain conditions. One of these conditions is that MOL must fully divest its gas storage and trading businesses. As a result, ERI signed an agreement providing for its acquisition of the remaining 25.0 percent plus one share of the gas storage and trading businesses. The total consideration amounted to €445 million. In addition, ERI assumed debt amounting to €600 million. ERI and MOL also agreed upon a purchase price adjustment mechanism designed to reflect developments in the relevant regulatory framework through 2009. The acquisition of the gas storage and trading units was completed by the end of March 2006, and the purchase price was subsequently adjusted to €400 million. The initial goodwill of €205 million was reduced to €119 million after a purchase price adjustment and the purchase price allocation. The acquisition of MOL’s 50.0 percent interest in Panrusgáz was completed at the end of October 2006.

In June 2005, E.ON Ruhrgas acquired a 51.0 percent stake in the Romanian gas supplier S.C. Distrigaz Nord S.A. (“Distrigaz Nord”) from the Romanian government in a two-step transaction. In the first step, E.ON Ruhrgas acquired a 30.0 percent share in Distrigaz Nord. In the second step, which immediately followed the

41 first, this stake was increased to 51.0 percent through a capital increase. E.ON Ruhrgas paid an aggregate of €305 million for the 51.0 percent stake; €127 million for the 30.0 percent interest and €178 million in the capital increase. Goodwill of €60 million resulted from the purchase price allocation. Distrigaz Nord was consolidated as of June 30, 2005 and has since been renamed E.ON Gaz România.

In November 2005, E.ON Ruhrgas acquired Caledonia Oil and Gas Ltd. (“Caledonia”), a U.K. gas production company with interests in a number of producing gas fields and development projects in the British North Sea, two field pipelines and 100.0 percent of a gas trading company. The seller was a group of investors led by the private equity firm First Reserve. Caledonia was subsequently renamed E.ON Ruhrgas North Sea. The total purchase price for the 100.0 percent interest in Caledonia amounted to €602 million and was primarily paid through the issuance of loan notes. For more information on these loan notes, see Note 26 of the Notes to Consolidated Financial Statements. Goodwill of €390 million resulted from the final purchase price allocation. Caledonia was fully consolidated as of November 1, 2005.

In June 2007, E.ON Ruhrgas AG participated in the joint venture to plan a new European gas pipeline in Scandinavia. This Skanled pipeline is to transport Norwegian gas to Norway, Sweden and Denmark. With a 15 percent stake, E.ON Ruhrgas is one of the largest partners in the European pipeline project, in which a total of 10 companies from Norway, Sweden, Denmark and Poland are involved. The total investment for the pipeline (of which E.ON expects to bear a pro rata share) is estimated at €1,300 million according to an updated design incorporating developments in the markets for the procurement of materials and construction services. A final decision on construction of the pipeline is to be taken by the end of 2009. If constructed, the pipeline is then expected to come into operation by 2012.

In August 2007, E.ON Ruhrgas acquired through its subsidiary E.ON Ruhrgas Norge AS an approximately 28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from Shell, retroactively as of January 1, 2007. E.ON Ruhgas Norge AS’ share of the investments for developing the fields is expected to be around $1.4 billion (around €1.0 billion). Skarv and Idun are both located in the northern Norwegian Sea, just below the Arctic Circle. Gas production is expected to start in 2011.

In November 2007, E.ON Ruhrgas acquired a 10 percent stake in the Austrian gas transportation company Baumgarten-Oberkappel Gasleitungsgesellschaft mbH. As a result, the shareholding of E.ON Ruhrgas in the company has increased to 15 percent.

In December 2007, E.ON Ruhrgas E & P GmbH acquired a 30.05 percent stake in the Austrian holding company EESU Holding GmbH, which subsequently acquired an indirect 25 percent stake in the Austrian exploration company Roöhl-Aufsuchungs Aktiengesellschaft.

U.K. In the first half of 2005, E.ON UK acquired, in two tranches, 100.0 percent of the equity of Enfield Energy Centre Ltd. (“Enfield”) from NRG, El Paso and Indeck. The total consideration amounted to €185 million, with no goodwill resulting from the purchase price allocation. Enfield was fully consolidated as of April 1, 2005.

In July 2005, E.ON UK acquired 100.0 percent of Holford Gas Storage Limited (“HGSL”) from Scottish Power Energy Management Limited. The total consideration amounted to €140 million, with no goodwill resulting from the purchase price allocation. HGSL was consolidated as of July 28, 2005.

In December 2006, E.ON UK sold its shareholding in Edenderry Power Limited to Bord na Mona plc for €80 million, realizing a gain on the sale of €20 million.

Nordic. In September 2004, E.ON agreed further details regarding its agreement in principle with Statkraft to sell a portion (1.6 TWh) of the generating capacity that E.ON Sverige had acquired as part of the Graninge AB (“Graninge”) acquisition to Statkraft. In July 2005, Sydkraft and Statkraft signed the corresponding agreement,

42 whereby Statkraft would acquire a total of 24 hydropower plants. In accordance with the agreement, Statkraft took ownership of the plants in October 2005. The total consideration amounted to €481 million, corresponding to the assets’ book value. Because assets and liabilities were recognized at fair values as part of the purchase price allocation following the acquisition of Graninge, the sale of the disposal group did not result in a significant effect on income.

In August 2006, E.ON Sverige sold a 75.1 percent interest in the broadband communication business E.ON Sverige Bredband to Tele2 for consideration of €44 million. The sale agreement also provides E.ON Sverige with the option to put its remaining 24.9 percent interest to Tele2 within 24 months and Tele2 with the call option to acquire E.ON Sverige’s remaining shares in E.ON Sverige Bredband in the event that E.ON Sverige does not exercise the put option. E.ON recorded a gain of €28 million on the disposal. In June 2007, E.ON Sverige exercised the put option on E.ON Sverige Bredband and sold the remaining 24.9 percent stake to Tele2. E.ON recorded a gain of €9 million on the disposal.

U.S. Midwest. In June 2007, ECC sold its approximate 19.6 percent interests in the Argentine gas distribution company, Ban and related companies for €37 million. In June 2006, ECC’s subsidiaries, LG&E Power Inc. (“LPI”) and LG&E Power Services LLC, sold a 50.0 percent ownership interest in a 209 MW coal- fired facility in North Carolina and sold the remaining operations and maintenance contracts relating to the North Carolina plant along with four independent power generation facilities contracts for total consideration of €21 million.

Corporate Center. In December 2005, E.ON AG and RAG signed a framework agreement on the sale of E.ON’s 42.9 percent participation in Degussa to RAG. As part of the implementation of that framework agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft in March 2006 and agreed on the forward sale of that entity to RAG for a purchase price of €2.8 billion. The transaction closed in July 2006, with E.ON recording a book gain of €596 million on the forward sale. Until the completion of this transaction, E.ON and RAG operated Degussa under joint control, and E.ON accounted for its 42.9 percent interest in Degussa under the equity method. E.ON owns a 39.2 percent interest in RAG.

In June 2007, E.ON and its partners Telenor and Tele Danmark signed a contract to sell their shares in the Austrian telecommunications company ONE to a consortium of bidders consisting of France Télécom and the financial investor Mid Europa Partners. The transfer of E.ON’s 50.1 percent stake became effective on October 2, 2007. In the fourth quarter of 2007, E.ON realized cash proceeds of €569 million from the sale (including repayment of shareholder loans previously granted), as well as a book gain of €321 million.

In August 2007, E.ON Climate & Renewables acquired a 100.0 percent stake in E2-I. Through its affiliated and associated companies, E2-I primarily operates wind farms in Spain and Portugal. The purchase price totaled €481 million. E2-I and its affiliated companies were fully consolidated as of September 1, 2007. The E.ON consolidated financial statements included revenues of €5 million and a loss of €1 million attributable to E2-I for the period from September 1 through December 31, 2007 (after the write-down of differences in fair values from the purchase price allocation).

In August 2007, E.ON, ThyssenKrupp and RWE came to an agreement with the foundation “RAG-Stiftung” to sell their shares of RAG to that foundation. The three shareholding companies held a total of 90 percent of the share capital of RAG. The block of E.ON shares was transferred on November 30, 2007, for a nominal price of €1.

In October 2007, E.ON acquired from the Russian government’s energy holding company RAO UES a majority stake in the Russian power plant company OGK-4. After the acquisition of additional smaller tranches following the purchase of the majority stake, E.ON held 72.7 percent of OGK-4 as of December 31, 2007. The total cost incurred by E.ON for this acquisition, which includes a contractually agreed capital increase of €1.3 billion to finance the investment program planned for the coming years, was €4.4 billion.

43 Under Russian capital-markets legislation, E.ON was required to make a public offer to purchase the remainder of the shares held by the minority shareholders of OGK-4, and this offer, at a price of 3.3503 rubles per share, was made public on November 15, 2007. The acceptance period ended on February 4, 2008. E.ON was thus able to acquire additional shares equivalent to approximately 3.4 percent of OGK-4 and increase its total ownership stake to approximately 76.1 percent. As was expected, RAO UES did not accept the offer for its 22.5 percent stake in OGK-4.

OGK-4 operates conventional power plants at five locations with a total installed output of 8.6 GW and plans to build additional power plants with a capacity of approximately 2.4 GW at the existing locations by 2011. OGK-4 was consolidated as of October 1, 2007. The E.ON consolidated financial statements included revenues of €248 million and earnings of €3 million (after the write-down of fair value adjustments from the preliminary purchase price allocation) attributable to OGK-4 for the period from October 1 through December 31, 2007. The purchase price allocation for OGK-4 was not final as of December 31, 2007, because effects on property, plant and equipment and from potential obligations, in particular, remain to be evaluated. Goodwill of €1,733 million resulted from the preliminary purchase price allocation.

In December 2007, E.ON North America Holdings LLC acquired all the shares of Airtricity for a purchase price of €580 million. Airtricity operates a number of wind farms in the U.S. states of Texas and New York with a total installed capacity of around 250 MW. Additional wind farms are expected to be completed by the end of 2008. The full consolidation of the Airtricity companies took place on December 31, 2007. Goodwill of €718 million resulted from the preliminary purchase price allocation for the business combinations of Airtricity and E2-I.

Critical Accounting Policies And Estimates The preparation of the consolidated financial statements requires management to make estimates and assumptions that may influence the application of accounting principles within the Group and affect the valuation and presentation of reported figures. Estimates are based on past experience and on additional knowledge obtained on transactions to be reported. Actual amounts could differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Adjustments to accounting estimates are recognized in the period in which the estimate is revised if the change affects only that period or in the period of the revision and subsequent periods if both current and future periods are affected. Estimates are particularly necessary for the measurement of the value of property, plant and equipment and of intangible assets, especially in connection with purchase price allocations, the recognition and measurement of deferred taxes, the accounting treatment of provisions for pensions and miscellaneous provisions, as well as for impairment testing in accordance with IAS 36, “Impairment of Assets” (“IAS 36”). The underlying principles used for estimates in each of the relevant topics are outlined in the respective sections.

Business Combinations In accordance with the exemption allowed under IFRS 1, the provisions of IFRS 3, “Business Combinations” (“IFRS 3”) were not applied with respect to the accounting for business combinations that occurred before January 1, 2006. The goodwill maintained from this period did not include any intangible assets that had to be reported separately under IFRS. Conversely, there were no intangible assets that until now had been reported separately that had to be included in goodwill. As no adjustment for intangible assets was required relating to such business combinations, the goodwill reported under U.S. GAAP was maintained in E.ON’s opening balance sheet under IFRS.

Business combinations are accounted for by applying the purchase method, whereby the purchase price is offset against the proportional share in the acquired company’s net assets. In doing so, the values at the acquisition date are used as a basis. The acquiree’s identifiable assets, liabilities and contingent liabilities are recognized at their fair values, regardless of the extent attributable to minority interests. The fair values of

44 individual assets are determined using published exchange or market prices at the time of acquisition in the case of marketable securities, for example, and in the case of land, buildings and more significant technical equipment, generally using independent valuation reports that have been prepared by third parties. If exchange or market prices are unavailable for consideration, fair values are determined using the most reliable information available that is based on market prices for comparable assets or on suitable valuation techniques. In such cases, E.ON determines fair value using the discounted cash flow method by discounting estimated future cash flows by a weighted average cost of capital. Estimated cash flows are consistent with the internal mid-term planning data for the next three years, followed by two additional years of cash flow projections, which are extrapolated until the end of an asset’s useful life using a growth rate based on industry and internal projections. The discount rate reflects specific risks inherent to the asset.

Transactions with minority shareholders are treated in the same way as transactions with equity holders. Should the acquisition of additional shares in a subsidiary result in a difference between the cost of purchasing the shares and the carrying amount of the minority interest acquired, that difference must be fully recognized in equity.

Gains and losses from disposals of shares to minority shareholders are also recognized in equity, provided that such disposals do not result in a loss of control.

Intangible assets must be recognized separately from goodwill if they are clearly separable or if their recognition arises from a contractual or other legal right. Provisions for restructuring measures may not be recorded in a purchase price allocation. If the purchase price paid exceeds the proportional share in the net assets at the time of acquisition, the positive difference is recognized as goodwill. A negative difference is immediately recognized in income.

Management utilizes certain assumptions and estimates believed to be reasonable in fair valuing assets and liabilities assumed in a business combination. These estimates are based on historical experience and information obtained from the management of the acquired companies and are inherently uncertain. Critical estimates used in valuing certain assets include, but are not limited to, future expected cash flows, discount rates, the useful life over which cash flows will occur, the acquired company’s market position and regulatory environment. Any changes in these underlying factors and assumptions may materially affect the Company’s financial position and net income.

Revenue Recognition The Company generally recognizes revenue upon delivery of products to customers or upon fulfillment of services. Delivery has occurred when the risks and rewards associated with ownership have been transferred to the buyer, compensation has been contractually established and collection of the resulting receivable is probable. Revenues from the sale of goods and services are measured at the fair value of the consideration received or receivable. Revenues are presented net of sales taxes, returns, rebates and discounts, and after elimination of intercompany sales. Revenues are generated primarily from the sale of electricity and gas to industrial and commercial customers and to retail customers. Additional revenue is earned from the distribution of electricity and gas, as well as from deliveries of steam and heat. Revenues from the sale of electricity and gas to industrial and commercial customers and to retail customers are recognized when earned on the basis of a contractual arrangement with the customer; they reflect the value of the volume supplied, including an estimated value of the volume supplied to customers between the date of their last meter reading and period-end.

Goodwill and Intangible Assets Goodwill According to IFRS 3, goodwill is not amortized, but rather tested for impairment at the cash-generating unit level on at least an annual basis. Impairment tests must also be performed between these annual tests if events or changes in circumstances indicate that the carrying amount of the respective cash-generating unit might not be recoverable.

45 Newly created goodwill is allocated to those cash-generating units expected to benefit from the respective business combination. E.ON has identified the operating units one level below its primary segments as its cash- generating units.

In a first step, E.ON determines the recoverable amount of a cash-generating unit on the basis of the fair value (less costs to sell) using valuation procedures that make use of the Company’s internal mid-term planning data. Valuation is based on the discounted cash flow method, and accuracy is verified through the use of multipliers. In addition, market transactions or valuations prepared by third parties for comparable assets are used to the extent available.

In an impairment test, the recoverable amount of a cash-generating unit is compared with its carrying amount, including goodwill. The recoverable amount is the higher of the cash-generating unit’s fair value less costs to sell and its value in use. If the carrying amount exceeds the recoverable amount, the goodwill allocated to that cash-generating unit is adjusted in the amount of this difference. If the impairment thus identified exceeds the goodwill allocated to the affected cash-generating unit, the remaining assets of the unit must be written down in the proportion of their carrying amounts. Individual assets may not be written down if their respective carrying amounts were to fall below the highest of the following as a result: • Fair value less costs to sell • Value in use • Zero

The impairment loss that would otherwise have been allocated to the asset concerned must instead be allocated pro rata to the remaining assets of the unit. E.ON has elected to perform the annual testing of goodwill for impairment at the cash-generating unit level in the fourth quarter of each fiscal year.

Impairment losses recognized for goodwill in a cash-generating unit may not be reversed in subsequent reporting periods.

E.ON has goodwill totaling €16,761 million as of December 31, 2007, as compared with €15,320 million as of December 31, 2006, resulting from various significant acquisitions in recent years. Intangible assets not subject to amortization amounted to €1,503 million as of December 31, 2007, as compared with €1,263 million as of December 31, 2006. Future adverse changes in a reporting unit’s economic and regulatory environment could adversely affect both estimated future cash flows and discount rates and could result in impairment charges to goodwill which could materially and adversely affect E.ON’s future financial position and net income.

In 2007 and 2006, no impairment charges on goodwill resulted from the testing of goodwill for impairment.

Intangible Assets IAS 38, “Intangible Assets” (“IAS 38”) requires that intangible assets be amortized over their useful lives unless their lives are considered to be indefinite. Intangible assets not subject to amortization are measured at cost and must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Acquired intangible assets subject to amortization are classified as marketing-related, customer-related, contract-based, and technology-based. Internally generated intangible assets subject to amortization are related to software. Intangible assets subject to amortization are measured at cost and amortized using the straight-line method over their expected useful lives, generally for a period between 5 and 25 years or between 3 and 5 years for software, respectively. Useful lives and amortization methods are subject to annual verification. Intangible assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate that such assets may be impaired.

46 Intangible assets not subject to amortization are measured at cost and tested for impairment annually or more frequently if events or changes in circumstances indicate that such assets may be impaired. Moreover, such assets are reviewed annually to determine whether an assessment of indefinite useful life remains applicable.

In accordance with IAS 36, the carrying amount of an intangible asset, whether subject to amortization or not, is tested for impairment by comparing the carrying value with its recoverable amount, which is the higher of an asset’s value in use and its fair value less costs to sell. Should the carrying amount exceed the recoverable amount, an impairment charge equal to the difference between the carrying amount and the recoverable amount is recognized. If the reasons for previously recognized impairment losses no longer exist, such impairment losses are reversed. A reversal shall not cause the carrying amount of an intangible asset subject to amortization to exceed the amount that would have been determined, net of amortization, had no impairment loss been recognized during the period.

If a recoverable amount cannot be determined for an individual intangible asset, the recoverable amount for the smallest identifiable group of assets (cash-generating unit) that the intangible asset may be assigned to is determined.

***

In 2007, impairment charges of €66 million on intangible assets not subject to amortization resulted from the impairment tests conducted under the principles outlined above. No impairment charges have been recorded on goodwill and intangible assets subject to amortization.

Please see Note 14(a) of the Notes to Consolidated Financial Statements for additional information about goodwill and intangible assets.

The assumptions and conditions used to determine recoverability reflect the Company’s best estimates and assumptions utilizing data currently available and are consistent with internal planning, but these items involve inherent uncertainties. As a result, the accounting for such items could result in different amounts if management used different assumptions or if different conditions occur in future periods.

Property, Plant and Equipment Property, plant and equipment are initially measured at acquisition or production cost, including decommissioning or restoration cost that must be capitalized, and are depreciated over their expected useful lives, generally using the straight-line method, unless a different method of depreciation is deemed more suitable in certain exceptional cases.

Property, plant and equipment are tested for impairment whenever events or changes in circumstances indicate that an asset may be impaired. In such a case, property, plant and equipment are tested for impairment according to the principles prescribed for intangible assets in IAS 36. If an impairment loss is determined, the remaining useful life of the asset might also be subject to adjustment, where applicable. If the reasons for previously recognized impairment losses no longer exist, such impairment losses are reversed and recognized in income. Such reversal shall not cause the carrying amount to exceed the amount that would have been presented had no impairment taken place during the preceding periods.

Investment subsidies do not reduce the acquisition and production costs of the respective assets; they are instead reported on the balance sheet as deferred income.

Subsequent costs arising, for example, from additional or replacement capital expenditure are only recognized as part of the acquisition or production cost of the asset, or else — if relevant — recognized as a separate asset if it is probable that the Group will receive a future economic benefit and the cost can be determined reliably.

47 Repair and maintenance costs that do not constitute significant replacement capital expenditure are expensed as incurred.

In 2007, E.ON recorded impairment charges totaling €33 million on property, plant and equipment.

Financial Instruments Non-Derivative Financial Instruments Non-derivative financial instruments are recognized at fair value on the settlement date when acquired. Unconsolidated equity investments and securities are measured in accordance with IAS 39. E.ON categorizes financial assets as held for trading, available for sale, or as loans and receivables. Management determines the categorization of the financial assets at initial recognition.

Securities categorized as available for sale are carried at fair value on a continuing basis, with any resulting unrealized gains and losses, net of related deferred taxes, reported as a separate component within equity until realized. Realized gains and losses are recorded based on the specific identification method. Unrealized losses previously recognized in equity are recognized in financial results in the case of substantial impairment. Reversals of impairment losses relating to equity instruments are recognized exclusively in equity.

Loans and receivables (including trade receivables) are non-derivative financial assets with fixed or determinable payments that are not traded in an active market. Loans and receivables are reported on the balance sheet under “Receivables and other assets.” They are subsequently measured at amortized cost, using the effective interest method. Valuation allowances are provided for identifiable individual risks. If the loss of a certain part of the receivables is probable, valuation allowances are provided to cover the expected loss. Reversals of losses are recognized under “Other operating income.”

Non-derivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at amortized cost, using the effective interest method. Initial measurement takes place at fair value plus transaction costs. In subsequent periods, the amortization and accretion of any premium or discount is included in financial results.

Derivative Financial Instruments and Hedging Transactions Derivative financial instruments and separated embedded derivatives are measured at fair value as of the trade date at initial recognition and in subsequent periods. IAS 39 requires that they be categorized as held for trading as long as they are not a component of a hedge accounting relationship. Gains and losses from changes in fair value are immediately recognized in net income.

Instruments commonly used are foreign currency forwards and swaps, as well as interest-rate swaps and cross-currency swaps. Equity forwards are entered into to cover price risks on securities. In commodities, the instruments used include physically and financially settled forwards and options related to electricity, gas, coal, oil and emission rights. As part of conducting operations in commodities, derivatives are also acquired for proprietary trading purposes.

IAS 39 sets requirements for the designation and documentation of hedging relationships, the hedging strategy, as well as ongoing retrospective and prospective measurement of effectiveness in order to qualify for hedge accounting. The Company does not exclude any component of derivative gains and losses from the measurement of hedge effectiveness. Hedge accounting is considered to be appropriate if the assessment of hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80 to 125 percent effective at offsetting the change in fair value due to the hedged risk of the hedged item or transaction.

48 For qualifying fair value hedges, the change in the fair value of the derivative and the change in the fair value of the hedged item that is due to the hedged risk(s) are recognized in income. If a derivative instrument qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is recognized in equity (as a component of accumulated other comprehensive income) and reclassified into income in the period or periods during which the transaction being hedged affects income. The hedging result is reclassified into income immediately if it becomes probable that the hedged underlying transaction will no longer occur. For hedging instruments used to establish cash flow hedges, the change in fair value of the ineffective portion is recognized immediately in the income statement. To hedge the foreign currency risk arising from the Company’s net investment in foreign operations, derivative as well as non-derivative financial instruments are used. Gains or losses due to changes in fair value and from foreign currency translation are recognized separately within equity as currency translation adjustments.

Changes in fair value of derivative instruments that must be recognized in income are classified as other operating income or expenses. Gains and losses from interest-rate derivatives are netted for each contract and included in interest income. Gains and losses from derivative proprietary trading instruments are shown net as either revenues or cost of materials. Certain realized amounts are, if related to the sale of products or services, also included in sales or cost of materials.

Unrealized gains and losses resulting from the initial measurement of derivative financial instruments at the inception of the contract are not recognized in income. They are instead deferred and recognized in income systematically over the term of the derivative. An exception to the accrual principle applies if unrealized gains and losses from the initial measurement are verified by quoted market prices, observable prices of other current market transactions or other observable data supporting the valuation technique. In this case the gains and losses are recognized in income.

See Note 30 of the Notes to Consolidated Financial Statements for additional information regarding the Company’s use of derivative instruments.

The use of valuation models requires E.ON to make assumptions and estimates regarding the volatility of derivative contracts at the balance sheet date, and actual results could differ significantly due to fluctuations in value-influencing market data. The valuation models for the interest rate and currency derivatives are based on calculations and valuations, generally using a Group-wide financial management system that provides consistent market data and valuation algorithms throughout the Company. The algorithms used to obtain valuations are those which are commonly used in the financial markets. In certain cases the calculated fair value of derivatives is compared with results which are produced by other market participants, including banks, as well as those available through other internally available systems. The valuations of commodity instruments are delivered by multiple use EDP-based systems in the market units, which also utilize common valuation techniques and models as described above.

Certain electricity contracts that E.ON has entered into in the ordinary course of business meet all of the required criteria for a derivative as defined in IAS 39, and are marked to market. However, due to the own use exemption some of these contracts are not accounted for as derivatives under IAS 39 and therefore are not being marked to market. As a result, any price volatility inherent in these contracts prior to delivery is generally not reflected in the operating results of E.ON. If this exemption is disallowed or amended through future interpretations or actions of the International Accounting Standards Board (“IASB”), the impact on future results could be significant.

The same applies to gas contracts. The market units enter into gas purchase and sale contracts in connection with their distribution, sale and retail activities, as well as long-term gas purchase contracts for E.ON Ruhrgas’ gas supplies and for certain subsidiaries of E.ON Energie, E.ON Sverige and the operation of E.ON UK’s generation plants. Contracts providing for physical delivery in some countries are currently accounted for as contracts outside the scope of IAS 39, as no functioning natural gas market mechanism or spot market exists in

49 these countries which would allow the Company to net settle the contracts. In the future, it is possible that a functioning market mechanism or spot market for natural gas could emerge, resulting in a need to reassess the contracts in these countries for derivatives under IAS 39. If any such reassessment resulted in contracts being accounted for as derivatives under IAS 39, the impact on future results could be significant.

IFRS 7, “Financial Instruments: Disclosures” (“IFRS 7”), became effective in the 2007 fiscal year. The new standard requires both quantitative and qualitative disclosures about the extent of risks arising from financial instruments (e.g., credit, liquidity and market risks). The required information is presented in the Notes to Consolidated Financial Statements.

Provisions for Pensions and Similar Obligations The valuation of defined benefit obligations in accordance with IAS 19, “Employee Benefits” (“IAS 19”), is based on actuarial computations using the projected unit credit method, with actuarial valuations performed at year-end. The valuation encompasses both pension obligations and pension entitlements that are known on the balance sheet date as well as economic trend assumptions made in order to reflect realistic expectations.

Actuarial gains and losses that may arise from differences between the estimated and actual number of beneficiaries and from the underlying assumptions are recognized in full in the period in which they occur. Such gains and losses are not reported within the Consolidated Statements of Income but rather are recognized within the Statements of Recognized Income and Expenses (which are included in the consolidated financial statements) as part of equity.

The service cost representing the additional benefits that employees earned under the benefit plan during the fiscal year is reported under personnel expenses; interest expenses and expected return on plan assets are reported under financial results.

Unrecognized past service cost is recognized immediately to the extent that the benefits are already vested or is amortized on a straight-line basis over the average period until the benefits become vested.

The amount reported in the balance sheet represents the present value of the defined benefit obligation adjusted for unrecognized past service cost and reduced by the fair value of plan assets. If a net asset position arises from this calculation, the amount is limited to the unrecognized past service cost plus the present value of available refunds and reductions in future contributions.

Payments for defined contribution pension plans are expensed as incurred and reported under personnel costs. Contributions to government pension plans are treated like payments for defined contribution pension plans to the extent that the Group’s obligations under these pension plans correspond to those under defined contribution pension plans.

Provisions for Asset Retirement Obligations and Other Provisions In accordance with IAS 37, provisions are recognized when E.ON has a legal or constructive present obligation towards third parties as a result of a past event, it is probable that E.ON will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation. The provision is recognized at the expected settlement amount. Long-term obligations are reported as liabilities at the present value of their expected settlement amounts if the interest rate effect (the difference between present value and repayment amount) resulting from discounting is material; future cost increases that are foreseeable and likely to occur on the balance sheet date must also be included in the measurement. Long-term obligations are discounted at the market interest rate applicable as of the respective balance sheet date. The accretion amounts and the effects of changes in interest rates are generally presented as part of financial results. A reimbursement related to the provision that is virtually certain to be collected is capitalized as a separate asset. No offsetting within provisions is permitted. Advance payments remitted are deducted from the provisions.

50 Obligations arising from the decommissioning and restoration of property, plant and equipment are recognized during the period of their occurrence at their discounted settlement amounts, provided that the obligation can be reliably estimated. The carrying amounts of the respective property, plant and equipment are increased by the same amounts. In subsequent periods, capitalized asset retirement costs are amortized over the expected remaining useful lives of the assets, and the provision is accreted to its present value on an annual basis.

Changes in estimates arise in particular from deviations from original cost estimates, from changes to the maturity or the scope of the relevant obligation, and also as a result of the regular adjustment of the discount rate to current market interest rates. The adjustment of provisions for the decommissioning and restoration of property, plant and equipment for changes to estimates is generally recognized by way of a corresponding adjustment to assets, with no effect on income. If the property, plant and equipment to be decommissioned have already been fully depreciated, changes to estimates are recognized within the income statement.

Contingent liabilities are potential or present obligations toward third parties in which an outflow of resources embodying economic benefits is not probable or where the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are generally not recognized on the balance sheet.

No provisions are established for contingent asset retirement obligations where the type, scope, timing and associated probabilities cannot be determined reliably.

Operators of nuclear power plants are required under German nuclear law to establish sufficient financial provisions for obligations that arise from the use of nuclear power. In accordance with IAS 37 and IFRIC 1, these provisions include: (1) provisions for management of non-contractual obligations based on experts’ opinions and estimates, and (2) provisions for contractual obligations based on concluded contracts. All nuclear provisions include expenses for management of spent nuclear fuel rods, disposal of contaminated operating waste and the decommissioning of nuclear plants. At year-end 2007, E.ON Energie had provisions in its consolidated accounts for these purposes equal to €8.9 billion for management of non-contractual obligations and €3.3 billion for contractual obligations.

Under Swedish law, E.ON Sverige is required to pay fees to the country’s national fund for nuclear waste management. Each year, the Swedish Nuclear Power Inspectorate calculates the fees for the disposal of high- level radioactive waste and nuclear power plant decommissioning based on the amount of electricity produced at the particular nuclear power plant. The proposed fees are then submitted to government offices for approval. Upon approval, E.ON Sverige makes the corresponding payments. In accordance with IFRIC 5, “Rights to Interests Arising from Decommissioning, Restoration and Environmental Funds” (“IFRIC 5”), payments into the Swedish national fund for nuclear waste management are offset by a right of reimbursement of asset retirement obligations, which is recognized as an asset under “Other assets.” In a departure from the policy applied in Germany, provisions for Sweden measured on the basis of the contributions to the fund are discounted at the real interest rate.

Management utilizes certain assumptions and estimates to calculate the fair value of the obligation for nuclear plant decommissioning and nuclear waste management. Any changes in the underlying data, the timing in the future that the corresponding costs will be incurred, as well as changes in regulatory requirements, may adversely affect the Company’s financial position and net income.

Income Taxes Under IAS 12, “Income Taxes” (“IAS 12”), deferred taxes are recognized on temporary differences arising between the carrying amounts of assets and liabilities on the balance sheet and their tax bases (balance sheet liability method). Deferred tax assets and liabilities are recognized for temporary differences that will result in taxable or deductible amounts when taxable income is calculated for future periods, unless those differences are the result of the initial recognition of an asset or liability in a transaction other than a business combination that,

51 at the time of the transaction, affects neither accounting nor taxable profit/loss. IAS 12 further requires that deferred tax assets be recognized for unused tax loss carryforwards and unused tax credits. Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and unused tax losses can be utilized. Each of the corporate entities is assessed individually with regard to the probability of a positive tax result in future years. Any existing history of losses is incorporated in this assessment. For those tax assets to which these assumptions do not apply, the value of the deferred tax assets has been reduced.

Deferred tax liabilities caused by temporary differences associated with investments in affiliated and associated companies are recognized unless the timing of the reversal of such temporary differences can be controlled within the Group and it is probable that, owing to this control, the differences will in fact not be reversed in the foreseeable future.

Deferred tax assets and liabilities are measured using the enacted or substantively enacted tax rates expected to be applicable for taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of changes in tax rates and tax law is generally recognized in income. Equity is adjusted for deferred taxes that had previously been recognized directly in equity. Following passage of the 2008 corporate tax reforms in Germany, deferred taxes for domestic companies were calculated using a total tax rate of 30 percent (2006: 39 percent). This tax rate includes, in addition to the 15 percent (2006: 25 percent) corporate income tax, the solidarity surcharge of 5.5 percent on the corporate tax rate, and the average trade tax rate of 14 percent (2006: 13 percent) applicable to the E.ON Group. Foreign subsidiaries use applicable national tax rates.

Note 10 of the Notes to Consolidated Financial Statements shows the major temporary differences so recorded.

E.ON has significant deferred tax assets and liabilities totaling €6,559 million and €12,959 million, respectively, as of December 31, 2007, which are expected to be realized through the statement of income over extended periods of time in the future. Based on the Company’s past performance and the expectations of similar performance in the future, it is expected that the future taxable income will more likely than not be sufficient to permit recognition of their deferred tax assets. As of December 31, 2007, changes in value have been established totaling €212 million for that portion of the deferred tax assets for which this criterion is not expected to be met.

New Accounting Pronouncements The IASB issued the following accounting pronouncements in 2006, 2007 and 2008, which became applicable or will become applicable to E.ON in 2007, 2008 and 2009: • IFRS 3, Business Combinations; • IAS 1, Presentation of Financial Statements; • IAS 23, Borrowing Costs; • IAS 27, Consolidated and Separate Financial Statements; • Amendment to IAS 32, Financial Instruments: Presentation and IAS 1 Presentation of Financial Instruments; • IFRIC 11, IFRS 2 — Group and Treasury Share Transactions; • IFRIC 12, Service Concession Arrangements; • IFRIC 13, Customer Loyalty Programmes; and • IFRIC 14, IAS 19 — The Limit on a Defined Benefit Asset Minimum Funding Requirements and their Interaction.

52 The application of some of these standards and interpretations is at the present time still subject to adoption by the EU, which has yet to occur. For details of these pronouncements and their impact or expected impact on the Company’s results, see Note 2 of the Notes to Consolidated Financial Statements.

Results Of Operations E.ON’s sales in 2007 increased 7.2 percent to €68,731 million from €64,091 million in 2006. The increase of €4,640 million was primarily attributable to increased sales at the Central Europe market unit. Net income increased by 27.0 percent to €7,724 million in 2007 from €6,082 million in 2006, primarily reflecting higher income from continuing operations partially offset by lower income from discontinued operations, as described in more detail below. Cash provided by operating activities increased 21.9 percent to €8,726 million in 2007 from €7,161 million in 2006, with the increase being primarily attributable to increases at the Pan-European Gas, U.K. and Nordic market units, which were offset in part by a decline in the cash generated by the Corporate Center and the U.S. Midwest market unit. In 2007, 53.7 percent of the Group’s total sales were to customers in Germany and 46.3 percent were to customers in other parts of the world, as compared with 54.5 percent and 45.5 percent in 2006, respectively. E.ON’s sales and earnings are influenced by a number of differing economic and other external factors. The energy business is generally not subject to severe fluctuations in its results, but is to some extent affected by seasonality in demand related to weather patterns. Typically, demand is higher for the Central Europe, Pan-European Gas and U.K. market units during the winter months and for the U.S. Midwest market unit during the summer. For a discussion of trends and factors affecting E.ON’s businesses, see the market unit descriptions in “Summary — Business Overview” and “Risk Factors.”

Year Ended December 31, 2007 Compared With Year Ended December 31, 2006 The following table sets forth sales and adjusted EBIT, which are presented in accordance with IFRS, for each of E.ON’s business segments for 2007 and 2006 (in each case excluding the results of discontinued operations): E.ON BUSINESS SEGMENT SALES AND ADJUSTED EBIT IFRS IFRS 2007 2006 Adjusted Adjusted Sales EBIT Sales EBIT (€ in millions) Central Europe ...... 32,029 4,670 27,197 4,235 Pan-European Gas ...... 22,745 2,576 22,947 2,347 U.K...... 12,584 1,136 12,518 1,239 Nordic(1) ...... 3,339 670 2,827 512 U.S. Midwest(1) ...... 1,819 388 1,930 426 Corporate Center(1)(2)(3) ...... (3,785) (232) (3,328) (403) Total ...... 68,731 9,208 64,091 8,356

(1) Excludes the sales and adjusted EBIT of certain activities now accounted for as discontinued operations. For more details, see “— Discontinued Operations” for this period below and Note 4 of the Notes to Consolidated Financial Statements. (2) Includes primarily the parent company and effects from consolidation (including the elimination of intersegment sales), as well as the results of its remaining telecommunications interests, as explained above. Sales between companies in the same market unit are eliminated in calculating sales on the market unit level. (3) Includes adjusted EBIT of Degussa prior to its disposal in 2006. For a reconciliation of adjusted EBIT to net income, see the discussion under “— E.ON Group” below.

53 E.ON Group E.ON’s sales in 2007 increased 7.2 percent to €68,731 million from €64,091 million in 2006. The increase of €4,640 million was primarily attributable to increased sales at the Central Europe market unit. As illustrated in the table above, the overall increase in the Group’s sales also reflected an increase in sales at the Nordic and U.K. market units, which more than offset decreases at the Pan-European Gas and U.S. Midwest market units and the Corporate Center.

Sales of the Central Europe market unit increased 17.8 percent in 2007 to €32,029 million from €27,197 million in 2006. Nordic’s sales increased by 18.1 percent to €3,339 million from €2,827 million in 2006. Sales of the U.K. market unit increased by 0.5 percent, amounting to €12,584 million in 2007, as compared to €12,518 million in 2006. Pan-European Gas’ sales decreased by 0.9 percent to €22,745 million in 2007 from €22,947 million in 2006. Sales of the U.S. Midwest market unit decreased by 5.8 percent in 2007 to €1,819 million compared with €1,930 million in 2006. The elimination of intersegment sales at the Corporate Center resulted in the segment reporting negative sales of €3,328 million in 2006 and negative sales of €3,785 million in 2007. The 2007 figure also reflected €252 million in sales of newly acquired companies (primarily OGK-4 and Airtricity). The sales of each of these segments are discussed in more detail below.

Changes in inventories amounted to €22 million in 2007 as compared with €8 million in 2006.

Own work capitalized increased by 30.9 percent or €122 million to €517 million in 2007, as compared with €395 million in 2006, mainly resulting from engineering services for new development projects. The increase reflected an increase of own work capitalized at the Nordic market unit, primarily due to work in progress in capital investment projects at the power distribution business at the Central Europe market unit mainly resulting from construction within the market unit and at the Pan-European Gas market unit.

Other operating income decreased by €138 million to €7,776 million in 2007 as compared to €7,914 million in 2006. This 1.7 percent decrease in other operating income was primarily attributable to a decrease in income from exchange rate differences (including realized gains on currency derivatives) and lower miscellaneous other operating income. These negative effects were partially offset by higher gains on derivative financial instruments and higher gains on the disposal of investments and securities, which in 2007 included the book gain from the sale of the stake in ONE. Under IFRS, we no longer net our gains and losses in respect of derivatives and exchange rate differences, but rather report them separately as components of other operating income and other operating expense, respectively.

Cost of materials increased by €3,515 million from €46,708 million in 2006 to €50,223 million in 2007. This 7.5 percent increase was mainly attributable to an increase at the Central Europe market unit, reflecting increased expenses for Central Europe’s network that primarily resulted from increased deliveries onto Central Europe’s network of electricity pursuant to Germany’s Renewable Energy Law.

Personnel expenses increased by €68 million from €4,529 million in 2006 to €4,597 million in 2007. This 1.5 percent increase was attributable to an increase at the UK market unit, reflecting an increase in headcount, primarily in the retail business. This effect was partially offset by lower personnel expenses at the Central Europe market unit, primarily as a result of a decrease in provisions for early retirement programs.

Depreciation, amortization and impairment charges amounted to €3,194 million in 2007 as compared with €3,670 million in 2006. This 13.0 percent or €476 million decrease reflected decreases at the UK market unit and at the Central Europe market unit, as well as at the Nordic market unit, in each case resulting from the fact that impairment charges which had been taken in 2006 did not recur in 2007. These effects were partially offset by an increase in scheduled depreciation, as depreciation at the Corporate Center increased by €37 million from €14 million in 2006 to €51 million in 2007 due to the newly consolidated activities, primarily OGK-4, E2-I and Airtricity.

54 Other operating expenses decreased by 18.3 percent or €2,183 million to €9,724 million in 2007 as compared to €11,907 million in 2006. The change in this line item was primarily attributable to lower losses on derivative financial instruments, which generated expenses of €1,331 million in 2007, compared to expenses of €3,052 million in 2006, primarily reflecting a change in the market value of derivatives at the U.K., Pan-European Gas and Nordic market units. Losses from exchange rate differences amounted to €3,218 million in 2007, compared to €4,447 million in 2006. Miscellaneous other operating expenses increased from €4,093 million in 2006 to €4,821 million in 2007, primarily reflecting an increase in costs for external audit and non-audit services and consulting from €263 million in 2006 to €414 million in 2007, as well as costs of €288 million related to the proposed Endesa acquisition.

Income/Loss from companies accounted for under the equity method amounted to €1,147 million in 2007, compared with €748 million in 2006. This 53.3 percent or €399 million increase was primarily attributable to higher income from companies accounted for under the equity method at the Pan-European Gas market unit.

As a result of the factors described above, income (loss) from continuing operations before financial results and income taxes increased by 64.9 percent or €4,113 million to €10,455 million in 2007, as compared with €6,342 million in 2006.

Financial results were negative €995 million in 2006 and negative €772 million in 2007. The improvement resulted from lower interest and similar expenses and higher income from other equity investments mainly due to lower impairments of other share investments at the Pan-European Gas market unit. These positive effects were partially offset by a decrease in income from other securities, interest and similar income, primarily reflecting lower interest income from loans and receivables. For additional information, see Note 9 of the Notes to Consolidated Financial Statements.

In 2007, E.ON recorded an income tax expense of €2,289 million, as compared to a tax expense of €40 million in 2006. This significant change was primarily attributable to the increase in earnings, as well as the fact that the 2006 results had benefited from certain special tax effects. For additional information, see Note 10 of the Notes to Consolidated Financial Statements.

Results from discontinued operations increased net income by €330 million in 2007, as compared to a contribution to net income of €775 million in 2006. The significant decrease primarily reflected the fact that the 2006 results included a significant gain on the disposal of Degussa, as well as the significant decrease at the U.S. Midwest market unit reflecting the results of WKE, which had generated income of €64 million in 2006 and a loss of €81 million in 2007. For details, see Note 4 of the Notes to Consolidated Financial Statements. The Group’s net income increased 27.0 percent, totaling €7,724 million in 2007, compared with €6,082 million in 2006. Excluding the results of discontinued operations, E.ON would have recorded net income of €7,394 million in 2007, as compared to net income of €5,307 million in 2006.

Reconciliation of Adjusted EBIT. As noted above, E.ON uses adjusted EBIT as its segment reporting measure in accordance with IFRS 8. On a consolidated Group basis, adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable GAAP measure. A reconciliation of Group adjusted EBIT to net income for each of 2007 and 2006 appears in the table below. The following paragraphs discuss changes in the principal components of each of the reconciling items to income (loss) from continuing operations before income taxes and minority interests. For additional details, see Note 33 of the Notes to Consolidated Financial Statements.

55 IFRS IFRS 2007 2006 (€ in millions) Adjusted EBIT ...... 9,208 8,356 Adjusted interest income, net ...... (960) (948) Net book gains ...... 1,345 829 Cost-management and restructuring expenses ...... (77) — Other non-operating results ...... 167 (2,890) Income/(loss) from continuing operations before income taxes ...... 9,683 5,347 Income taxes ...... (2,289) (40) Income/(loss) from continuing operations ...... 7,394 5,307 Income/(loss) from discontinued operations ...... 330 775 Net income ...... 7,724 6,082

On a consolidated Group basis, adjusted EBIT increased by 10.2 percent to €9,208 million in 2007, as compared with €8,356 million in 2006.

As detailed in the table below, adjusted interest income, net, amounted to an expense of €960 million in 2007 as compared to an expense of €948 million in 2006. Non-operating interest income, net, amounted to income of €9 million in 2007 as compared with an expense of €97 million in 2006. In both 2006 and 2007, such non-operating interest income primarily reflected lower expenses for liabilities related to put options (primarily at the Corporate Center), as well as higher interest income related to derivatives at the Central Europe market unit. In 2006, non-operating interest income primarily reflected higher interest charges related to derivatives in the U.K. market unit that were partially offset by higher interest income at the Central Europe market unit and the Corporate Center.

IFRS IFRS 2007 2006 (€ in millions) Interest income and similar expenses (net) as shown in Note 9 of the Notes to Consolidated Financial Statements ...... (951) (1,045) (+) Non-operating interest income, net(1) ...... (9) 97 Adjusted interest income, net ...... (960) (948)

(1) This net figure is calculated by adding in non-operating interest expense and subtracting non-operating interest income.

Net book gains as used in the reconciliation of adjusted EBIT were €516 million higher than in 2006, increasing from €829 million in 2006 to €1,345 million in 2007. In both 2006 and 2007, such net book gains primarily resulted from the sale of interests in funds invested in securities held by the Central Europe market unit.

Cost-management and restructuring expenses amounted to €77 million, whereas such expenses did not occur in 2006. These expenses related to the retail operations of the U.K. market unit, as well as to the implementation of the new internal market unit structure.

The amount reported as other non-operating results amounted to income of €167 million in 2007, as compared to an expense of €2,890 million in 2006. The significant change in this figure over the period under review was primarily attributable to contrasting results from the required marking to market of derivatives (primarily at the U.K. and Pan-European Gas market units). In 2007, such marking to market resulted in our recording income of €564 million, while in 2006 it had resulted in an expense of €1,946 million. The improvement in the overall figure was partially offset by costs incurred for the planned acquisition of Endesa and the storm in Sweden in January 2007. In addition, the 2006 result reflected a total of €665 million in impairment

56 charges (whereas the comparable figure for 2007 was income of €99 million). Following the BNetzA’s reduction of allowable network charges, E.ON conducted impairment tests on E.ON’s network assets and shareholdings in municipal distribution network operators in 2006. As a result, E.ON recorded impairment charges totaling €374 million in its gas distribution businesses. Of this total, €266 million related to the Central Europe market unit. The remaining impairment loss of €108 million was recorded on other shareholdings at the Pan-European Gas market unit. Impairment tests on E.ON Energie’s electricity transmission and distribution networks did not lead to any impairment losses. Further impairments in 2006 related to gas storage and CHP generation assets at the U.K. market unit, as well as tangible assets at the Pan-European Gas and Nordic market units. The impact of these impairments was partially offset by effects from the first-time consolidation of VKE at the Central Europe market unit, which add up to €83 million.

Central Europe For financial reporting purposes, the Central Europe market unit comprises four business units: Central Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power also includes the results of E.ON Benelux, which operates power generation, district heating and gas and electricity retail businesses in the Netherlands. The Central Europe West Gas business unit reflects the results of the regional distribution of gas and the gas retail business in Germany. The Central Europe East business unit primarily includes the results of the regional distribution companies in Bulgaria, the Czech Republic, Hungary, Romania and Slovakia (with the Slovak activities being valued under the equity method given E.ON Energie’s minority interest). Other/Consolidation primarily includes the results of E.ON Energie’s business in Italy, other national and international shareholdings, service companies and E.ON Energie AG, as well as intrasegment consolidation effects.

Total sales of the Central Europe market unit increased by 17.8 percent to €32,029 million (including €679 million in intersegment sales) in 2007, compared with a total of €27,197 million (including €813 million in intersegment sales) in 2006. The overall increase of €4,832 million reflected higher sales at each of Central Europe’s business units except for the Central Europe West Gas business unit, as described in more detail below.

The following table sets forth the sales of each business unit in the Central Europe market unit in each of the last two years: SALES OF CENTRAL EUROPE MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Central Europe West Power ...... 23,293 18,829 +23.7 Central Europe West Gas ...... 3,676 4,368 -15.8 Central Europe East ...... 4,087 3,469 +17.8 Other/Consolidation ...... 973 531 +83.2 Total ...... 32,029 27,197 +17.8

Sales of the Central Europe West Power business unit increased by €4,464 million or 23.7 percent from €18,829 million in 2006 to €23,293 million in 2007. The most significant factor in the overall increase was a greater contribution to the product mix of sales of electricity produced from renewable resources, as the volume of such energy, which E.ON Energie is required to purchase and resell under regulatory requirements, generally bearing significantly higher prices, increased in 2007. Higher electricity prices resulting from the global rise in raw material and energy prices, as well as an increase in the volume of electricity sold as part of our non-proprietary trading activities also contributed to the increase in sales.

57 Sales of the Central Europe West Gas business unit decreased by 15.8 percent from €4,368 million in 2006 to €3,676 million in 2007, with the decrease of €692 million reflecting lower volumes resulting from unseasonably warm winter weather across many parts of Europe, as well as lower sales prices.

Sales of the Central Europe East business unit increased by 17.8 percent or €618 million, from €3,469 million in 2006 to €4,087 million in 2007, with the increase being primarily due to higher sales in Hungary reflecting increased prices and an increase in trading revenues. The result also reflected a positive translation effect between the unit’s operating currencies and the euro and from the first-time inclusion of a full year of sales from one electricity and one gas company in the Czech Republic which were consolidated as of September 2006, as well as the first-time inclusion of one Hungarian power company in 2007.

Sales of the Other/Consolidation business unit almost doubled, increasing by €442 million to €973 million in 2007, with the increase being primarily attributable to the full-year inclusion of sales from Dalmine in 2007.

Total power procured by the Central Europe market unit (excluding physically-settled trading activities) rose 16.4 percent to 327.2 billion kWh in 2007, compared with 281.2 billion kWh in 2006. The increase was primarily attributable to an increase in power procured from third parties. E.ON Energie’s own production of power rose 2.5 percent from 131.3 billion kWh in 2006 to 134.6 billion kWh in 2007. E.ON Energie produced approximately 41 percent of its power requirements in 2007, compared with approximately 47 percent in 2006. Compared with 2006, purchases of electricity from third parties increased by 33.9 percent, from 137.6 billion kWh in 2006 to 184.3 billion kWh in 2007, including the purchase of significantly higher volumes (approximately 15 TWh) of electricity generated from renewable resources pursuant to Germany’s Renewable Energy Law. Electricity purchased from jointly operated power stations decreased by 32.4 percent from 12.3 billion kWh in 2006 to 8.3 billion kWh in 2007, primarily as a result of continuing outages at jointly owned nuclear power stations Krümmel and Brunsbüttel, both of which are operated by Vattenfall.

In 2007, the Central Europe market unit contributed adjusted EBIT of €4,670 million, a 10.3 percent increase from a total of €4,235 million in 2006. The following table sets forth the adjusted EBIT of each business unit in the Central Europe market unit in each of the last two years: ADJUSTED EBIT OF CENTRAL EUROPE MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Central Europe West Power ...... 4,145 3,636 +14.0 Central Europe West Gas ...... 200 270 -25.9 Central Europe East ...... 361 266 +35.7 Other/Consolidation ...... (36) 63 — Total ...... 4,670 4,235 +10.3

Adjusted EBIT at the Central Europe West Power business unit increased by €509 million from €3,636 million in 2006 to €4,145 million in 2007. This 14.0 percent increase was primarily attributable to higher wholesale electricity prices which could be passed on to customers, and to the revaluation of nuclear provisions, mainly due to a decision to calculate them on the basis of a significant component of internal financing. Additionally, the 2006 result reflected certain negative effects recorded in the prior-year period that did not recur in 2007. These positive effects were partially offset by higher electricity procurement costs, provisions for obligations in the grid business, higher expenditures resulting in particular from an increase in the amount of renewable-source electricity delivered onto the network and lower results from network activities. Adjusted EBIT was also negatively affected by the fact that the 2006 results reflected €220 million in income mainly from the sale of equity interests and from the release of provisions. The outages at the German power plants Krümmel and Brunsbüttel and higher costs for maintenance and information technology also reduced overall adjusted EBIT. Higher group internal cost allocation and the first-time inclusion of results from a start-up retail company also burdened the results.

58 Adjusted EBIT of the Central Europe West Gas business unit decreased by 25.9 percent to €200 million in 2007, compared with €270 million in 2006. The lower result was primarily due to the unusually warm winter, which resulted in a decrease in gas sales volumes.

The Central Europe East business unit contributed adjusted EBIT of €361 million in 2007, a 35.7 percent increase from €266 million in 2006, largely reflecting higher gross margins in Hungary and Romania, higher results from equity-accounted investees in the Czech Republic as well as in Slovakia, the inclusion of a full year of earnings from two companies in the Czech Republic (JCP and Teplárna Otrokovice) and translation effects. These positive effects were partly offset by weather related lower sales volumes in the Czech Republic and by higher procurement costs in Bulgaria.

Central Europe’s Other/Consolidation business unit recorded adjusted EBIT of negative €36 million in 2007, compared with an adjusted EBIT of €63 million in 2006. This negative change primarily resulted from higher personnel costs, the impairment of available-for-sale securities reflecting market price declines, higher audit and consultancy fees, lower results from the sale of securities, lower results from realized hedging transactions and foreign currency loans, higher depreciation costs, and the fact that the prior-year results had included the release of provisions.

Pan-European Gas For financial reporting purposes, the Pan-European Gas market unit is divided into three business units: Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects the results of the supply, transmission system, storage and sales businesses, with the midstream operations essentially including all of the supply and sales business other than exploration and production activities. The Downstream Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes consolidation effects.

Total sales of the Pan-European Gas market unit decreased by 0.9 percent to €22,745 million (including €3,031 million in intersegment sales) in 2007, compared with a total of €22,947 million (including €2,392 million in intersegment sales) in 2006. The negative impact of the trends in energy prices and severe competition in the midstream business was not completely offset by the positive effect resulting from the first- time full-year inclusion of the E.ON Földgaz companies.

The following table sets forth the sales of each business unit in the Pan-European Gas market unit in each of the last two years: SALES OF PAN-EUROPEAN GAS MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Up-/Midstream ...... 17,738 18,889 -6.1 Downstream ...... 5,625 4,773 +17.9 Other/Consolidation ...... (618) (715) +13.6 Total ...... 22,745 22,947 -0.9

Sales in the Up-/Midstream business unit decreased in 2007 by €1,151 million or 6.1 percent from €18,889 million to €17,738 million. Sales volumes were relatively unchanged, increasing from 710 billion kWh to 713 billion kWh. The impact of the slight increase in volumes was more than offset by the fact that trends in the various energy prices to which supply costs and sales prices are linked differed over the course of the year, and lower sales prices due to the severe competition in the midstream business. In the upstream business, sales decreased by €26 million, in particular as a result of lower sales prices at E.ON Ruhrgas North Sea and E.ON Ruhrgas UK.

59 In the Downstream Shareholdings business unit, sales increased by €852 million or 17.9 percent to €5,625 million in 2007 compared with €4,773 million in 2006. The main reason for the change was an increase in sales in ERI’s downstream operations, particularly the impact of the first-time inclusion of a full year of results from E.ON Földgaz Trade and E.ON Földgaz Storage following their consolidation as of April 2006. These positive effects were partially offset by a decrease in sales of €238 million at the other ERI companies mainly attributable to warmer weather and a €28 million decrease at Thüga’s downstream operations. The decline in Thüga’s sales primarily derived from lower volumes of gas and electricity sold, mainly due to the warm weather. Rising gas and electricity prices and the positive impact of changes in the basis of consolidation at Thüga Italia could not offset this negative impact.

The total volume of gas sold by E.ON Ruhrgas’ midstream operations increased by 0.4 percent to 712.8 billion kWh in 2007 from 709.7 billion kWh in 2006. Sales to domestic distributors decreased by 8.2 percent from 318.7 billion kWh to 292.5 billion kWh. Sales to domestic municipal utilities increased by 4.1 percent from 163.1 billion kWh to 169.8 billion kWh. E.ON Ruhrgas sold 70.1 billion kWh of gas to domestic industrial customers, an increase of 3.7 percent from 67.6 billion kWh in 2006. Exports reached 180.4 billion kWh in 2007, a 12.5 percent increase from 160.3 billion kWh in 2006. The higher sales volumes were mainly attributable to an approximately 19 percent increase in the UK; in addition sales volumes in Denmark increased strongly in 2007 due to a new contract signed at the beginning of the year. E.ON Ruhrgas purchased approximately 81.8 percent of its gas supplies from outside Germany and approximately 18.2 percent from German producers in 2007, compared with 84.4 percent and 15.6 percent, respectively, in 2006. In the Downstream Shareholdings business unit, total gas sales volumes rose by 11.9 percent from 175.1 billion kWh in 2006 to 197.5 billion kWh in 2007. ERI increased its sales volumes by 16.8 percent to 177.6 billion kWh from 152.0 billion kWh, primarily due to the first time full-year inclusion of the E.ON Földgaz companies. Sales volumes at Thüga decreased by 13.8 percent to 19.9 billion kWh from 23.1 billion kWh in 2006, largely due to unfavorable weather conditions.

Adjusted EBIT of the Pan-European Gas market unit increased by 9.8 percent to €2,576 million in 2007 from €2,347 million in 2006. The rise in adjusted EBIT reflected very positive results in the Downstream Shareholdings business unit, which were only partly offset by lower results in the Up-/Midstream business unit, as described in more detail below.

The following table sets forth the adjusted EBIT of each business unit in the Pan-European Gas market unit in each of the last two years:

ADJUSTED EBIT OF PAN-EUROPEAN GAS MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Up-/Midstream ...... 1,581 1,905 -17.0 Downstream Shareholdings ...... 987 453 +117.9 Other/Consolidation ...... 8 (11) — Total ...... 2,576 2,347 +9.8

Adjusted EBIT in the Up-/Midstream business unit decreased by €324 million or 17.0 percent from €1,905 million in 2006 to €1,581 million in 2007. The €89 million decrease in adjusted EBIT at the upstream activities primarily reflected lower sales prices at E.ON Ruhrgas UK and E.ON Ruhrgas North Sea, an increase in impairments relating to exploration activities in the German and the British North Sea and higher operating and depreciation costs due to the start of production at new fields. Adjusted EBIT in the midstream activities decreased by €235 million, primarily as a consequence of a decline in gross margin. The decline in gross margin was related to short-term, asset-based trading activities; proprietary trading transactions; a decline in earnings attributable to the storage valuation (for which the development of gas prices is the underlying driver); and other price effects as a consequence of strong competition. The impact of these factors on gross margin was mitigated

60 by the fact that the time lag effect resulting from the fact that procurement prices are adjusted more rapidly than sales prices had a greater negative impact on adjusted EBIT in 2006. These negative effects were partially offset by higher income from minority shareholdings, especially that in Gazprom.

In the Downstream Shareholdings business unit, adjusted EBIT increased by €534 million, more than doubling to €987 million in 2007 from €453 million in 2006. The increase in adjusted EBIT was primarily attributable to higher earnings at the E.ON Földgaz companies, which were included for the entire year for the first time and which benefited from a tariff adjustment designed to compensate for lower realized earnings in prior years, as well as to the fact that prior year results had included €188 million in partial impairments of certain minority Thüga shareholdings resulting from the introduction of new regulation of network charges in Germany. Furthermore, book gains on the sale of shareholdings at Thüga Germany and the reduction of the rate applicable to deferred taxes as a consequence of the German corporate tax reform also served to increase adjusted EBIT.

U.K. Total sales of the U.K. market unit in 2007 increased by 0.5 percent to €12,584 million (including €129 million in intersegment sales) from €12,518 million (including €163 million in intersegment sales) in 2006, primarily as a result of increased sales in the Non-regulated Business, as explained in more detail below.

The following table sets forth the sales of each business unit in the U.K. market unit in each of the last two years: SALES OF U.K. MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Non-regulated Business ...... 12,126 12,031 +0.8 Regulated Business ...... 888 858 +3.5 Other/Consolidation ...... (430) (371) -15.9 Total ...... 12,584 12,518 +0.5

Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and trading), retail and the energy services businesses in the U.K., increased by €95 million from €12,031 million in 2006 to €12,126 million in 2007. This 0.8 percent increase was primarily attributable to higher average (retail) prices and higher sales volumes in the energy wholesale business in 2007, which were largely offset by lower sales volumes in the retail business due to warmer weather, consumer behavior and lower customer numbers.

Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, increased to €888 million in 2007 from €858 million in 2006. The sales increase of €30 million, or 3.5 percent, was principally attributable to tariff changes.

Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of intrasegment sales and had a negative impact on sales of €430 million in 2007, as compared to a negative impact of €371 million in 2006.

The volume of electricity sold by the U.K. market unit increased by 4.1 billion kWh or 5.6 percent to 77.8 billion kWh, as compared with 73.7 billion kWh in 2006. Market sales associated with trading operations increased by 7.8 billion kWh or 44.6 percent to 25.3 billion kWh, while mass market sales decreased by 3.7 billion kWh or 9.8 percent to 34.2 billion kWh due to lower customer numbers and warmer weather. Sales to industrial and commercial customers remained stable at 18.4 billion kWh. The increase in sales was reflected in

61 the volume of own production and power purchased from power stations in which E.ON UK has an interest of 50 percent or less. Own production increased by 5.3 billion kWh or 15.0 percent from 35.9 billion kWh in 2006 to 41.2 billion kWh in 2007, primarily due to improved plant availability and a reduction in wholesales gas prices which made generation more economically attractive than buying power. Power purchased from power stations in which E.ON UK has an interest of 50 percent or less increased by 0.5 billion kWh or 69.5 percent to 1.2 billion kWh from 0.7 billion kWh. The volume of power purchased from other suppliers decreased by 2.6 billion kWh or 6.9 percent, reflecting the significant increase in own production. Gas sales increased by 12.4 billion kWh or 6.4 percent from 194.0 billion kWh in 2006 to 206.4 billion kWh in 2007, with the increase reflecting higher market sales (15.4 billion kWh) and an increase in gas used for the market unit’s own generation (10.7 billion kWh), offset in part by lower sales to retail mass market customers (8.4 billion kWh) and lower sales to industrial and commercial customers (5.3 billion kWh). E.ON UK satisfied its increased need for gas through an increase of 16.1 billion kWh or 10.7 percent in market purchases, while the volume of gas being sourced under long-term gas supply contracts decreased by 3.7 billion kWh or 8.7 percent from 42.9 billion kWh in 2006 to 39.2 billion kWh in 2007.

Adjusted EBIT at the U.K. market unit decreased by €103 million or 8.3 percent from €1,239 million in 2006 to €1,136 million in 2007, reflecting a decrease at each of the Non-regulated Business and Other/ Consolidation, partially offset by higher results at the Regulated Business, as described in more detail below.

The following table sets forth the adjusted EBIT of each business unit in the U.K. market unit in each of the last two years: ADJUSTED EBIT OF U.K. MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Non-regulated Business ...... 762 851 -10.5 Regulated Business ...... 509 488 +4.3 Other/Consolidation ...... (135) (100) -35.0 Total ...... 1,136 1,239 -8.3

The Non-regulated Business contributed adjusted EBIT of €762 million in 2007. This €89 million or 10.5 percent decrease from €851 million in 2006 mainly resulted from the combination of lower retail sales volumes due to warmer weather and lower customer numbers, as well as lower retail margins (mainly due to the price reductions in February 2007 combined with higher energy transportation and distribution costs). These negative factors were partially offset by the fact that the 2006 results had included high gas input costs during the first quarter of 2006 caused by gas supply issues and cold weather, and that 2007 was marked by increased margins from the gas power stations and improved station availability.

The Regulated Business increased its adjusted EBIT from €488 million in 2006 to €509 million in 2007. The 4.3 percent or €21 million increase was mainly attributable to tariff changes.

The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative due to the combination of intercompany eliminations and costs of the E.ON UK corporate center, was negative €135 million in 2007, as compared with negative €100 million in 2006. The change was primarily attributable to higher administrative costs, in part due to the transfer of certain activities to the corporate center from the business units.

62 Nordic Total sales of the Nordic market unit increased by €512 million or 18.1 percent from €2,827 million (including €87 million in intersegment sales) to €3,339 million (including €123 million in intersegment sales) in 2007. Sales increased in both the Non-regulated Business and Regulated Business units, but were partially offset by a greater negative effect in Other/Consolidation, as described in more detail below.

The following table sets forth the sales of each business unit in the Nordic market unit in each of the last two years, in each case excluding electricity and natural gas taxes: SALES OF NORDIC MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Non-regulated Business ...... 2,895 2,298 +26.0 Regulated Business ...... 729 725 +0.6 Other/Consolidation ...... (285) (196) -45.4 Total ...... 3,339 2,827 +18.1

Sales in the Non-regulated Business unit, which includes power generation, retail, trading, heat and waste and services operations, increased by €597 million or 26.0 percent from €2,298 million to €2,895 million, driven by higher electricity volumes sold to Nord Pool and higher realized wholesale prices achieved on the hedged portfolio. These positive effects were partially offset by a decrease in retail sales, volumes and prices, reflecting continuing strong competition in the Nordic market.

Sales in the Regulated Business unit, which includes electricity distribution, as well as gas transmission, distribution and storage, increased from €725 million to €729 million. This €4 million or 0.6 percent increase was mainly attributable to higher tariffs for electricity distribution.

Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of intrasegment sales and had a negative impact on sales of €285 million in 2007, as compared to a negative impact of €196 million in 2006.

Total power supplied by E.ON Nordic (excluding physically settled trading activities) increased by 7.0 percent to 43.4 billion kWh in 2007, compared with 40.6 billion kWh in 2006. The increase of 2.8 billion kWh reflected an increase in the volume of power sold to sales partners/Nord Pool by 19.7 percent from 21.1 billion kWh in 2006 to 25.3 billion kWh in 2007, primarily reflecting higher hydroelectric production due to the better than average hydrological balance. Sales to residential customers decreased by 0.5 billion kWh or 7.6 percent from 6.6 billion kWh in 2006 to 6.1 billion kWh in 2007. Sales to commercial customers decreased by 6.4 percent to 12.0 billion kWh in 2007 compared with 12.8 billion kWh in 2006. These effects primarily resulted from unseasonably warm weather in the first half of 2007. E.ON Nordic’s own production increased by 8.1 percent from 27.9 billion kWh in 2006 to 30.2 billion kWh in 2007, mainly as a result of higher hydroelectric generation (2.9 billion kWh) due to higher water reservoir inflow in the beginning of 2007, which was partly offset by lower nuclear generation (0.3 billion kWh). E.ON Nordic purchased 0.8 billion kWh more power from outside sources, mainly from E.ON Sales & Trading. Purchases from jointly owned power stations decreased by 0.3 billion kWh due to lower volumes procured from Ringhals. The total volume of gas sold to third parties decreased in 2007 to 6.9 billion kWh from 7.6 billion kWh in 2006, reflecting lower sales to business customers due to the milder weather in the beginning of 2007.

63 Adjusted EBIT at the Nordic market unit increased by €158 million or 30.9 percent, from €512 million to €670 million, primarily reflecting market developments at the Non-regulated Business unit, while the adjusted EBIT at the Regulated Business unit showed a slightly positive development, as described in more detail below.

The following table sets forth the adjusted EBIT of each business unit in the Nordic market unit in each of the last two years: ADJUSTED EBIT OF NORDIC MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Non-regulated Business ...... 488 342 +42.7 Regulated Business ...... 220 200 +10.0 Other/Consolidation ...... (38) (30) -26.7 Total ...... 670 512 +30.9

Adjusted EBIT in the Non-regulated Business unit increased by €146 million from €342 million in 2006 to €488 million in 2007. This 42.7 percent increase primarily reflected the successful hedging of the production portfolio and the favorable hydrological balance, which led to an increase in hydroelectric production with the business benefitting from both higher wholesale prices and an increase in volumes. These positive effects were partly offset by an increase in the estimated costs of nuclear decommissioning in 2007.

In the Regulated Business, adjusted EBIT increased by €20 million from €200 million in 2006 to €220 million in 2007. This 10.0 percent increase mainly resulted from the positive developments within electricity distribution, where the Nordic market unit was able to introduce higher network tariffs mainly reflecting the higher costs for procuring electricity to cover power losses. Despite the unseasonably warm weather, the results of the gas distribution business remained rather stable.

U.S. Midwest Total sales of the U.S. Midwest market unit amounted to €1,819 million in 2007, a decrease of 5.8 percent from €1,930 million in 2006. The decrease was primarily attributable to translation effects reflecting the increase in the value of the euro over the course of the year. In US dollars (U.S. Midwest’s operating currency), the market unit’s sales were slightly higher, with the impact of higher retail sales volumes partially offset by that of lower gas prices.

The following table sets forth the sales of each business unit in the U.S. Midwest market unit in each of the last two years: SALES OF U.S. MIDWEST MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Regulated Business ...... 1,766 1,869 -5.5 Non-regulated Business ...... 53 61 -13.1 Total ...... 1,819 1,930 -5.8

Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, decreased by €103 million to €1,766 million in 2007, from €1,869 million in 2006. The 5.5 percent decrease was attributable to the increase in the value of the euro over the course of the year. In US dollars, sales of the Regulated Business increased as a result of the impact of higher power retail sales volumes partially offset by that of lower gas prices.

64 The decrease in sales at the Non-regulated Business was also primarily attributable to the strong euro, as sales in US dollars were relatively flat.

Adjusted EBIT at the U.S. Midwest market unit decreased by 8.9 percent from €426 million in 2006 to €388 million in 2007.

The following table sets forth the adjusted EBIT of each business unit in the U.S. Midwest market unit in each of the last two years: ADJUSTED EBIT OF U.S. MIDWEST MARKET UNIT

IFRS IFRS Percent 2007 2006 Change (€ in millions) Regulated Business ...... 393 431 -8.8 Non-regulated Business ...... -5 -5 — Total ...... 388 426 -8.9

Adjusted EBIT at the Regulated Business decreased by €38 million or 8.8 percent from €431 million in 2006 to €393 million in 2007. The decrease was primarily attributable to translation effects caused by the stronger euro, although the business unit’s adjusted EBIT result in US dollars was also slightly lower than that in the previous year. In US dollar terms, the negative impact of lower off-system electric sales volumes and lower gas margins as a result of the timing of gas cost recoveries from customers was largely offset by higher retail electric volumes and higher environmental cost recoveries.

Adjusted EBIT at E.ON U.S.’s Non-regulated Business was essentially flat compared to the prior year.

Corporate Center The Corporate Center reduced Group sales by €3,785 million in 2007, compared with reducing sales by €3,328 million in 2006. The 2007 figure also reflected €252 million in sales of newly acquired companies (primarily OGK-4 and Airtricity). The reduction in adjusted EBIT attributable to the segment was €232 million in 2007, compared with €403 million in 2006. The contribution of the Corporate Center to both sales and adjusted EBIT is structurally negative due to the elimination of intersegment results and administrative costs that are not matched by revenues.

Discontinued Operations E.ON U.S.’s wholly-owned subsidiary, WKE operates the generating facilities of Big Rivers Electric Corporation (“BREC”), a power generation cooperative in western Kentucky, and a coal-fired facility owned by the city of Henderson, Kentucky, under a 25-year lease which commenced in July 1998. In March 2007, E.ON U.S. entered into an agreement with BREC regarding an anticipated transaction to terminate the lease and operational agreements among the parties and other related matters. During 2007, the parties entered into a number of definitive amendments and ancillary documents regarding the termination transaction. The closing of the lease termination transaction remains subject to a number of conditions, including review and approval of various regulatory agencies and acquisition of certain consents by other interested parties. Subject to such contingencies, the parties are working on completing the proposed termination transaction in the first half of 2008. WKE was classified as discontinued operations at the end of December 2005. “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income included a loss of €81 million for 2007, and income of €64 million for 2006 related to WKE.

In addition to the loss recorded with respect to WKE, there were gains from discontinued operations recognized in 2007, primarily €418 million in respect of book gains on the sale of tranches of Degussa shares to

65 RAG in previous years. Although Degussa had not been considered a discontinued operation under U.S. GAAP, it did qualify as a discontinued operation under IFRS 5, “Non-current Assets Held for Sale and Discontinued Operations” (“IFRS 5”). The gains on these sales of Degussa shares, which were attributable to E.ON’s former 39.2 percent interest in RAG, crystallized as a result of the transfer to the “RAG-Stiftung Foundation” on November 30, 2007 of E.ON’s shareholding in RAG and were therefore recorded” in 2007. The 2007 results from discontinued operations also reflected €6 million in gains from the discontinued operations of the Company’s former Viterra real estate segment, as well as a loss of €13 million from the sale of the former Veba Oel oil segment.

Our IFRS results from discontinued operations in 2006 were also significantly affected by the classification of Degussa as a discontinued operation, as the 2006 result reflected both €37 million in income earned by Degussa prior to its disposal in the first quarter of 2006 (during which period we accounted for our interest in Degussa under the equity method) and €596 million in book gains on the sale of Degussa shares to RAG in 2006. The 2006 results also reflected €53 million in gains from the discontinued operations of Viterra and €20 million in gains from the discontinued operations of E.ON Finland (including €9 million in income earned by E.ON Finland prior to its disposal in June 2006).

For more information on the discontinued operations, including certain selected financial information, see Note 4 of the Notes to Consolidated Financial Statements.

Year Ended December 31, 2006 Compared With Year Ended December 31, 2005 As noted above, the comparison of E.ON’s segment results for 2006 and 2005 presented below has been prepared in accordance with U.S. GAAP, as previously reported in E.ON’s Annual Report on Form 20-F for the fiscal year ended December 31, 2006 and the Notes to Consolidated Financial Statements included therein.

The following table sets forth sales and adjusted EBIT, which are presented in accordance with U.S. GAAP, for each of E.ON’s business segments for 2006 and 2005 (in each case excluding the results of discontinued operations): E.ON BUSINESS SEGMENT SALES AND ADJUSTED EBIT

U.S. GAAP U.S. GAAP 2006 2005 Adjusted Adjusted Sales EBIT Sales EBIT (€ in millions) Central Europe(1) ...... 28,380 4,168 24,295 3,930 Pan-European Gas(2)(3) ...... 24,987 2,106 17,914 1,536 U.K ...... 12,569 1,229 10,176 963 Nordic(2)(4) ...... 3,204 619 3,213 766 U.S. Midwest(2) ...... 1,947 391 2,045 365 Corporate Center(2)(5) ...... (3,328) (416) (1,502) (399) Core Energy Business ...... 67,759 8,097 56,141 7,161 Other Activities(2)(6) ...... — 53 — 132 Total ...... 67,759 8,150 56,141 7,293

(1) Sales include energy taxes of €1,124 million in 2006 and €1,049 million in 2005. (2) Excludes the sales and adjusted EBIT of certain activities now accounted for as discontinued operations. For more details, see “— Discontinued Operations” for this period below and Note 4 of the Notes to Consolidated Financial Statements. (3) Sales include natural gas and electricity taxes of €2,060 million in 2006 and €3,110 million in 2005. (4) Sales include electricity and natural gas taxes of €377 million in 2006 and €381 million in 2005.

66 (5) Includes primarily the parent company and effects from consolidation (including the elimination of intersegment sales), as well as the results of its remaining telecommunications interests, as explained above. Sales between companies in the same market unit are eliminated in calculating sales on the market unit level. (6) Includes adjusted EBIT of Degussa.

For a reconciliation of adjusted EBIT to net income, see the discussion under “— E.ON Group” below.

E.ON Group E.ON’s sales in 2006 increased 24.4 percent to €64,197 million from €51,616 million in 2005 (in each case net of electricity and natural gas taxes). As noted above, the increase was primarily attributable to higher electricity and gas sales at the Pan-European Gas and Central Europe market units. As illustrated in the table on the previous page, the overall increase in the Group’s sales also reflected an increase in sales at the Central Europe, Pan-European Gas and U.K. market units, which more than offset decreases at the Nordic and U.S. Midwest market units and the Corporate Center.

Sales of the Central Europe market unit increased 16.8 percent in 2006 to €28,380 million (including €1,124 million of electricity taxes) from €24,295 million (including €1,049 million of electricity taxes) in 2005. Pan-European Gas’ sales increased by 39.5 percent to €24,987 million (including €2,060 million of natural gas and electricity taxes) in 2006 from €17,914 million (including €3,110 million of natural gas and electricity taxes) in 2005. Sales of the U.K. market unit increased by 23.5 percent, amounting to €12,569 million in 2006 as compared to €10,176 million in 2005. Nordic’s sales decreased by 0.3 percent to €3,204 million (including €377 million of electricity and natural gas taxes) from €3,213 million (including €381 million of electricity and natural gas taxes) in 2005. Sales of the U.S. Midwest market unit decreased by 4.8 percent in 2006 to €1,947 million compared with €2,045 million in 2005. The elimination of intersegment sales at the Corporate Center resulted in the segment reporting negative sales of €1,502 million in 2005 and negative sales of €3,328 million in 2006. The sales of each of these segments are discussed in more detail below.

Total cost of goods sold and services provided in 2006 increased 28.8 percent or €11,701 million to €52,304 million compared with €40,603 million in 2005, with increases at the Pan-European Gas market unit, primarily reflecting the effect of higher gas prices, and at the Central Europe market unit. Purchases of electricity from third parties and the purchase of significantly higher volumes of electricity generated from renewable resources, as well as price-related increased procurement costs for gas increased costs of goods sold at the Central Europe market unit while consolidation effects and higher costs at the U.K. market unit also contributed to the overall increase. These effects were partially offset by lower cost of goods sold and services provided at the Corporate Center, reflecting consolidation effects recorded at the Corporate Center level mainly as a result of higher intergroup sales from the Pan-European Gas market unit to the U.K. market unit. Cost of goods sold as a percentage of revenues (net of electricity and natural gas taxes) increased to 81.5 percent in 2006 from 78.7 percent in 2005, as the rate of increase of cost of goods sold and services provided was greater than that of sales. Gross profit nonetheless increased, rising by 8.0 percent to €11,893 million in 2006 from €11,013 million in 2005.

Selling expenses increased 12.9 percent or €496 million to €4,341 million in 2006, compared with €3,845 million in 2005. The increase reflected an overall increase of €299 million in selling expenses at the U.K. market unit as a result of the expansion of the sales force and impairments of intangible assets due to the rebranding of Powergen, at the Central Europe market unit, primarily attributable to the consolidation effects involving Arena One GmbH (“Arena One”), E.ON Moldova and the Bulgarian companies Varna and Gorna and IT-related expenses, as well as at the Pan-European market unit, primarily resulting from the first-time full-year consolidation of E.ON Gaz România.

General and administrative expenses increased by €258 million, amounting to €1,774 million in 2006 compared with €1,516 million in 2005. The 17.0 percent increase reflected increases at the U.K. market unit,

67 primarily due to higher headcount, at the Central Europe market unit mainly resulting from consolidation effects and an increase in purchased services from third parties, and at the Pan-European Gas market unit, also reflecting the first full year consolidation of several new shareholdings. These effects were partially offset by lower general and administrative expenses at the Corporate Center, reflecting consolidation effects.

Other operating income (expenses), net equaled expenses of €848 million in 2006 as compared to income of €1,674 million in 2005. The significant change in this line item was primarily attributable to net gains/losses on derivative instruments, which generated expenses of €2,748 million in 2006, compared to income of €931 million in 2005, in part reflecting a decrease in the market value of derivatives at E.ON UK. In addition, net income arising from exchange rate differences of €44 million in 2006 was lower than the corresponding net income of €138 million in 2005. These negative effects were partially offset by higher net book gains on the disposal of investments and increased miscellaneous other net operating income. Net book gains on the disposal of investments increased by €545 million year on year, amounting to €579 million in 2006, compared with €34 million in 2005. The 2006 figure primarily included the gain from the forward sale of the stake in Degussa. Miscellaneous other operating income (expenses), net rose by €733 million, amounting to net income of €1,297 million in 2006, as compared with net income of €564 million in 2005. For 2006, this line item also reflects gains from the derecognition of institutional securities funds as part of the transfer to the Contractual Trust Arrangement (“CTA”) in the amount of €159 million. In 2006, a Staff Accounting Bulletin No. 51, Accounting for Sales of Stock of a Subsidiary, gain of €7 million related to the sale of shares of E.ON Avacon, compared with €31 million in 2005.

Financial earnings increased by €377 million, resulting in a gain of €203 million in 2006 compared with a loss of €174 million in 2005. The increase was primarily attributable to higher income from companies accounted for under the equity method of €403 million and lower interest expenses of €49 million, which were partly offset by higher depreciation on securities and share investments. For additional information, see Note 9 of the Notes to Consolidated Financial Statements.

As a result of the factors described above, income (loss) from continuing operations before income taxes and minority interests decreased by 28.2 percent or €2,019 million to €5,133 million in 2006, as compared with €7,152 million in 2005.

In 2006, E.ON recorded an income tax benefit of €323 million, as compared to a tax expense of €2,261 million in 2005. This change was primarily attributable to the change in the German corporate income tax act with regard to corporate tax credits arising from the former corporate imputation system which led to a tax credit of approximately €1.3 billion. In addition, deferred tax income in the amount of approximately €1.2 billion resulted primarily from losses in the market valuation of energy derivatives. For additional information, see Note 10 of the Notes to Consolidated Financial Statements.

Income attributable to minority interests, and therefore deducted in the calculation of net income, was €526 million in 2006, as compared to €536 million in 2005.

Results from discontinued operations increased net income by €127 million in 2006, as compared to a contribution to net income of €3,059 million in 2005. The significant decrease reflected the very significant gains on the disposal of Viterra and Ruhrgas Industries recorded in 2005. For details, see Note 4 of the Notes to Consolidated Financial Statements. The Group’s net income decreased 31.7 percent, totaling €5,057 million in 2006, compared with €7,407 million in 2005. Excluding the results of discontinued operations, E.ON would have recorded net income of €4,930 million in 2006, as compared to net income of €4,355 million in 2005.

Reconciliation of Adjusted EBIT. As noted above, E.ON uses adjusted EBIT as its segment reporting measure in accordance with SFAS 131. On a consolidated Group basis, adjusted EBIT is considered a

68 non-GAAP measure that must be reconciled to the most directly comparable GAAP measure. A reconciliation of Group adjusted EBIT to net income for each of 2006 and 2005 appears in the table below. The following paragraphs discuss changes in the principal components of each of the reconciling items to income (loss) from continuing operations before income taxes and minority interests. For additional details, see Note 33 of the Notes to Consolidated Financial Statements. U.S. GAAP U.S. GAAP 2006 2005 (€ in millions) Adjusted EBIT ...... 8,150 7,293 Adjusted interest income, net ...... (1,081) (1,027) Net book gains ...... 1,205 491 Cost-management and restructuring expenses ...... — (29) Other non-operating results ...... (3,141) 424 Income/(loss) from continuing operations before income taxes and minority interests 5,133 7,152 Income taxes ...... 323 (2,261) Minority interests ...... (526) (536) Income/(loss) from continuing operations ...... 4,930 4,355 Income/(loss) from discontinued operations ...... 127 3,059 Cumulative effect of change in accounting principles ...... — (7) Net income ...... 5,057 7,407

On a consolidated Group basis, adjusted EBIT increased by 12.0 percent to €8,150 million in 2006, as compared with €7,293 million in 2005. As detailed in the table below, adjusted interest income, net, amounted to an expense of €1,081 million in 2006 as compared to an expense of €1,027 million in 2005. The interest portion of long-term provisions deducted in the calculation was €389 million, as compared to €252 million in 2005, reflecting higher interest expenses for nuclear waste management that were partially offset by lower interest expenses for pensions at the Central Europe and Pan-European Gas market units, as well as the Corporate Center. Non-operating interest income, net, amounted to income of €5 million in 2006 as compared with income of €39 million in 2005. In 2006, non-operating interest income primarily reflected higher interest charges related to derivatives in the U.K. market unit that were partially offset by higher interest income at the Central Europe market unit and the Corporate Center. In 2005, non-operating interest income primarily reflected the termination of an interest provision. U.S. GAAP U.S. GAAP 2006 2005 (€ in millions) Interest income and similar expenses (net) as shown in Note 9 of the Notes to Consolidated Financial Statements ...... (687) (736) (+) Non-operating interest income, net(1) ...... (5) (39) (–) Interest portion of long-term provisions ...... 389 252 Adjusted interest income, net ...... (1,081) (1,027)

(1) This net figure is calculated by adding in non-operating interest expense and subtracting non-operating interest income. Net book gains as used in the reconciliation of adjusted EBIT more than doubled in 2006, increasing by €714 million from €491 million in 2005 to €1,205 million. In 2006, net book gains primarily resulted from the sale of funds invested in securities held by the Central Europe market unit and the Degussa transaction. In 2005, net book gains primarily resulted from the sale of other securities held by the Central Europe market unit. In addition, the Central Europe market unit realized a gain on disposal of €90 million from the transfer of shares in TEAG. These book gains are calculated on a more inclusive basis than those discussed above in the analysis of

69 other operating income (expenses), net. These gains generally include all gains and losses from the disposal of financial assets and results of deconsolidation, both net of expenses directly linked with the relevant disposal. They also include book gains and losses realized by equity investees, which are included in the income statement as a component of financial earnings.

Cost-management and restructuring expenses did not occur in 2006, compared with €29 million in 2005. In 2005, the principal expenses contributing to this item were restructuring costs of €18 million at the U.K. market unit, mainly attributable to the integration of Midlands Electricity, and restructuring costs of €11 million at the Central Europe market unit, primarily due to the merger of GVT and TEAG into ETE.

The amount reported as other non-operating results amounted to an expense of €3,141 million in 2006, as compared to income of €424 million in 2005. The total of 2006 primarily reflected the fulfilment of derivative gas procurement contracts and the marking to market of derivatives, particularly at the U.K. market unit. The 2006 result also reflected a total of €548 million in impairment charges. Following the BNetzA’s reduction of allowable network charges, E.ON conducted impairment tests on E.ON’s network assets and shareholdings in municipal distribution network operators. As a result, E.ON recorded impairment charges totaling €374 million in its gas distribution businesses. Of this total, €266 million relate to the Central Europe market unit, with €227 million relating to its own gas distribution networks and the remaining €39 million to minority shareholdings. The remaining impairment loss of €108 million was recorded on other shareholdings at the Pan-European Gas market unit. Impairment tests on E.ON Energie’s electricity transmission and distribution networks did not lead to any impairment losses. Further impairments relate to CHP generation assets at the U.K. market unit, as well as intangible and tangible assets at the Pan-European Gas, U.K. and Nordic market units. The impact of these impairments was partially offset by effects from the first-time consolidation of VKE at the Central Europe market unit, which add up to €83 million. In 2005, other non-operating earnings positively reflected unrealized gains from the required marking to market of derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, primarily at the U.K. market unit. This positive effect on this item was partially offset by the impact of an impairment charge that Degussa took as of December 31, 2005. Degussa recorded an impairment charge of €836 million (before taxes) in its Fine Chemicals business unit due to significant changes in market conditions. As a result of this impairment, E.ON recorded a loss of €347 million attributable to its direct 42.9 percent shareholding in Degussa. Additional offsetting effects on other non-operating earnings were storm-related costs for rebuilding of the distribution grid and compensating customers of €142 million at the Nordic market unit, impairments recorded at cogeneration facilities in the U.K. market unit, and an adjustment of deferred taxes made at an equity holding of the Corporate Center.

Central Europe For financial reporting purposes, the Central Europe market unit comprises four business units: Central Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power also includes the results of E.ON Benelux, which operates power generation, district heating and gas and electricity retail businesses in the Netherlands. The Central Europe West Gas business unit reflects the results of the regional distribution of gas and the gas retail business in Germany. The Central Europe East business unit primarily includes the results of the regional distribution companies in Bulgaria, the Czech Republic, Hungary, Romania and Slovakia (with the Slovak activities being valued under the equity method given E.ON Energie’s minority interest). Other/Consolidation primarily includes the results of E.ON Energie’s business in Italy, other national and international shareholdings, service companies and E.ON Energie AG, as well as intrasegment consolidation effects.

Total sales of the Central Europe market unit increased by 16.8 percent to €28,380 million (including €1,124 million of energy taxes and €686 million in intersegment sales) in 2006, compared with a total of

70 €24,295 million (including €1,049 million of energy taxes and €248 million in intersegment sales) in 2005. The overall increase of €4,085 million reflected higher sales at each of Central Europe’s business units, as described in more detail below.

The following table sets forth the sales of each business unit in the Central Europe market unit in each of the last two years, in each case excluding energy taxes: SALES OF CENTRAL EUROPE MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Central Europe West Power ...... 18,885 16,945 +11.4 Central Europe West Gas ...... 4,371 3,463 +26.2 Central Europe East ...... 3,469 2,618 +32.5 Other/Consolidation ...... 531 220 +141.4 Total ...... 27,256 23,246 +17.3

Sales of the Central Europe West Power business unit increased by €1,940 million or 11.4 percent from €16,945 million in 2005 to €18,885 million in 2006. The rise was primarily attributable to higher electricity prices resulting from the global rise in raw material and energy prices as well as to an increase in the sale of electricity produced from renewable resources, as the volume of such energy, which E.ON Energie is required to purchase under regulatory requirements, increased in 2006. An increase in the volume of electricity sold also contributed to the increase in sales. These positive impacts were offset in part by the negative effect of the new regulations applicable to network charges in Germany.

Sales of the Central Europe West Gas business unit rose by 26.2 percent from €3,463 million in 2005 to €4,371 million in 2006, with the increase of €908 million primarily reflecting higher gas prices as well as the first-time full-year consolidation of GVT. These positive factors were offset in part by the negative effect of the new regulation applicable to network charges in Germany.

Sales of the Central Europe East business unit increased by 32.5 percent or €851 million, from €2,618 million in 2005 to €3,469 million in 2006, with the increase primarily due to the first-time inclusion of full-year results from Hungarian gas companies which were consolidated as of April 2005, the Bulgarian companies Varna and Gorna Oryahovitza (consolidated as of March 2005), and the Romanian company E.ON Moldova (consolidated as of September 2005), as well as the first-time inclusion of two companies in the Czech Republic and one Hungarian company in 2006. The remainder mainly resulted from higher electricity prices in Hungary and the Czech Republic.

Sales of the Other/Consolidation business unit more than doubled, increasing by €311 million to €531 million in 2006, with the increase being primarily attributable to the consolidation effects involving E.ON IS UK (an IT services company), Arena One and Dalmine.

Total power procured by the Central Europe market unit (excluding physically-settled trading activities) rose 3.6 percent to 281.2 billion kWh in 2006, compared with 271.3 billion kWh in 2005. The increase was primarily attributable to an increase in power procured from third parties and the own production of power. E.ON Energie’s own production of power increased by 1.7 percent from 129.1 billion kWh in 2005 to 131.3 billion kWh in 2006. E.ON Energie produced approximately 47 percent of its power requirements in 2006, compared with approximately 48 percent in 2005. Compared with 2005, electricity purchased from jointly operated power stations increased by 2.2 percent from 12.0 billion kWh to 12.3 billion kWh. Purchases of electricity from third

71 parties increased by 5.7 percent, from 130.2 billion kWh in 2005 to 137.6 billion kWh in 2006, largely due to the first-time inclusion of a full year of results from the electricity distribution companies in Bulgaria and Romania (approximately 3.6 TWh), as well as the purchase of significantly higher volumes of electricity generated from renewable resources pursuant to Germany’s Renewable Energy Law (approximately 3.4 TWh).

In 2006, the Central Europe market unit contributed adjusted EBIT of €4,168 million, a 6.1 percent increase from a total of €3,930 million in 2005. The following table sets forth the adjusted EBIT of each business unit in the Central Europe market unit in each of the last two years: ADJUSTED EBIT OF CENTRAL EUROPE MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Central Europe West Power ...... 3,550 3,389 +4.8 Central Europe West Gas ...... 272 307 -11.4 Central Europe East ...... 269 237 +13.5 Other/Consolidation ...... 77 (3) — Total ...... 4,168 3,930 +6.1

Adjusted EBIT at the Central Europe West Power business unit increased by €161 million from €3,389 million in 2005 to €3,550 million in 2006. This 4.8 percent increase was primarily attributable to higher wholesale electricity prices which could be passed on to customers, higher earnings from sale of shareholdings and lower expenses for nuclear fuel management, primarily due to the absence of expenditures for nuclear operations taken in the prior year. The positive effects of these factors on the business unit’s adjusted EBIT were partly offset by negative effects from the new regulation of network charges in Germany. Higher fuel costs, primarily reflecting significantly higher prices for hard coal and higher procurement costs also reduced overall adjusted EBIT. Adjusted EBIT was also negatively affected by increased charges relating to earlier periods.

Adjusted EBIT of the Central Europe West Gas business unit decreased by 11.4 percent to €272 million in 2006, compared with €307 million in 2005. The lower result was a consequence of the impact of new regulation of network charges in Germany. The negative impact of the regulation could only partially be offset by the effect of the first-time inclusion of a full year of results from GVT.

The Central Europe East business unit contributed adjusted EBIT of €269 million in 2006, a 13.5 percent increase from €237 million in 2005, largely reflecting the inclusion of a full year of earnings from the regional distributors in Bulgaria, Hungary, and Romania acquired in 2005, as well as a positive contribution from the two newly acquired companies in the Czech Republic. Higher procurement costs and weather related lower sales volumes in the Hungarian gas business had a negative effect on adjusted EBIT.

Central Europe’s Other/Consolidation business unit recorded an adjusted EBIT of €77 million in 2006 compared with an adjusted EBIT of negative €3 million in 2005. This positive change primarily resulted from higher income from realized hedging transactions and increased earnings from shareholdings, while intrasegment consolidation effects, re-evaluation of stock options owing to an increase in E.ON’s stock price, reduction of the interest rate for pensions and changes in the basis of consolidation had a negative effect.

Pan-European Gas For financial reporting purposes, the Pan-European Gas market unit is divided into three business units: Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects the results of the supply, transmission system, storage and sales businesses, with the midstream operations

72 essentially including all of the supply and sales business other than exploration and production activities. The Downstream Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes consolidation effects.

The results of the Downstream Shareholdings business unit have included the results of E.ON Gaz România since July 1, 2005 and the results of MOL’s gas trading and storage units (now E.ON Földgaz Trade and E.ON Földgaz Storage) since April 1, 2006. The results of the Up-/Midstream business unit include those of Caledonia (now E.ON Ruhrgas North Sea), which has been consolidated since November 1, 2005.

Total sales of the Pan-European Gas market unit increased by 39.5 percent to €24,987 million (including €2,060 million of natural gas and electricity taxes and €2,393 million in intersegment sales) in 2006, compared with a total of €17,914 million (including €3,110 million of natural gas and electricity taxes and €1,079 million in intersegment sales) in 2005. The increase was mainly attributable to higher average sales prices, higher sales volumes outside of Germany and consolidation effects. The decline in natural gas and electricity taxes is related to the new German energy taxation law which came into effect in August 2006 and provides that the tax is paid by distributors of gas rather than the importer.

The following table sets forth the sales of each business unit in the Pan-European Gas market unit (excluding natural gas and electricity taxes) in each of the last two years: SALES OF PAN-EUROPEAN GAS MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Up-/Midstream ...... 18,868 13,380 +41.0 Downstream ...... 4,773 1,848 +158.3 Other/Consolidation ...... (715) (424) -68.6 Total ...... 22,926 14,804 +54.9

Sales in the Up-/Midstream business unit increased in 2006 by €5,488 million or 41.0 percent from €13,380 million to €18,868 million, with the increase being primarily attributable to the increase in average sales prices and higher sales volumes (from 690.2 billion kWh to 709.7 billion kWh) in the midstream activities. In the upstream business, sales increased in particular as a result of the first time full year inclusion of E.ON Ruhrgas North Sea, which was acquired in November 2005, and the increase of sales prices at E.ON Ruhrgas Norge and E.ON Ruhrgas UK.

In the Downstream Shareholdings business unit, sales more than doubled, increasing by €2,925 million to €4,773 million in 2006 compared with €1,848 million in 2005. The main reason for the change was an increase in sales in ERI’s downstream operations, particularly the impact of the first-time consolidation of E.ON Földgaz Trade and E.ON Földgaz Storage following their consolidation in April and the first time inclusion of a full year of results from E.ON Gaz România. The overall figure also reflected an increase in sales of €125 million at Thüga’s downstream operations, mainly reflecting a rise in gas sales as a consequence of higher average gas prices, the impact of which was partially offset by the impact of regulatory changes in Italy and Germany.

The total volume of gas sold by E.ON Ruhrgas’ midstream operations increased by 2.8 percent to 709.7 billion kWh in 2006 from 690.2 billion kWh in 2005. Sales to domestic distributors decreased by 1.5 percent from 323.7 billion kWh to 318.7 billion kWh. Sales to domestic municipal utilities increased by 1.4 percent from 160.9 billion kWh to 163.1 billion kWh. E.ON Ruhrgas sold 67.6 billion kWh of gas to domestic industrial customers, a decrease of 4.0 percent from 70.4 billion kWh in 2005. Exports reached 160.3 billion kWh in 2006, a 18.6 percent increase from 135.2 billion kWh in 2005, primarily resulting from increased trading activities in the U.K. E.ON Ruhrgas purchased approximately 84.4 percent of its gas supplies from outside

73 Germany and approximately 15.6 percent from German producers in 2006, compared with 84.5 percent and 15.5 percent, respectively, in 2005. In the Downstream Shareholdings business unit, total gas sales volumes more than doubled, rising from 69.0 billion kWh in 2005 to 175.1 billion kWh in 2006. Thüga increased its sales volumes by 2.7 percent to 23.1 billion kWh from 22.5 billion kWh. Sales volumes at ERI more than tripled to 152.0 billion kWh from 46.5 billion kWh in 2005, largely due to the first time inclusion of a full year of results from E.ON Gaz România and the inclusion of E.ON Földgaz since April 2006.

Adjusted EBIT of the Pan-European Gas market unit increased by 37.1 percent to €2,106 million in 2006 from €1,536 million in 2005. The rise in adjusted EBIT reflected positive results in the Up-/Midstream business unit, which were only partly offset by lower results in the Downstream Shareholdings business unit, as described in more detail below.

The following table sets forth the adjusted EBIT of each business unit in the Pan-European Gas market unit in each of the last two years: ADJUSTED EBIT OF PAN-EUROPEAN GAS MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Up-/Midstream ...... 1,684 988 +70.4 Downstream Shareholdings ...... 431 551 -21.8 Other/Consolidation ...... (9) (3) -200.0 Total ...... 2,106 1,536 +37.1

Adjusted EBIT in the Up-/Midstream business unit increased by €696 million or 70.4 percent from €988 million in 2005 to €1,684 million in 2006. The €25 million increase in adjusted EBIT at the upstream activities primarily reflected continued high oil and natural gas prices. These higher oil and gas prices led to improvements in adjusted EBIT of E.ON Ruhrgas UK and E.ON Ruhrgas Norge, whereas the positive effect of the first time inclusion of a full year of results from E.ON Ruhrgas North Sea was more than offset by the impact of reductions in expected production from certain gas fields. Adjusted EBIT in the midstream activities increased by €671 million, primarily due to the positive impact of the time lag effect in adjusting purchase prices, which had a negative impact last year. The settlement of proprietary trading transactions at maturity also contributed to the increase. The positive impact of these factors on the adjusted EBIT of the midstream activities was partially offset by a lower contribution from commodity derivatives as well as the combination of higher transportation fees and the fact that the 2005 result had benefited from the recalculation of fees for the usage of gas pipes.

In the Downstream Shareholdings business unit, adjusted EBIT decreased by €120 million or 21.8 percent to €431 million in 2006 from €551 million in 2005. The decrease in adjusted EBIT was primarily attributable to the new regulation of network charges in Germany which led to impairments of certain Thüga shareholdings totaling €188 million, as well as to the establishment of provisions for the obligation to refund to network customers the difference between network charges originally assessed and those finally approved. Furthermore, E.ON Földgaz Trade, which operates in Hungary’s regulated gas market, negatively impacted the Downstream Shareholding’s adjusted EBIT due to a delay in the approval of tariffs allowing it to recoup higher procurement costs. These negative effects were partially offset by higher net earnings at other equity investments, the inclusion of the results of E.ON Gaz România for the entire year of 2006 as compared to only six months in 2005 and the first- time inclusion of the results of E.ON Földgaz Storage.

U.K. From the beginning of 2006, E.ON UK re-allocated costs relating to the business services unit (facilities, IT and other shared services), which had been recorded under Other/Consolidation, to the Non-regulated Business to

74 reflect this unit’s use of such services. The Regulated Business already incurred a charge for these services. The 2005 results included below have been recalculated on the same basis to facilitate a comparison. In addition, the Energy Services business, most of which was included in the Regulated Business in prior years, has been included in the Non-regulated Business since the beginning of 2006, reflecting the unit’s revised strategic objectives.

Total sales of the U.K. market unit in 2006 increased by 23.5 percent to €12,569 million (including €163 million in intersegment sales) from €10,176 million (including €74 million in intersegment sales) in 2005, primarily as a result of increased sales in the Non-regulated Business, as explained in more detail below.

The following table sets forth the sales of each business unit in the U.K. market unit in each of the last two years: SALES OF U.K. MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Non-regulated Business ...... 12,081 9,553 +26.5 Regulated Business ...... 856 813 +5.3 Other/Consolidation ...... (368) (190) -93.7 Total ...... 12,569 10,176 +23.5

Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and trading), retail and the energy services businesses in the U.K., increased by €2,528 million from €9,553 million in 2005 to €12,081 million in 2006. This 26.5 percent increase was primarily attributable to higher retail prices driven by higher energy prices, the effects of which were partially offset by lower volumes resulting from warmer weather and changes in consumer behavior and higher sales in the wholesale market reflecting both higher energy prices and increased market sales volumes.

Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, increased to €856 million in 2006 from €813 million in 2005. The sales increase of €43 million, or 5.3 percent, was principally attributable to tariff changes.

Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of intrasegment sales and had a negative impact on sales of €368 million in 2006, as compared to a negative impact of €190 million in 2005.

The volume of electricity sold by the U.K. market unit decreased by 1.2 billion kWh or 1.6 percent to 73.8 billion kWh, as compared with 75.0 billion kWh in 2005. Market sales associated with trading operations increased by 2.1 billion kWh or 13.8 percent to 17.5 billion kWh and mass market sales increased by 0.6 billion kWh or 1.6 percent to 37.9 billion kWh, while those to industrial and commercial customers decreased by 3.9 billion kWh or 17.6 percent to 18.4 billion kWh, reflecting the market unit’s focus in this segment on securing margins rather than volume. The decrease in sales was reflected in the volume of own production and power purchased from outside sources. Own production decreased by 1.4 billion kWh or 3.7 percent from 37.3 billion kWh in 2005 to 35.9 billion kWh in 2006, primarily due to the unplanned outage at Ratcliffe power station. Power purchased from other suppliers decreased by 1.1 billion kWh or 2.8 percent to 38.1 billion kWh from 39.2 billion kWh, reflecting lower sales to industrial and commercial customers. The volume of power purchased from power stations in which E.ON UK has an interest of 50 percent or less increased by 0.1 billion kWh or 16.6 percent. Gas sales increased by 11.5 billion kWh or 6.3 percent from 182.5 billion kWh in 2005 to 194.0 billion kWh in 2006, with the increase reflecting higher market sales (20.9 billion kWh), offset in part by lower sales to industrial and commercial customers (3.9 billion kWh), lower sales to retail mass market customers (3.8 billion kWh), as well as a decrease in gas used for the market unit’s own generation

75 (1.7 billion kWh). E.ON UK satisfied its increased need for gas through an increase of 17.0 billion kWh or 12.7 percent in market purchases, while the volume of gas being sourced under long-term gas supply contracts decreased by 5.5 billion kWh or 11.4 percent from 48.4 billion kWh in 2005 to 42.9 billion kWh in 2006.

Adjusted EBIT at the U.K. market unit increased by €266 million or 27.6 percent from €963 million in 2005 to €1,229 million in 2006, reflecting an increase at each of the Non-regulated Business and the Regulated Business, partially offset by lower results at Other/Consolidation, as described in more detail below.

The following table sets forth the adjusted EBIT of each business unit in the U.K. market unit in each of the last two years: ADJUSTED EBIT OF U.K. MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Non-regulated Business ...... 869 540 +60.9 Regulated Business ...... 488 452 +8.0 Other/Consolidation ...... (128) (29) -341.4 Total ...... 1,229 963 +27.6

The Non-regulated Business contributed adjusted EBIT of €869 million in 2006. This €329 million or 60.9 percent increase from €540 million in 2005 mainly resulted from the combination of higher margins at the coal fired power stations, higher retail prices and profit and cost saving initiatives implemented after the disappointing results of the first quarter, which were partially offset by higher commodity costs in 2006 as well as the fact that the 2005 results reflected a benefit relating to the integration of previously outsourced customer service activities.

The Regulated Business increased its adjusted EBIT from €452 million in 2005 to €488 million in 2006. The 8.0 percent or €36 million increase was almost entirely attributable to tariff changes and cost improvements.

The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative due to the combination of intercompany eliminations and costs of the E.ON UK corporate center, was negative €128 million in 2006, as compared with negative €29 million in 2005. The change was primarily attributable to foreign exchange hedging impacts, higher pension costs and central costs to support a growing business.

Nordic Total sales of the Nordic market unit remained essentially stable in 2006, amounting to €3,204 million (including €377 million of electricity and natural gas taxes and €86 million in intersegment sales) compared to €3,213 million (including €381 million of electricity and natural gas taxes and €102 million in intersegment sales) in 2005. Sales decreased in both the Non-regulated Business and the Regulated Business units. This was offset by a positive development in Other/Consolidation, as described in more detail below.

As noted above, the Nordic market unit adopted a new business unit structure following the disposition of E.ON Finland, with its operating units split between the Non-regulated Business and the Regulated Business. In addition, the gas business has been undergoing structural changes since 2005. Following the deregulation of the Swedish gas market, the gas trading and retail businesses were moved from the distribution company to the respective trading and retail companies in the E.ON Sverige group. Since January 2006, the trading and retail businesses are included in the business unit “Non-regulated Business”, whereas the gas distribution business remains in the business unit “Regulated.” This re-allocation affects the year-on-year comparison of sales and adjusted EBIT for both the Regulated Business unit and the Non-regulated Business unit.

76 The following table sets forth the sales of each business unit in the Nordic market unit in each of the last two years, in each case excluding electricity and natural gas taxes: SALES OF NORDIC MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Non-regulated Business ...... 2,119 2,247 -5.7 Regulated Business ...... 725 850 -14.7 Other/Consolidation ...... (17) (266) +93.6 Total ...... 2,827 2,831 —

Sales in the Non-regulated Business unit, which includes power generation, retail, trading, heat and services operations decreased by €128 million or 5.7 percent from €2,247 million to €2,119 million, driven by lower volumes in hydro and nuclear power generation following significantly lower hydro reservoir inflow in the first three quarters of 2006 and the temporary shutdown of several nuclear plants.

Sales in the Regulated Business unit, which includes electricity distribution, as well as gas transmission, distribution and storage, decreased from €850 million to €725 million. This €125 million or 14.7 percent decrease was mainly attributable to the reorganization of gas trading activities from the Regulated Business unit to the Non-regulated Business unit in 2006 noted above.

Sales attributed to the Other/Consolidation business unit consists almost entirely of the elimination of intrasegment sales and had a negative impact on sales of €17 million in 2006, as compared to a negative impact of €266 million in 2005. The significant decrease of intersegment sales in 2006 compared to 2005 primarily reflects the impact of the re-allocation of the gas trading and retail businesses to the Non-regulated Business and the fact that the 2005 results had included a higher volume of maintenance services provided to the Non-regulated Business following the severe storm in January 2005. Notably, the hydroelectric assets sold to Statkraft in October 2005 were included in the Other/Consolidation business unit and contributed to the results until their disposal. This partly offset the negative impact on sales coming from the Other/Consolidation business unit in 2005.

Total power supplied by E.ON Nordic (excluding physically settled trading activities) decreased by 11.5 percent to 40.6 billion kWh in 2006, compared with 45.9 billion kWh in 2005. The decrease of 5.3 billion kWh reflected a reduction in the volume of power sold to sales partners/Nord Pool by 19.6 percent from 26.2 billion kWh in 2005 to 21.1 billion kWh in 2006, primarily reflecting lower hydroelectric production due to the prevailing hydroelectric situation, the sale of hydroelectric assets to Statkraft in late 2005, and the unplanned outages of nuclear reactors. Sales to residential customers decreased by 0.4 billion kWh or 5.7 percent from 7.0 billion kWh in 2005 to 6.6 billion kWh in 2006, as a result of unseasonably warm weather in the fourth quarter 2006. Sales to commercial customers increased by 1.6 percent to 12.7 billion kWh in 2006 compared with 12.6 billion kWh in 2005, reflecting the impact of new customers. E.ON Nordic’s own production decreased by 16.2 percent from 33.3 billion kWh in 2005 to 27.9 billion kWh in 2006, mainly resulting from lower hydroelectric generation (5.1 billion kWh) and lower nuclear generation (0.8 billion kWh). As a result of lower production volumes from its own sources, E.ON Nordic purchased slightly more power from outside sources (0.5 billion kWh). Purchases from jointly owned power stations remained stable with 10.2 billion kWh. The total volume of gas sold to third parties decreased in 2006 to 5.8 billion kWh from 6.9 billion kWh in 2005, mainly resulting from lower sales to industrial and distribution customers (1.7 billion kWh).

Adjusted EBIT at the Nordic market unit decreased by €147 million or 19.2 percent, from €766 million to €619 million, primarily reflecting lower generation volumes, the disposition of hydroelectric assets to Statkraft, and increased taxation on hydroelectric assets and nuclear generation, as described in more detail below.

77 The following table sets forth the adjusted EBIT of each business unit in the Nordic market unit in each of the last two years: ADJUSTED EBIT OF NORDIC MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Non-regulated Business ...... 448 541 -17.2 Regulated Business ...... 200 244 -18.0 Other/Consolidation ...... (29) (19) -52.6 Total ...... 619 766 -19.2

Adjusted EBIT in the Non-regulated Business unit decreased by €93 million from €541 million in 2005 to €448 million in 2006. This 17.2 percent decrease primarily reflected increased taxation on hydroelectric assets and nuclear generation, and lower hydro and nuclear generation volumes resulting from the strained hydrological situation during summer and autumn and the unplanned nuclear outages. These effects were partially offset by a positive effect from rising spot electricity prices and successful hedging activities, which enabled Nordic to secure higher average sales prices for its production portfolio.

In the Regulated Business, adjusted EBIT decreased by €44 million from €244 million in 2005 to €200 million in 2006. This 18.0 percent decrease mainly resulted from the re-allocation of gas trading activities from the Regulated Business unit to the Non-regulated Business unit, and increased costs for power losses in the transmission and distribution grid driven by higher electricity prices during 2006.

The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative due to the combination of intercompany eliminations and costs of the E.ON Nordic corporate center, was negative €19 million in 2005 and negative €29 million in 2006. The change primarily reflects the loss of the contribution from hydroelectric assets sold to Statkraft in 2005.

U.S. Midwest Total sales of the U.S. Midwest market unit amounted to €1,947 million in 2006, a decrease of 4.8 percent from €2,045 million in 2005. The decrease was primarily due to lower off-system sales volumes and milder weather in 2006, the impact of which was partially offset by higher recoveries of coal price increases from retail customers and recoveries of environmental capital spending.

The following table sets forth the sales of each business unit in the U.S. Midwest market unit in each of the last two years: SALES OF U.S. MIDWEST MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Regulated Business ...... 1,887 1,965 -4.0 Non-regulated Business ...... 60 80 -25.0 Total ...... 1,947 2,045 -4.8

Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, decreased by €78 million to €1,887 million in 2006, from €1,965 million in 2005. The 4.0 percent decrease was primarily attributable to lower revenues from off-system electric sales, as well as lower retail electric and gas volumes resulting from milder weather (and associated lower passed-through costs of gas supply), and lower off-system gas sales volumes. These negative effects were partially offset by the higher recovery from customers of passed-through costs for fuel (primarily coal) used for generation, and higher recoveries on environmental capital spending.

78 Sales of the Non-regulated Business, which primarily consists of ECC and its subsidiaries, decreased by €20 million or 25.0 percent from €80 million in 2005 to €60 million in 2006, with the decrease being primarily attributable to new regulations that allowed Argentine industrial customers to purchase gas directly from producers.

Adjusted EBIT at the U.S. Midwest market unit increased by 7.1 percent from €365 million in 2005 to €391 million in 2006.

The following table sets forth the adjusted EBIT of each business unit in the U.S. Midwest market unit in each of the last two years: ADJUSTED EBIT OF U.S. MIDWEST MARKET UNIT

U.S. GAAP U.S. GAAP Percent 2006 2005 Change (€ in millions) Regulated Business ...... 387 351 +10.3 Non-regulated Business ...... 4 14 -71.4 Total ...... 391 365 +7.1

Adjusted EBIT at the Regulated Business increased by €36 million or 10.3 percent from €351 million in 2005 to €387 million in 2006. The increase was primarily attributable to net cost savings resulting from the exit from MISO in the third quarter of 2006 and lower amortization expenses reflecting the completion of certain restructuring activities, as well as recoveries on environmental capital spending and higher prices realized on off-system electric sales. The impact of these positive effects was partially offset by lower retail electric and gas volumes due to significantly milder weather in 2006 and higher labor costs.

Adjusted EBIT at E.ON U.S.’s Non-regulated Business decreased from €14 million in 2005 to €4 million in 2006. This 71.4 percent or €10 million decrease primarily reflected the loss of earnings from LPI following its sale in 2006, partially offset by the improved performance of the Argentine operations.

Corporate Center The Corporate Center reduced Group sales by €3,328 million in 2006, compared with reducing sales by €1,502 million in 2005. The reduction in adjusted EBIT attributable to the segment was €416 million in 2006, compared with €399 million in 2005. The contribution of the Corporate Center to both sales and adjusted EBIT is structurally negative due to the elimination of intersegment results and administrative costs that are not matched by revenues.

Discontinued Operations In 2001, the Company discontinued the operations of its former aluminum segment. This former segment was accounted for as discontinued operations in accordance with U.S. GAAP. In 2005, E.ON discontinued and either disposed of certain operations or classified certain businesses as held for sale in the Pan-European Gas and U.S. Midwest market units, as well as Viterra in the Other Activities business segment. E.ON therefore also considers these businesses to be discontinued operations. Finally, in 2006, the Nordic market unit disposed of its entire stake in E.ON Finland. Under U.S. GAAP, results of all such discontinued operations must be shown separately, net of taxes and minority interests, under “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income. For details, see Note 4 of the Notes to Consolidated Financial Statements.

In March 2002, E.ON sold VAW (then one of Europe’s major aluminum companies) to the Norwegian company Norsk Hydro ASA for the aggregate price of €3.1 billion, including financial liabilities and pension provisions totaling €1.2 billion. E.ON realized a gain on disposal of €893 million, which does not include the

79 reversal of VAW’s negative goodwill of €191 million, as this amount was required to be recognized as income due to a change in accounting principles upon adoption of SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002. In 2005, E.ON recognized a gain of €10 million before income taxes resulting from the release of a related provision. This effect was recorded under “Income (Loss) from discontinued operations, net” in the Consolidated Statements of Income. In May 2005, E.ON sold Viterra to Deutsche Annington GmbH. The total consideration received for 100.0 percent of Viterra’s equity was €4 billion. The company was classified as a discontinued operation in May 2005 and deconsolidated as of July 31, 2005. E.ON recorded a gain of just over €2.4 billion on the sale, which closed in August. The portion of Viterra’s 2005 and 2004 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €2,558 million and €294 million, respectively. In 2005, Viterra had revenues of €453 million. In 2006, E.ON recognized gains of €52 million resulting from adjustments of the purchase price and the partial release of a related provision. In June 2005, E.ON Ruhrgas signed an agreement for the sale of Ruhrgas Industries to CVC Capital Partners, a European private equity firm. The purchase price for 100.0 percent of Ruhrgas Industries was €1.2 billion, with the purchasers’ assumption of Ruhrgas Industries’ debt and provisions bringing the total value of the transaction to €1.5 billion. The transaction received antitrust approvals in July and September and was closed on September 12, 2005. The company was classified as a discontinued operation in June 2005, and deconsolidated as of August 31, 2005. The portion of Ruhrgas Industries’ 2005 and 2004 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €628 million and €29 million, respectively. In 2005, Ruhrgas Industries had revenues of €847 million. E.ON recorded a gain on the disposal of €0.6 billion. In February 2006, E.ON Nordic and Fortum signed an agreement providing for Fortum’s acquisition of E.ON Nordic’s entire 65.6 percent stake in E.ON Finland for a total consideration of €393 million. The transaction closed in June 2006, and E.ON Nordic recorded a gain of €11 million on the sale. E.ON Finland was accounted for as discontinued operations from January 16, 2006 (the date on which a legal impediment to E.ON Nordic’s sale of the stake was removed) through the date of its disposal. The portion of E.ON Finland’s 2006 and 2005 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €11 million and €24 million, respectively. In 2006, E.ON Finland had revenues of €131 million. The U.S. GAAP consolidated financial statements and related notes thereto for the years ending December 31, 2006, 2005 and 2004, were reclassified to reflect the discontinued operations treatment outlined above. Operating results for discontinued operations through the disposal date, as well as the gains or losses from ultimate sale, are reported in “Income (Loss) from discontinued operations, net” in the Consolidated Statements of Income. The assets and liabilities of the business units which were classified as held for sale as of December 31, 2006 and 2005, but which were not yet sold as of the respective balance sheet date, are reported as “Assets of disposal groups” and “Liabilities of disposal groups,” respectively, in the respective Consolidated Balance Sheets. Cash flows from discontinued operations have been presented separately from the Consolidated Statements of Cash Flows for all periods presented.

Other Activities For the period between Degussa’s deconsolidation and E.ON’s disposal of its interest in July 2006, E.ON’s proportionate share of Degussa’s after-tax earnings continued to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which is reported as a separate segment. Degussa contributed €53 million to adjusted EBIT in 2006, compared with €132 million in 2005. For information regarding the disposal of E.ON’s remaining interest in Degussa, see “Business — Overview.”

Liquidity And Capital Resources The major source of liquidity for E.ON in 2007 was again cash provided by operating activities. Cash provided by operating activities amounted to €8,726 million in 2007 and €7,161 million in 2006. The 21.9

80 percent increase in cash provided by operating activities in 2007 was primarily attributable to improvements at the Pan-European Gas, U.K. and Nordic market units. A key factor at the Pan-European Gas market unit was the inclusion of a full year of results from the E.ON Földgaz companies, which were not consolidated until April 2006, and negatively impacted cash provided by operating activities in 2006. In addition, there were positive cash effects arising from the usage of stored volumes in 2007. The improvement at the U.K. market unit was mainly due to improved operational performance from the retail business, and an improvement in the management of accounts receivable, as well as strong profits from the fourth quarter of 2006 collected as cash in 2007. At the Nordic market unit, positive effects from higher power sales volumes, higher average price levels achieved through hedging activities, and improvements in working capital were offset by cash-effective payments for the January storm and higher income tax payments. Improvements at these market units were partially offset by lower levels of cash from operations at the Corporate Center, primarily due to lower external tax refunds, and at the U.S. Midwest market unit, mainly due to increased pension contributions made in 2007 and the strong performance of the euro.

Proceeds from divestments, which are reported in the Consolidated Statements of Cash Flows as the sum of payments received on the disposition of equity investments and intangible and fixed assets, amounted to €1,431 million in 2007 and €3,877 million in 2006. In 2007, divestment proceeds were primarily attributable to the sale of E.ON’s interest in ONE (€569 million), the sale of various interests in Saxony held by the Pan-European Gas market unit to EnBW (€181 million) and an additional payment relating to the sale of equity interests in EWE Aktiengesellschaft (€100 million) at the Central Europe market unit.

E.ON’s major liquidity requirement in recent years has been capital expenditures for purchases of financial assets (including equity investments) and other fixed assets. Capital expenditures in 2007 and 2006 amounted to €11,306 million and €5,037 million, respectively, and are reported in the Consolidated Statements of Cash Flows as the sum of purchases of equity investments, and intangible and fixed assets. In both 2007 and 2006, investments in fixed and intangible assets exceeded purchases of equity investments. For additional information on these acquisitions, see “— Acquisitions and Dispositions” above and Note 4 of the Notes to Consolidated Financial Statements. As described in more detail in the segment analysis below, the most significant capital expenditures in 2007 were for the acquisition of E2-I, Airtricity and OGK-4 at the Corporate Center, and interests in the Skarv and Idun natural gas fields at the Pan-European Gas market unit. Funds used for the above- mentioned acquisitions were the primary reasons for the change in E.ON’s cash flow used for investing activities, which totaled €4,457 million cash used in 2006 and €8,789 million cash used in 2007.

Cash provided by financing activities totaled €1,808 million, as compared to €5,860 million in cash used by such activities in 2006, primarily reflecting an increase in borrowing, partially offset by cash used for the purchase of own shares as part of the share buy-back program. For further information, see Note 19 of the Notes to Consolidated Financial Statements.

As of December 31, 2007, the Group had cash and cash equivalents from continuing operations of €2,887 million, as compared with €1,154 million at December 31, 2006.

81 The following table shows the cash provided by operating activities and used for capital expenditures for each of the Group’s segments in 2007 and 2006 (in each case excluding the cash flows of discontinued operations, see “ — Results of Operations” above). E.ON BUSINESS SEGMENT CASH FLOW AND CAPITAL EXPENDITURES(1)(2) 2007 2006 Cash from Capital Cash from Capital Operations Expenditures Operations Expenditures (€ in millions) Central Europe ...... 3,811 2,581 3,802 2,279 Pan-European Gas(3) ...... 3,041 2,424 604 882 U.K...... 1,615 1,364 724 863 Nordic(3) ...... 914 914 715 642 U.S. Midwest(3) ...... 216 690 381 398 Corporate Center(3) ...... (871) 3,333 935 (27) Total ...... 8,726 11,306 7,161 5,037

(1) For a detailed description of capital expenditures by purchases of financial assets and purchases of other fixed assets, see Note 29 of the Notes to Consolidated Financial Statements. (2) Excludes investments in other financial assets. (3) Excludes the cash from operations and capital expenditures of certain activities accounted for as discontinued operations. For more details, see “— Results of Operations — Discontinued Operations” for each period and Note 4 of the Notes to Consolidated Financial Statements.

Capital Expenditures The Central Europe market unit continued to account for the largest portion of the Group’s capital expenditures over the most recent two-year period, primarily as a result of additions to property, plant and equipment and intangible assets, as well as acquisitions of equity interests in energy companies and other share investments. In 2007, capital expenditures at the Central Europe market unit rose by 13.3 percent to €2,581 million, compared to €2,279 million in the prior year. Investments in property, plant and equipment and intangible assets totaled €2,390 million, compared with €1,883 million in the prior year. The additional investments went towards power generation projects currently under way in Germany and Italy, as well as offshore investments in Germany. Share investments of €191 million were €205 million below the prior-year level. In 2006, investments in property, plant and equipment and intangible assets amounted to €1,883 million, mainly consisting of assets used in conventional and renewable power generation, waste incineration and the distribution of energy. The Central Europe market unit invested €396 million in share investments, of which €100 million were due to the acquisitions of JCP and Teplárna Otrokovice in the Czech Republic and Dalmine in Italy. Furthermore, investments in companies which are engaged in conventional generation and waste incineration plants amounted to €134 million.

The Pan-European Gas market unit’s level of capital expenditures almost tripled, increasing from €882 million in 2006 to €2,424 million in 2007. In 2007, the Pan-European Gas market unit invested €1,381 million in property, plant, and equipment and intangible assets with the largest single items being the acquisition of interests in Skarv and Idun gas fields in the northern Norwegian Sea (€641 million) and the construction of the new gas pipelines Lauterbach-Scheidt and Rothenstadt-Schwandorf (€160 million). Share investments of €1,043 million primarily reflected the acquisition of Contigas Deutsche Energie-AG from the Central Europe market unit. A corresponding offsetting item was recorded in the Corporate Center reporting segment. Furthermore, an increase in the stake held in Rohöl-Aufsuchungs AG led to an expenditure of €86 million. In 2006, the Pan-European Gas market unit invested €505 million in share investments, with the largest single investment being the €400 million spent acquiring the MOL activities. Investments in property, plant and equipment and intangible assets, mainly in the transmission system and the upstream activities, amounted to €377 million.

82 Investments in the U.K. market unit increased by 58.1 percent to €1,364 million in 2007, compared with €863 million in 2006. In 2007, the U.K. market unit spent €1,364 million on property, plant and equipment primarily for the development of new generation capacity, power station overhauls, gas storage and our distribution network, while there were no share investments during the year. In 2006, the U.K. market unit invested €860 million in property, plant and equipment and intangible assets, primarily for generation assets, including the development of new renewables capacity at Lockerbie, Scotland, and in existing conventional power plants, as well as investments in the regulated distribution business. Investments in share investments amounted to €3 million.

In 2007, investments at the Nordic market unit amounted to €914 million, an increase of 42.4 percent compared with 2006. E.ON Nordic invested €892 million in property, plant, and equipment and intangible assets, primarily to maintain and expand existing production plants and to upgrade and extend the distribution network. Share investments amounted to €22 million with the largest single investment being the acquisition of a further interest in Elverket Vallentuna AB. The Nordic market unit invested €642 million in 2006 with €592 million dedicated to property, plant and equipment and intangible assets, mainly to maintain existing production plants, particularly nuclear power plants, and to upgrade and extend E.ON Nordic’s distribution network. Share investments amounted to €50 million.

Capital expenditures in the U.S. Midwest market unit increased by 73.4 percent from €398 million in 2006 € to 690 million in 2007 primarily due to investments for SO2 emissions equipment and the construction of a new 750 MW baseload unit at the Trimble County plant.

The Corporate Center segment’s capital expenditures in 2007 amounted to €3,333 million, with €3,134 million in share investments, primarily for the acquisition of E2-I, Airtricity and OGK-4 and €199 million in property, plant and equipment and intangible assets. In the Corporate Center, capital expenditures amounted to negative €27 million in 2006, with investments of negative €13 million in share investments and negative €14 million in property, plant and equipment and intangible assets.

Financial Liabilities and Financing Policy. The financial liabilities of E.ON increased to €21,464 million at year-end 2007 from €13,472 million at year-end 2006. The increase of €7,992 million or 59.3 percent primarily resulted from increases in bonds outstanding (€5,467 million), commercial paper outstanding (€1,618 million), the outstanding amount of bank loans (€775 million) and other financial liabilities (€61 million). Bank loans increased from €1,237 million at year-end 2006 to €2,012 million at year-end 2007. (Of the amounts payable under bank loans at year-end 2007, €1,045 million (52.0 percent) are due in 2008, €93 million (4.6 percent) due in 2009, €381 million (18.9 percent) due in 2010, €182 million (9.0 percent) due in 2011, €100 million (5.0 percent) due in 2012 and €211 million (10.5 percent) due after 2012.)

E.ON’s investment program and its share buyback program are financed by liquid funds, operating cash flows and additional indebtedness. E.ON follows a financing policy that ensures access to various sources of financing at all times. As a general rule, external financings will be undertaken at the E.ON AG level or via the Dutch financing subsidiary E.ON International Finance B.V. (under guarantee of E.ON AG)) E.ON pursues a financing policy that is based on the following principles. Firstly, E.ON pursues a wide diversification of investors by accessing a variety of markets and using different instruments. Secondly, bonds are issued with a view to achieve a balanced portfolio of maturities. Thirdly, benchmark issues with a high volume are being combined with smaller opportunistic issues.

To support E.ON’s financing policy, E.ON AG has a Commercial Paper program and a Debt Issuance program with aggregate authorized amounts of €10 billion and €30 billion, respectively. E.ON also has a Syndicated Multi-Currency Revolving Credit Facility that permits borrowings in various currencies in an aggregate amount of up to €15 billion. For additional information on these programs, including amounts outstanding and available as of year end 2007, see Note 26 of the Notes to Consolidated Financial Statements.

83 For more detailed information on interest rates, maturities and other details of the Group’s financial liabilities, including the syndicated credit facility and Commercial Paper and Debt Issuance programs, see Note 26 of the Notes to Consolidated Financial Statements.

At year-end 2007, Standard & Poor’s Ratings Group (“S&P”) and Moody’s Investors Service (“Moody’s”) rated E.ON’s Commercial Paper program with a short-term rating of “A-1” and “Prime-1,” respectively. Following the announcement of E.ON’s new investment plan in May 2007, Moody’s confirmed its long-term rating for E.ON at “A2” with a stable outlook. Previously, Moody’s had reduced its long-term rating for E.ON from “Aa3” to “A2” following E.ON’s announcement that it had signed an agreement with Enel and Acciona to acquire certain assets following their purchase of Endesa. Moody’s short-term “P-1” rating remained unchanged. On June 12, 2007, S&P lowered its long-term rating for E.ON from “AA-” to “A” with a stable outlook following the announcement of E.ON’s revised strategy on May 31, 2007. Both the long-term rating from Moody’s and S&P factor in the higher investment plan and the resulting increase of indebtedness. Both agencies expect that the relevant ratios will remain within the ranges of an A2 or A rating, respectively.

Expected Investment Activity. E.ON currently plans to invest a total of approximately €49.9 billion over the three years from 2008 to 2010. A majority of these capital expenditures (approximately 73 percent or €36.3 billion) is planned for expanding the existing business and approximately 27 percent or €13.6 billion at maintaining E.ON’s position in the electricity and gas markets. The investment plan is based on the actual group structure as of December 31, 2007. Investments in new market units are shown as part of the Corporate Center.

The Central Europe market unit expects to make a total of approximately €14.3 billion in capital expenditures between 2008 and 2010. Of this amount, approximately 64 percent is budgeted for maintenance and replacement, and 36 percent are growth investments. Maintaining and increasing the unit’s generating capacity in the convergent western European market is an important component in these investments. As described in more detail in the description of the market unit’s activities in “Business,” the construction of new power stations at Datteln and Irsching has already begun, while E.ON is committed to building a new coal-fired power station at Staudinger if and when the necessary regulatory approvals are obtained. The market unit’s plans also include the construction at Wilhelmshaven of the world’s first large coal-fired power plant capable of operating with a target efficiency of more than 50 percent. Outside of Germany, E.ON has started to build a modern gas-fired power station at Livorno Ferraris in Italy, and plans to build a coal-fired power station at Maasvlakte in the Netherlands and at Antwerp in Belgium. New coal-fired and gas-fired power stations are planned at Malzenice in Slovakia and Gönyu in Hungary, as well as elsewhere in Eastern Europe. A total of approximately €3.5 billion has been budgeted for investments in power and gas networks in Central Europe, of which the single largest investment (approximately €1.7 billion) is intended for connecting the offshore wind power facilities to the power network.

The Pan-European Gas market unit plans to invest approximately €6.0 billion during the three-year period, of which approximately 90 percent is budgeted for growth investments. These investments are mainly targeted towards developing natural gas fields. In addition, investments are planned to improve and expand the gas transmission pipelines and storage facilities to secure the security and flexibility of gas supplies.

Investments at the U.K. market unit are expected to total approximately €5.7 billion between 2008 and 2010 and are predominantly focused on the replacement and maintenance of generation facilities and the distribution network infrastructure. This includes the construction of a coal-fired power station, as well as two combined cycle gas-fired plants. In addition, growth investment in power production from renewable sources, especially wind power, is also expected to increase. Of the total of €5.7 billion, approximately €0.8 billion has been budgeted for financial investments in companies operating wind power facilities.

The Nordic market unit is expected to invest approximately €3.0 billion over the three-year period. Nordic’s investments are mainly earmarked for the improvement of the Swedish power distribution network and the modernization, improvement in performance and expansion of existing generation facilities, such as the completion of the CHP power station currently being built at Malmö. Of the total of €3.0 billion, approximately €1.4 billion are maintenance and €1.6 billion are growth investments.

84 Capital expenditures totaling approximately €1.7 billion through 2010 are budgeted at the U.S. Midwest market unit. All of these investments are earmarked for property, plant and equipment. The market unit’s most important investment project is the completion of Trimble County 2, a 750 MW coal-fired power station, while investments will also be made in environmental measures at existing power stations and the improvement of power and gas networks.

The investment plan summarized above only contains projects that E.ON believes are sufficiently probable from today’s perspective.

In addition to the investments expected in each individual market unit (together totaling approximately €30.7 billion), other budgeted expenditures (totaling approximately €19.2 billion) over the period 2008 to 2010 include the planned takeover of activities in France, Italy and Spain as part of the agreement with Enel and Acciona, as well as investments in new markets. Among these are follow-up investments in Russia and in renewable energies.

The acquisition of Endesa assets in Europe and Viesgo are the material transactions expected to have a significant impact on E.ON’s cash flows in 2008.

Upon approval of the Supervisory Board on August 10, 2005, E.ON Pension Trust e.V. and Pensionsabwicklungstrust e.V. were formed, each with registered offices in Grünwald, Germany. The purpose of these trusts is the fiduciary administration of funds to provide for future pension benefit payments to employees of German group companies (the so-called “CTA model”). In 2006, E.ON made a contribution of €5.1 billion.

In January 2005, E.ON AG agreed to make a payment of GBP431 million (approximately €629 million) into the pension schemes for existing employees of the U.K. market unit. The payment, which was made in April 2005, improved the funding level of the plans (which had a funding deficit of GBP728 million (€1.1 billion) at the time of the last actuarial valuation in March 2004) and allowed for the merger of four previously autonomous sections covering Powergen, East Midlands Electricity Distribution plc, Midlands Electricity and TXU into a single pool.

E.ON expects that cash flow from operations will continue to be the primary source of funds for capital expenditures in its ongoing business (i.e., excluding acquisitions) and working capital requirements in 2008. E.ON believes that its cash flow and available liquid funds and credit lines will be sufficient to meet the anticipated cash needs of its ongoing business operations. In addition, various means of raising share capital and debt are available to E.ON.

Fair Value of Derivatives. E.ON has established risk management policies that allow the use of foreign currency, interest rate, equity, and commodity derivative instruments and other instruments and agreements to manage its exposure to market, currency, interest rate, commodity price, share price and counterparty risk. E.ON uses derivatives for both trading and non-trading purposes. Proprietary trading is conducted with the goal of improving operating results within defined limits in specified markets.

For information regarding E.ON’s trading activities, risk management and market factors impacting the fair values of contracts, see the respective market unit descriptions in “— Quantitative and Qualitative Disclosures about Market Risk” and Notes 30 and 31 of the Notes to Consolidated Financial Statements.

E.ON estimated the gross mark-to-market value of its commodity contracts as of December 31, 2007, which amounted to negative €352.6 million (2006: negative €1,132.1 million), using quoted market values where available and other valuation techniques where market data is not available. In such instances, E.ON uses alternative pricing methodologies, including, but not limited to, fundamental data models, spot prices adjusted for forward premiums/discounts and option pricing models. Fair value contemplates the effects of credit risk, liquidity risk and the time value of money on gross mark-to-market positions.

85 The following table shows the sources of prices used to calculate the fair value of commodity contracts at December 31, 2007. In many cases these prices are fed into option models that calculate a gross mark-to-market value from which fair value is derived after considering reserves for liquidity, credit, time value and model confidence.

SOURCE OF FAIR VALUE TABLE

Fair Value of Contracts at Period-End Source of Fair Value Fair Value Nominal Value (€ in millions) Prices actively quoted ...... (73.1) 10,480.7 Prices provided by other external sources or based on models and other valuation methods ...... (279.5) 46,723.0

The amounts disclosed above are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and E.ON’s risk management portfolio needs and strategies.

Off-Balance Sheet Arrangements E.ON uses certain off-balance sheet arrangements in the ordinary course of business, including guarantees, lines of credit, indemnification agreements and other arrangements. E.ON’s arrangements in each of these categories are described in more detail below. For additional information, see Note 27 of the Notes to Consolidated Financial Statements.

Contingent liabilities. With regard to the aforementioned arrangements and other underlying matters contingent liabilities have been arisen in the E.ON group. A contingent liability is a possible obligation that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of E.ON or a present obligation that arises from past events but is not recognized because it is not probable that an outflow or E.ON’s resources embodying economic benefits will be required to settle E.ON’s obligation or the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are generally not recognized on E.ON’s balance sheet. As of December 31, 2007, E.ON’s contingent liabilities amounted to €96 million (2006: €114 million). E.ON currently does not have reimbursement rights relating to the contingent liabilities disclosed.

Guarantees. E.ON has issued various direct and indirect guarantees to third parties, which require the guarantor to make contingent payments upon the occurrence of certain events or changes in an underlying instrument that is related to an asset, a liability or the equity of the guaranteed party, on behalf of both related parties and external entities. These consist primarily of financial guarantees and warranties.

The direct guarantees of E.ON also include items related to the operation of nuclear power plants. With the entry into force on April 27, 2002, of the German Nuclear Power Regulations Act (Atomgesetz, or “Tag”), as amended, and of the ordinance regulating the provision for coverage under the Atomgesetz (Atomrechtliche Deckungsvorsorge-Verordnung, or “AtDeckV”), as amended, German nuclear power plant operators are required to provide nuclear accident liability coverage of up to €2.5 billion per incident.

The coverage requirement is satisfied in part by a standardized insurance facility in the amount of €255.6 million. The institution Nuklear Haftpflicht Gesellschaft bürgerlichen Rechts (“Nuklear Haftpflicht GbR”) now only covers costs between €0.5 million and €15 million for claims related to officially ordered evacuation measures. Group companies have agreed to place their subsidiaries operating nuclear power plants in a position to maintain a level of liquidity that will enable them at all times to meet their obligations as members of the Nuklear Haftpflicht GbR, in proportion to their shareholdings in nuclear power plants.

86 To provide liability coverage for the additional €2,244.4 million per incident required by the above- mentioned amendments, E.ON Energie AG and the other parent companies of German nuclear power plant operators reached a Solidarity Agreement (Solidarvereinbarung) on July 11, July 27, August 21, and August 28, 2001. If an accident occurs, the Solidarity Agreement calls for the nuclear power plant operator liable for the damages to receive — after the operator’s own resources and those of its parent company are exhausted — financing sufficient for the operator to meet its financial obligations. Under the Solidarity Agreement, E.ON Energie’s share of the liability coverage currently stands at 42.0 percent (2006: 42.0 percent), with an additional 5.0 percent charge for the administrative costs of processing damage claims.

In accordance with Swedish law, the Nordic market unit has issued guarantees to governmental authorities. The guarantees were issued to cover possible additional costs related to the disposal of high-level radioactive waste and to nuclear power plant decommissioning. These costs could arise if actual costs exceed accumulated funds. In addition, Nordic is also responsible for any costs related to the disposal of low-level radioactive waste.

In Sweden, owners of nuclear facilities are liable for damages resulting from accidents occurring in those nuclear facilities and for accidents involving any radioactive substances connected to the operation of those facilities. The liability per incident as of December 31, 2007, was limited to SEK 3,063 million, or €324 million (2006: SEK 3,102 million, or €343 million), which amount must be insured according to the Law Concerning Nuclear Liability. The Nordic market unit has purchased the necessary insurance for its nuclear power plants. The Swedish government is currently in the process of reviewing the regulatory framework underlying the aforementioned liability limitation. The extent to which this review will result in changes to the Swedish regulations on the limitation of nuclear liability is still unclear at present.

Other than in the Central Europe and Nordic market units, there are no nuclear power plants in operation. Accordingly, there are no additional contingent liabilities comparable to those mentioned above.

Moreover, E.ON has commitments under which it assumes joint and several liability arising from its interests in certain German civil-law companies (“GbR”), non-corporate commercial partnerships and consortia in which it participates.

E.ON has recorded appropriate provisions for the direct and indirect guarantees according to the regulations of IFRS.

Indemnification Agreements. A number of the agreements governing E.ON’s divestiture of former subsidiaries and operations include indemnification clauses (Freistellungen) and other guarantees, certain of which are required by applicable local law. These arrangements generally comprise customary guarantees relating to the accuracy of representations and warranties, as well as indemnification provisions relating to contingent future environmental and tax liabilities.

In some cases the buyer of such former subsidiaries and operations is required to either share costs or cover a certain amount of costs before E.ON is required to make any payments. Certain of E.ON’s obligations under these arrangements are also covered by insurance and/or provisions established at the relevant divested companies.

Guarantees issued by companies that were later sold by E.ON AG (or VEBA AG and VIAG AG before their merger) have generally been assumed by the buyers of the relevant businesses in the final sales contracts in the form of indemnities, and are therefore no longer obligations of E.ON.

E.ON has recorded appropriate provisions with respect to all indemnities and other guarantees included in the sales agreements according to the regulations of IFRS.

Special Purpose Entities. E.ON applies the rules of SIC Interpretation 12 “Consolidation — Special Purpose Entities” for various companies identified as “Special Purpose Entities.” These Special Purpose Entities (SPE)

87 consolidated within the E.ON group as of December 31, 2007, which are not significant either individually or in the aggregate, are two jointly managed electricity generation companies, one real estate leasing company, one company operating in the gas storage business and one company managing investments.

As of December 31, 2007, these special purpose entities included in the E.ON group had total assets of €937 million and recorded earnings of €77 million before consolidation compared to €1,034 million in total assets and €43 million recorded earnings before consolidation at year-end 2006.

Contractual Obligations The following table summarizes E.ON’s contractual obligations as of December 31, 2007 and the related amounts falling due within one year and thereafter:

Payments Due by Period Less than More than Contractual Obligations Total 1 Year 1 Year (€ in millions) Financial Liabilities(1) ...... 21,271 5,510 15,761 Capital Lease Obligations ...... 193 39 154 Operating Leases ...... 883 148 735 Purchase Obligations ...... 267,695 32,572 235,123 Asset Retirement Obligations ...... 15,034 734 14,300 Pension Payments(2) ...... 9,725 867 8,858 Other Long-Term Obligations ...... 3,673 1,918 1,755 Total Contractual Obligations ...... 318,474 41,788 276,686

(1) Excludes capital lease obligations. (2) Estimated pension payments for 2008-2017.

As of December 31, 2007, the majority of the Company’s long-term contractual obligations arose under long-term purchase contracts in its core energy business, primarily for natural gas and electricity. For additional details on E.ON’s financial liabilities and lease obligations, see Notes 14, 26, 27 and 31 of the Notes to Consolidated Financial Statements. For information on pension obligations, see Note 24 of the Notes to Consolidated Financial Statements.

Purchase Obligations. E.ON’s long-term purchase obligations primarily relate to the procurement of gas (€244 billion) and electricity (€8 billion). E.ON Ruhrgas purchases nearly all of its natural gas under long-term supply contracts with international and German gas producers. For more detailed information, see “Operating and Financial Review and Prospects — Acquisitions and Dispositions — Pan-European Gas.” As is standard in the industry, the price E.ON Ruhrgas pays for gas under these contracts is calculated on the basis of complex formulas incorporating variables based upon current market prices for fuel oil, gas oil, coal and/or other competing fuels, with prices being automatically recalculated periodically. The contracts also generally provide for formal revisions and adjustments of the price and other business terms to reflect changes in the market environment (in many cases expressly including changes in the retail market for natural gas and competing fuels), generally providing that such revisions may only be made once every few years unless the parties agree otherwise. Claims for revision are subject to binding arbitration in the event the parties cannot agree on the necessary adjustments. The contracts also require E.ON Ruhrgas to pay for specified minimum quantities of gas even if it does not take delivery of such quantities, a standard gas industry practice known as “take or pay.” Certain of the Company’s other energy businesses also procure gas under similar arrangements. E.ON calculates the financial obligations arising from these contracts using the same principles that govern its internal budgeting process, as well as taking into account the specific take-or-pay obligations in the individual contracts.

88 Contractual obligations for the purchase of electricity arise in particular in connection with E.ON Energie’s interest in jointly operated power plants. The price E.ON pays for electricity generated by these jointly operated power plants is determined on the basis of production cost plus a profit margin that is generally calculated on the basis of an agreed return on capital.

E.ON Energie has also entered into long-term contractual obligations for the procurement of services in the area of reprocessing and temporary storage of spent nuclear fuel elements delivered through June 30, 2005. For additional details on these obligations, see “Business — Central Europe — Western Europe — Power Generation.”

E.ON’s purchase obligations also include obligations for as yet outstanding investments in connection with new power plant construction projects as well as modernizations of existing power plants, particularly at the Central Europe, Nordic and U.K. market units and at the power plant operator OGK-4 acquired in Russia. These commitments also include obligations concerning the construction of wind power plants.

Asset Retirement Obligations. In accordance with IFRS, E.ON’s asset retirement obligations are reported at the fair value of both legal and contractual obligations. These obligations primarily relate to retirement costs for decommissioning of nuclear power plants in Germany and Sweden, environmental remediation related to non-nuclear power plants, including removal of electricity transmission and distribution equipment, environmental remediation at gas storage and opencast mining facilities and the decommissioning of oil and gas field infrastructure. For additional details on E.ON’s asset retirement obligations, see Note 25 of the Notes to Consolidated Financial Statements.

Other Long-Term Obligations. E.ON’s Other Long-Term Obligations includes obligations arising out of option agreements that would require the Company to purchase shares from third parties. As of December 31, 2007, E.ON is a party to put option agreements related to certain of its acquisitions that allow minority shareholders in other companies controlled by E.ON Energie to sell these remaining stakes in these companies to E.ON at a time fixed in the put option agreement. As of December 31, 2007, the total amount potentially payable in connection with such obligations was €0.5 billion.

Additionally, E.ON has an obligation that arises from the network connection of offshore wind farms.

Other Long-Term Obligations in the table above do not include E.ON’s obligation toward the minority shareholders of the Russian power plant operator OGK-4 to offer to acquire their shares in that company. For more information on this, see Note 4 of the Notes to Consolidated Financial Statements.

For more information with regard to E.ON’s long-term contractual obligations, see Notes 27 of the Notes to Consolidated Financial Statements.

Quantitative And Qualitative Disclosures About Market Risk For information on the Company’s risk exposures and the risk management policies and procedures it follows, please refer to the “Summary of Significant Accounting Policies” in Note 2 of the Notes to Consolidated Financial Statements and Notes 30 and 31 of the Notes to Consolidated Financial Statements, which provides a summarized comparison of nominal values and fair values of financial instruments used by the Company for risk management purposes and other information relating to those instruments.

89 BUSINESS

Except as otherwise indicated, the information contained herein is current to December 31, 2007 and has not been updated since that date. See “Summary — Recent Developments”.

History and Development of the Company E.ON AG is a stock corporation organized under the laws of Germany. It is entered in the Commercial Register (Handelsregister) of the local court of Düsseldorf, Germany, under HRB 22315. E.ON’s registered office is located at E.ON-Platz 1, D-40479 Düsseldorf, Germany, telephone +49-211-45 79-0. E.ON’s agent in the United States is E.ON North America, Inc., 405 Lexington Avenue, New York, NY 10174.

The State of Prussia established VEBA in 1929 when it consolidated state-owned coal mining and energy interests (hence the original name VEBA, “Vereinigte Elektrizitäts- und Bergwerks-Aktiengesellschaft”). Ownership of VEBA was transferred from the dissolved Prussian state to Germany. VEBA was partially privatized in 1965, leaving the German government with a 40.2 percent share. After several subsequent offerings, privatization was completed in 1987 when the German government offered its remaining 25.5 percent share to the public. During and since the privatization process, VEBA AG evolved into a management holding company, providing strategic leadership and resource allocation for the entire Group.

On June 16, 2000, VEBA AG merged with VIAG AG, one of the largest industrial groups in Germany. VEBA AG was subsequently renamed E.ON AG.

The merger of VEBA and VIAG was legally implemented by merging VIAG AG into VEBA AG, with VEBA AG continuing as the surviving entity. The newly-merged company then received the new name E.ON AG. VIAG AG was dissolved and its assets and liabilities were transferred to VEBA AG. Simultaneously, each VIAG shareholder, with the exception of VEBA AG, received two shares of the new company in exchange for each five VIAG shares held. Pursuant to this exchange ratio, the former VIAG shareholders (with the exception of VEBA AG) therefore held 33.1 percent of the company immediately after the merger, while the former VEBA shareholders held 66.9 percent.

In 2002, E.ON acquired the London- and Coventry-based British utility Powergen. As agreed between E.ON and Powergen, upon satisfaction of all conditions E.ON implemented the transaction under an alternative U.K. legal procedure known as a “scheme of arrangement” instead of a tender offer. The scheme of arrangement provided for the acquisition of all outstanding Powergen shares by virtue of an order of the English courts following approval of the transaction at a meeting of Powergen shareholders convened by order of the court. Following the receipt of the necessary regulatory approvals, E.ON completed its acquisition of the Powergen Group, which is now wholly owned by E.ON, on July 1, 2002. In March 2003, E.ON transferred LG&E Energy (Powergen’s former principal U.S. operating subsidiary; now named E.ON U.S.) and its direct parent holding company to a direct subsidiary of E.ON AG. In July 2004, Powergen was renamed E.ON UK.

The total purchase price amounted to €7.6 billion (net of €0.2 billion cash acquired), and the assumption of €7.4 billion of debt. Goodwill in the amount of €8.9 billion resulted from the purchase price allocation. A significant deterioration in the market environment for the Powergen Group’s U.K. and U.S. operations triggered an impairment analysis as of the acquisition date that resulted in an impairment charge of €2.4 billion, thus reducing the amount of goodwill associated with the transaction to €6.5 billion.

For more information on E.ON UK and E.ON U.S., see “— Our Business — U.K.” and “— U.S. Midwest.”

E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas business in Germany in terms of gas sales. Prior to its acquisition by E.ON, Ruhrgas was owned by a number of holding companies, with indirect stakes dispersed among a number of major industrial and energy companies both within and outside Germany. E.ON completed its acquisition of these stakes in 2003, following a prolonged procedure marked by regulatory and legal challenges to E.ON’s acquisition of control over Ruhrgas. For more detailed information on that process, see “— Our Business — Pan European Gas.” The total cost of the transaction to

90 E.ON, including settlement costs and excluding dividends received on Ruhrgas shares owned by E.ON prior to its consolidation, amounted to €10.2 billion. Beginning as of February 1, 2003, E.ON fully consolidated Ruhrgas, which was renamed E.ON Ruhrgas on July 1, 2004.

In February 2006, we announced our intent to make an offer to acquire all the outstanding ordinary shares and ADSs of Endesa. The offer consisted of an offer to all holders of Endesa ordinary shares and a separate, concurrent offer to all holders of Endesa ordinary shares who are resident in the United States and to all holders of Endesa ADSs, wherever located. In April 2007 following competing bids by Acciona S.A. (“Acciona”) and Enel SpA (“Enel”), we entered into an agreement with Enel/Acciona to acquire, following any acquisition of Endesa by Enel/Acciona, a substantial package comprising the Enel subsidiary Enel Viesgo in Spain and power plants and other shareholdings of Endesa in Spain, France and Italy. On August 6, 2007, the European Commission approved the acquisition of Endesa Europe and Viesgo by us without any conditions.

On March 28, 2008, our Board of Management and Supervisory Board approved the acquisition from Acciona S.A. and Enel S.p.A of: (1) Enel Viesgo Generación, S.L. and Electra de Viesgo Distribución, S.L. (together, “Viesgo”) in Spain, a 1,600 megawatts (“MW”) generation capacity business and distribution business, from Enel; (2) 1,400 MW of generating capacity in Spain to be transferred from Endesa; (3) new build projects in Spain of 2,000 MW capacity by 2010; (4) Endesa’s stake in Endesa Italia, S.p.A., a 7,200 MW generation capacity business (of which based on the current assumptions approximately 70 percent will be for us) and future liquid natural gas regasification capacity; (5) Endesa’s stake in SNET in France with 2,500 MW capacity; and (6) certain assets in Poland and Turkey. The valuation process of the assets, which was agreed on April 2, 2007 as a basis for determining the final enterprise value of the asset package, has now been completed on schedule. The transaction value totals approximately €11.8 billion: €2 billion for Viesgo, €750 million for the additional Spanish generation assets, and €9.1 billion for Endesa Europe. On the basis of a consolidated net debt of approximately €2.9 billion, the equity purchased would amount to approximately €8.9 billion. The final net debt figure still has to be determined according to the provisions of the agreement of April 2, 2007. The completion of the transaction is likely to take place in the third quarter of 2008 once all permits are available.

Our Business We are the largest industrial group in Germany, measured on the basis of market capitalization at December 31, 2007. For the year ended December 31, 2007, we had sales of €68.7 billion with approximately 88,000 employees worldwide.

As of December 31, 2007, our core energy business was organized into the following five market units: Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest.

Central Europe. E.ON Energie AG, Munich, Germany (“E.ON Energie”) is the lead company of the Central Europe market unit. E.ON Energie is one of the largest non-state-owned European power companies in terms of electricity sales. E.ON Energie’s core business consists of the ownership and operation of power generation facilities and the transmission, distribution and sale of electricity and, to a lesser extent, gas and heat, to interregional, regional and municipal utilities, traders and industrial, commercial and residential customers. Furthermore, E.ON Energie operates waste incineration facilities. The Central Europe market unit owns interests in and operates power stations with a total installed capacity of approximately 37,200 MW, of which Central Europe’s attributable share is approximately 28,500 MW (not including mothballed, shutdown and cold reserve plants). In 2007, E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in Germany. In 2007, the Central Europe market unit recorded revenues of €32.0 billion and an adjusted EBIT of €4.7 billion. For a definition of adjusted EBIT, see “Summary — Summary Consolidated Financial Data.”

Pan European Gas. E.ON Ruhrgas AG, Essen, Germany (“E.ON Ruhrgas”) is the lead company of the Pan-European Gas market unit and is responsible for all of E.ON’s non-retail gas activities in continental Europe. E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas company in

91 Germany in terms of gas sales, with 712.8 billion kilowatt hours (“kWh”) of gas sold in 2007. E.ON Ruhrgas’ principal business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas purchases nearly all of its natural gas from producers in six countries: Russia, Norway, the Netherlands, Germany, the United Kingdom and Denmark. E.ON Ruhrgas sells this gas to supra-regional and regional distributors, municipal utilities and industrial customers in Germany and increasingly also delivers gas to customers in other European countries. In addition, E.ON Ruhrgas is active in gas transmission within Germany via a network of approximately 11,611 kilometers (“km”) of gas pipelines and operates a number of underground storage facilities in Germany. E.ON Ruhrgas also holds numerous stakes in German and other European gas transportation and distribution companies, as well as a 6.4 percent shareholding in OAO Gazprom, Russia’s main natural gas exploration, production, transportation and marketing company. In 2007, the Pan-European Gas market unit recorded revenues of €22.7 billion and adjusted EBIT of €2.6 billion.

U.K. E.ON UK plc (formerly Powergen UK plc), Coventry, United Kingdom (“E.ON UK”) is the lead company of the U.K. market unit and is one of the leading integrated electricity and gas companies in the United Kingdom. E.ON UK and its associated companies are involved in electricity generation, distribution, retail and trading. As of December 31, 2007, E.ON UK owned or through joint ventures had an attributable interest in 10,581 MW of generation capacity. E.ON UK served approximately 8.0 million electricity and gas customer accounts at December 31, 2007 and its Central Networks business served 4.9 million customer connections. In 2007, the U.K. market unit recorded sales of €12.6 billion and an adjusted EBIT of €1.1 billion.

Nordic. E.ON Nordic AB, Malmö, Sweden (“E.ON Nordic”) is the lead company of the Nordic market unit. E.ON Nordic’s principal business, carried out mainly through E.ON Sverige AB (“E.ON Sverige”), is the generation, distribution, sale and trading of electricity, gas and heat and waste, mainly in Sweden. E.ON Sverige is the second-largest Swedish utility (on the basis of electricity sales and production capacity). E.ON Nordic is the largest shareholder in E.ON Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent voting interest. Statkraft (“Statkraft” refers to Statkraft AS and its consolidated subsidiaries), the other shareholder in E.ON Sverige and E.ON AG have on October 12, 2007 signed a letter of intent stating that E.ON AG will take over Statkraft’s 44.6 percent interest in E.ON Sverige’s share capital in the second or third quarter of 2008. As of December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power stations with a total installed capacity of approximately 18,300 MW, of which its attributable share was approximately 7,400 MW (not including mothballed and shutdown power plants). In 2007, E.ON Nordic recorded sales of €3.3 billion, and adjusted EBIT of €670 million.

U.S. Midwest. E.ON U.S. LLC, Louisville, USA (“E.ON U.S.”) is the lead company of the U.S. Midwest market unit. E.ON U.S. is a diversified energy services company with businesses in power generation, retail gas and electric utility services, as well as asset-based energy marketing. E.ON U.S.’s power generation and retail electricity and gas services are located principally in Kentucky, with a small customer base in Virginia and Tennessee. As of December 31, 2007, E.ON U.S. owned or controlled aggregate generating capacity of approximately 7,500 MW. In 2007, E.ON U.S. served more than one million customers. In 2007, the U.S. Midwest market unit recorded sales of €1.8 billion, and adjusted EBIT of €388 million.

Corporate Center. The Corporate Center consists of E.ON AG itself, those interests owned directly and indirectly by E.ON AG that have not been allocated to any of the other segments, including its remaining telecommunications interests (until their disposal), and for 2007 the newly acquired companies Airtricity Inc. and Airtricity Holdings (Canada) Ltd. (collectively “Airtricity”), ENERGI E2 Renovables Ibéricas S.L.U. (“E2-I”) and OAO OGK-4 (“OGK-4”). The Corporate Center’s results also reflect consolidation effects at the Group level, including the elimination of intersegment sales.

New Market Units Since January 1, 2008, E.ON has been organized into nine different market units having added the Energy Trading, Italy, Russia and Climate & Renewables market units. If the pending acquisition of Viesgo and additional generation capacity in Spain from Endesa is successful, these operations are expected to be organized

92 in a new tenth market unit. For information about the planned acquisition, see “Business — History and Development of the Company.” Until the end of 2008, the results of each of the new market units other than Energy Trading will be reported as part of the Corporate Center segment; Energy Trading’s results will be reported separately. The detailed discussion of each of the five existing market units that follows is based on their operations as of year-end 2007, and thus does not fully reflect intra-Group transfers of assets or operations to the new market units.

Energy Trading. E.ON Energy Trading AG, Germany (“EET”) is the lead company of the Energy Trading market unit. EET began operations in January 2008, and combines all our European trading activities, including those relating to electricity, gas, coal, oil and CO2 emission allowances. We have created EET with the goal of taking advantage of the opportunities created by the increasing integration of Europe’s power and gas markets and those present in global commodity markets.

Russia. E.ON Russia Power, Russia (“E.ON Russia”) is the lead company of the E.ON Russia market unit. E.ON Russia oversees our power business in Russia. In October 2007, we acquired a majority stake in the Russian power generation company OGK-4. E.ON now holds 76.1 percent of OGK-4’s capital stock. OGK-4 operates five conventional power stations at different locations with a total installed capacity of 8.6 gigawatts (“GW”). For additional details on the OGK-4 acquisition, see “History and Development of the Company.”

Italy. E.ON Italia S.p.A., Italy (“E.ON Italia”) is the lead company of the Italy market unit. E.ON Italia manages our power and gas business in Italy, and is active in Italy’s wholesale power and gas markets and in natural gas sales. The expected acquisition of the activities of Endesa in Italy will give us a total of about 5,000 MW of generating capacity in Italy. For information about the planned acquisition, see “History and Development of the Company.”

Climate & Renewables. E.ON Climate & Renewables GmbH, Germany (“C&R”) is the lead company of the Climate & Renewables market unit. C&R is responsible for managing and expanding our global renewables business and for coordinating climate-protection projects. C&R has about 760 MW of generating capacity in Europe and approximately 250 MW in North America.

The following table sets forth the sales of E.ON’s market units (as well as the Corporate Center) for 2007 and 2006:

2007 2006 (€ in millions) % (€ in millions) % Central Europe ...... 32,029 46.6 27,197 42.5 Pan-European Gas ...... 22,745 33.1 22,947 35.8 U.K...... 12,584 18.3 12,518 19.5 Nordic(1) ...... 3,339 4.9 2,827 4.4 U.S. Midwest(1) ...... 1,819 2.6 1,930 3.0 Corporate Center(1)(2)(3) ...... (3,785) (5.5) (3,328) (5.2) Total Sales ...... 68,731 100.0 64,091 100.0

(1) Excludes the sales of certain activities now accounted for as discontinued operations. For more details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for each period and Note 4 of the Notes to Consolidated Financial Statements. (2) Includes primarily the parent company and effects from consolidation, as well as the results of certain other interests, as noted above. (3) Excludes intercompany sales.

Most of E.ON’s operations are in Germany. German operations produced 59.1 percent of E.ON’s revenues (measured by location of operation) in 2007 (2006: 60.8 percent). E.ON also has a significant presence outside Germany representing 40.9 percent of revenues by location of operation for 2007 (2006: 39.2 percent). In 2007,

93 53.7 percent (2006: 54.5 percent) of E.ON’s revenues were derived from customers in Germany and 46.3 percent (2006: 45.5 percent) from customers outside Germany. For more details about the segmentation of E.ON’s revenues by location of operation and customers for the years 2007 and 2006, see Note 33 of the Notes to Consolidated Financial Statements. At December 31, 2007, E.ON had 87,815 employees, approximately 39.4 percent of whom were employed in Germany.

Central Europe Overview The Central Europe market unit is led by E.ON Energie. E.ON Energie, which is wholly owned by E.ON, is one of the largest non-state-owned European power companies in terms of electricity sales. E.ON Energie had revenues of €32.0 billion, €24.9 billion of which was generated from German customers and adjusted EBIT of €4.7 billion in 2007. E.ON Energie, together with E.ON Ruhrgas and E.ON Nordic, is responsible for all of E.ON’s energy activities in Germany and continental Europe and is one of the four interregional electric utilities in Germany that are interconnected in the western European power grid.

E.ON Energie is embarking on a significant program to build new generating capacity in many of the countries in which it operates: • Construction is underway on new facilities at Irsching, Germany (a 530 MW advanced natural gas plant to be built in cooperation with Siemens AG, scheduled to begin operations in 2011 and a new 800 MW combined cycle gas fired plant, which is scheduled to begin operations in 2009), Datteln, Germany (a 1,100 MW hard coal plant, scheduled to begin operations in 2011) and Livorno Ferraris, Italy (an 800 MW natural gas plant, scheduled to begin operations in 2008 and expected to form part of the new market unit Italy). • In addition, E.ON Energie plans to build new plants at the location of Staudinger, Germany (a 1,100 MW hard coal plant), Maasvlakte, the Netherlands (a 1,100 MW hard coal plant) and in the harbor of Antwerp, Belgium (a 1,100 MW hard coal plant), if all requirements are met. E.ON also plans to build the world’s first large coal fired power plant with a target efficiency of more than 50 percent and a capacity of about 550 MW in Wilhelmshaven, Germany. • E.ON Energie also intends to erect two 400 MW gas fired combined cycle power plants in Gönyü, Hungary, and Malzenice, Slovakia, both of which are expected to start operations in 2010, and may build other power plants in Eastern Europe.

For more information, see “Operating and Financial Review and Prospects — Liquidity and Capital Resources — Expected Investment Activity.”

E.ON Energie’s company structure reflects its operations in western and eastern Europe and, in addition, reflects the individual segments of its electricity business: generation, transmission, distribution, sales and trading. The following chart shows the major subsidiaries of the Central Europe market unit as of December 31, 2007, their respective fields of operation and the percentage of each held by E.ON Energie as of that date.

Central Europe Market Unit Holding Company E.ON Energie AG • Leading entity for the management and coordination of the group activities. • Centralized strategic, controlling and service functions.

94 Western Europe Conventional Power Plants E.ON Kraftwerke GmbH (100%) • Power generation by conventional power plants. • Renewables. • District heating. • Industrial power plants.

Nuclear Power Plants E.ON Kernkraft GmbH (100%) • Power generation by nuclear power plants.

Hydroelectric Power Plants E.ON Wasserkraft GmbH (100%) • Power generation by hydroelectric power plants.

Waste Incineration BKB AG (100%) • Energy generation from waste incineration.

E.ON Benelux Holding B.V. (100%) • Power generation by conventional power plants in the Netherlands. • District heating in the Netherlands. • Sales of power and gas in the Netherlands.

Transmission E.ON Netz GmbH (100%) • Operation of high voltage grids (380 kilovolt-110 kilovolt). • System operation, including provision of regulating and balancing power.

Distribution of Electricity and Gas Seven regional grid companies across Germany (shareholding percentages range from 62.8 to 100.0 percent) • Distribution of electricity and gas to retail customers.

Sales and Trading of Electricity, Gas and Heat E.ON Sales & Trading GmbH (100%)(1) • Supply of electricity and energy services to large industrial customers, as well as to regional and municipal distributors. • Centralized wholesale functions. • Optimization of energy procurement costs.

(1) Since December 20, 2007, E.ON Energy Trading AG

95 • Physical energy trading and trading of energy-based financial instruments and related risk management. • Optimization of the value of the power plants’ assets in the market place. • Emissions trading

Seven regional energy companies across Germany (shareholding percentages range from 62.8 to 100.0 percent) • Sales of electricity, gas, heat and water to retail customers. • Ownership and operation of regional grid companies in compliance with the Energy Law of 2005. • Energy support services. • Waste incineration.

E WIE EINFACH Strom & Gas GmbH (100%) • Sales of electricity and gas to residential customers and small and medium enterprises across Germany.

Ruhr Energie GmbH (100%) • Customer service and electricity and heat supply to utilities and industrial customers in the Ruhr region.

Eastern Europe E.ON Hungária Energetikai ZRt. (100%) • Generation, distribution and sales of electricity and gas in Hungary through its group companies.

E.ON Czech Holding AG (100%) • Generation, distribution and sales of electricity and gas in the Czech Republic through its group companies.

E.ON Energie România S.A. (90.2%) • Distribution and sales of electricity in Romania through its group companies.

E.ON Bulgaria EAD (100%) • Distribution and sales of electricity in Bulgaria through its group companies.

Západoslovenská energetika a.s. (49.0% held at equity) • Distribution and sales of electricity in Slovakia through its group companies.

Consulting and Support Services E.ON Engineering GmbH (57.0%)(2) • Provision of consulting and planning services in the energy sector to companies within the Group and third parties. • Marketing of expertise in the area of conventional and renewable power generation and cogeneration, as well as a pipeline business.

(2) The remaining 43.0 percent is held by E.ON Ruhrgas.

96 • E.ON IS GmbH (30.0%)(3) • Provision of information technology services to companies within the Group and third parties.

E.ON Facility Management GmbH (100%) • Infrastructure services.

For financial reporting purposes, the Central Europe market unit comprises four business units: Central Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power also includes the results of E.ON Benelux Holding B.V. (“E.ON Benelux”), which operates power generation, district heating and gas and electricity retail businesses in the Netherlands. The Central Europe West Gas business unit reflects the results of the regional distribution of gas and the gas retail business in Germany. The Central Europe East business unit primarily includes the results of the regional distribution companies in Bulgaria, the Czech Republic, Hungary, Romania and Slovakia (with the Slovak activities being valued under the equity method given E.ON Energie’s minority interest). Other/Consolidation primarily includes the results of E.ON Energie’s retail business in Italy, other national and international shareholdings, service companies and E.ON Energie AG, as well as intrasegment consolidation effects.

Operations Electricity generated at power stations is delivered to customers through an integrated transmission and distribution system. The principal segments of the electricity industry in the countries in which E.ON Energie operates are:

Generation: the production of electricity at power stations; Transmission: the bulk transfer of electricity across an interregional power grid, which consists mainly of overhead transmission lines, substations and some underground cables (at this level there is a market for bulk trading of electricity, through which sales and purchases of electricity are made between generators, regional distributors, and other suppliers of electricity); Distribution: the transfer of electricity from the interregional power grid and its delivery, across local distribution systems, to customers; Sales: the sale of electricity to customers; and Trading: the buying and selling of electricity and related products for purposes of portfolio optimization, arbitrage and risk management.

E.ON Energie and its associated companies are actively involved in all segments of the electricity industry. Its core business consists of the ownership and operation of power generation facilities and the transmission, distribution and sale of electricity and, to a lesser extent, gas and heat, to interregional, regional and municipal utilities, traders and industrial, commercial and residential customers. Furthermore, E.ON Energie operates waste incineration facilities.

(3) The remaining 70.0 percent is held by E.ON AG.

97 The following table sets forth the sources of E.ON Energie’s electric power in kWh in 2007 and 2006:

2007 2006 % Sources of Power million kWh million kWh Change Own production ...... 134,531 131,304 +2.5 Purchased power ...... 192,635 149,867 +28.5 from power stations in which E.ON Energie has an interest of 50 percent or less ...... 8,301 12,287 -32.4 from other suppliers ...... 184,334 137,580 +34.0 Total power procured(1) ...... 327,166 281,171 +16.4 Power used for operating purposes, network losses and pump storage ...... (13,469) (12,951) +4.0 Total ...... 313,697 268,220 +17.0

(1) Excluding physically-settled electricity trading activities at E.ON Sales & Trading GmbH (“EST”). EST’s physically-settled electricity trading activities amounted to 141,797 million kWh and 161,892 million kWh in 2007 and 2006, respectively.

In 2007, E.ON Energie procured a total of 327.2 billion kWh of electricity, including 13.5 billion kWh used for operating purposes, network losses and pumped storage. E.ON Energie purchased a total of 8.3 billion kWh of power from power stations in which it has an interest of 50 percent or less. In addition, E.ON Energie purchased 184.3 billion kWh of electricity from other utilities, 14.8 billion kWh of which were from Vattenfall Europe, the eastern German interregional utility, for redistribution by eastern German regional distributors. In addition, E.ON Energie purchased power from local generators in Hungary, the Czech Republic, Bulgaria and Romania totaling 36.5 billion kWh. The increase in purchased power compared to 2006 primarily reflects the purchase of significantly higher volumes due to an increase in trading activities (approximately 28 TWh), the purchase of higher volumes of electricity from renewable resources, which is regulated under Germany’s Renewable Energy Law (as defined in “— Regulatory Environment”) (approximately 15 TWh) and the contribution of Dalmine Energie S.p.A. (“Dalmine”) in Italy, first consolidated in December 2006 (approximately 4 TWh).

E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in Germany in 2007. Electricity accounted for 80.0 percent of E.ON Energie’s 2007 sales (2006: 75.3 percent), gas revenues represented 13.8 percent (2006: 17.6 percent), district heating 2.0 percent (2006: 2.2 percent) and other activities 4.2 percent (2006: 4.9 percent).

The following table sets forth data on the sales of E.ON Energie’s electric power in 2007 and 2006:

% Total 2007 Total 2006 Change in Sale of Power(1) to million kWh million kWh Total Non-consolidated interregional, regional and municipal utilities ...... 185,934 145,688 +27.6 Industrial and commercial customers ...... 83,687 77,238 +8.3 Residential and small commercial customers ...... 44,076 45,294 -2.7 Total ...... 313,697 268,220 +17.0

(1) Excluding physically-settled electricity trading activities at EST. EST’s physically-settled electricity trading activities amounted to 141,797 million kWh and 161,892 million kWh in 2007 and 2006, respectively.

The increase in the total sale of power is mainly attributable to higher volumes sold to sales and trading partners and to higher deliveries to the network of electricity generated from renewable resources pursuant to Germany’s Renewable Energy Law. Furthermore the sales volumes include those of Italy’s Dalmine, which became a consolidated E.ON Energie company in December 2006. For further information, see “Operating and Financial Review and Prospects — Results of Operations.

98 The following table sets forth data on the gas sales of E.ON Energie in 2007 and 2006:

% Total 2007 Total 2006 Change in Sale of Gas to million kWh million kWh Total Non-consolidated interregional, regional and municipal utilities ...... 27,544 30,631 -10.1 Industrial and commercial customers ...... 59,474 53,208 +11.8 Residential and small commercial customers ...... 39,179 44,629 -12.2 Total ...... 126,197 128,468 -1.8

The decline in gas sales volumes was primarily attributable to the unseasonably warm weather across many parts of Europe during the first four months of 2007. Although the inclusion of newly consolidated companies, mainly Jihoceska plynárenská a.s. (“JCP”) of the Czech Republic (since September 2006) and Dalmine in Italy (since December 2006), had a positive effect, overall gas sales volumes declined by 1.8 percent.

Western Europe Power Generation General. In Germany, E.ON Energie owns interests in and operates electric power generation facilities with a total installed capacity of approximately 34,800 MW, its attributable share of which is approximately 26,300 MW (not including mothballed, shutdown or reduced power plants). The German power generation business is subdivided into four units according to fuels used: E.ON Kraftwerke GmbH owns and operates the power stations using fossil fuel energy sources, as well as renewable generation facilities, E.ON Kernkraft owns and operates the nuclear power stations, E.ON Wasserkraft GmbH owns and operates the hydroelectric power plants and BKB AG owns and operates the waste incineration plants.

In the Netherlands, E.ON Energie operates, through its subsidiary E.ON Benelux, hard coal and natural gas power plants for the supply of electricity and heat to bulk customers and utilities. In 2007, it had a total installed generation capacity of approximately 1,900 MW.

Based on the consolidation principles under IFRS, E.ON Energie reports 100 percent of revenues and expenses from majority-owned power plants in its consolidated accounts without any deduction for minority interests. Conversely, 50 percent and minority-owned power plants (at least 20 percent) are accounted for by the equity method. Power generation capacity in jointly owned plants is generally reported based on E.ON’s ownership percentage.

Germany. E.ON Energie’s German plants generate electricity primarily with nuclear power, bituminous coal (commonly referred to as “hard coal”), lignite, gas, fuel oil and water. The existing nuclear and hydroelectric power plants are E.ON Energie’s source of power with the lowest variable costs and, together with lignite-based power plants, are used mainly to cover the base load. Hard coal is utilized mainly for middle load, while the other energy sources are used primarily for peak load.

Nuclear Power. E.ON Energie operates its German nuclear power plants through E.ON Kernkraft. These nuclear power plants are required to meet applicable German safety standards, which are among the most stringent standards in the world (see “— Environmental Matters — Germany”).

Operators of nuclear power plants are required under German nuclear law to establish sufficient financial provisions for obligations that arise from the use of nuclear power. In accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”) and IFRIC 1, these provisions include: (1) provisions for management of non-contractual obligations based on experts’ opinions and estimates, and (2) provisions for contractual obligations based on concluded contracts. All nuclear provisions include expenses for management of spent nuclear fuel rods, disposal of contaminated operating waste and the decommissioning of nuclear plants. At year-end 2007, E.ON Energie had provisions in its consolidated accounts for these purposes equal to €8.9 billion

99 for management of non-contractual obligations and €3.3 billion for contractual obligations. In addition to obligations relating to the German nuclear law, E.ON Energie had to establish provisions for the disposal and dismantling of non-nuclear plant components according to general applicable law.

E.ON Kernkraft purchases uranium and fuel elements for its nuclear power plants from domestic and international suppliers, primarily under long-term contracts. E.ON Energie considers the supply of uranium and fuel elements on the world market to be generally adequate.

In May 1995, PreussenElektra, which formed part of E.ON Energie in 2000, decided to shut down its nuclear power plant at Würgassen for economic reasons and, in October 1995, it applied for and received permission from the German authorities to decommission and dismantle the Würgassen plant in accordance with German nuclear energy legislation. E.ON Energie expects the decommissioning of Würgassen, which began in October 1995, to last until approximately 2015. In 2000, E.ON Energie also decided to shut down the nuclear power plant Stade. In July 2001, E.ON Kernkraft filed an application with the Lower Saxonian Ministry of Environment to decommission and dismantle Stade and received the relevant approval in September 2005. Stade was shut down in November 2003, and E.ON Energie expects its decommissioning to last until approximately 2015. E.ON Energie has established a provision for non-contractual obligations of €1.1 billion for the decommissioning of Würgassen and Stade, including the management of spent nuclear fuel rods and the dismantling of the plants. E.ON Energie has also established a provision of €0.3 billion for contractual obligations.

The current German Nuclear Power Regulations Act (Atomgesetz, or “AtG”) took effect in April 2002.

Among other things, it provides as follows: • Nuclear Phase-out: The operators of the nuclear plants have agreed to a specified number of operating kWh for each nuclear plant. This number has been calculated on the basis of 32 years of plant operation using a high load factor. The operators may trade allocated kWh among themselves. This means that if one nuclear plant closes before it has produced the allocated amount of kWh, the remaining kWh may be transferred to another nuclear power plant. • Termination of Fuel Reprocessing: The transport of spent fuel elements for reprocessing was allowed until June 30, 2005. Following this deadline, the operators must store spent fuel in interim facilities on the premises of the nuclear plants. Such storage requires the approval and construction of interim storage facilities. E.ON has constructed five interim on-site storage facilities. Two of these, Grafenrheinfeld and Grohnde, went into operation in the first quarter of 2006, while the remaining three interim on-site storage facilities in Brokdorf, Isar and Unterweser went into operation in the first half of 2007.

As part of the agreement, the German federal government has agreed not to institute any future changes in German tax law which discriminate against nuclear power operations or other measures creating economic disadvantages in comparison with other forms of power generation.

The Company considers its provisions with respect to nuclear power operations to be adequate with respect to the costs of implementing the agreement. E.ON Energie has no plans to construct any new nuclear power plants in Germany.

Hard Coal. In 2007, approximately 30 percent of the hard coal used by E.ON Energie’s German operations was mined in Germany. Traditionally, hard coal is mined in Germany under much more difficult conditions than in other countries. Therefore, German coal production costs are substantially above world market levels, and E.ON Energie strongly believes they will continue to remain high. Although electricity producers were in the past required to purchase German coal, they are now free to purchase coal from any source. To encourage the purchase of German coal, the German federal government has been paying direct subsidies to German producers enabling them to offer domestic coal at world market prices, although it is now in the process of reducing such subsidies. Due to high production costs and the reduction in subsidies, the volume of German coal production has

100 shown a relatively steady decline in the past and is expected to continue to decline further. However, E.ON Energie expects that adequate supplies of imported coal for its operations will be available on the world coal market at acceptable prices. Hard coal is generally available from multiple sources, though prices are determined on international commodities markets and are therefore subject to fluctuations. E.ON Benelux also uses imported hard coal in its power plants.

Lignite. German lignite, also known as brown coal, has approximately one-third of the heating value of hard coal. E.ON Energie participates in lignite-based energy generation in western Germany through BKB Aktiengesellschaft (“BKB”) and in eastern Germany through Kraftwerk Schkopau GbR and a portion of one unit of Kraftwerk Lippendorf. Lignite is a readily available domestic fuel source that E.ON Energie obtains from its own reserves or under long-term contracts with German producers. The price of lignite is not generally volatile and is generally determined by reference to published indices in Germany. However, the price can fluctuate based on the underlying price of hard coal in global commodities markets.

Gas and Oil. In Germany, the price of natural gas is linked to the price of oil and other competing fuels. This mechanism has been enforced in order to reduce the influence of, and dependence on, gas-producing countries. Only about 16 percent of gas demand in Germany is satisfied by German deposits, while about 84 percent is satisfied through imports from foreign producers, primarily from Russia, Norway and the Netherlands. For its gas-fired power plants, E.ON Energie purchases gas from E.ON Ruhrgas and other international suppliers, mainly under short-term contracts. Fuel oil power plants are only used for peak load operations. E.ON Energie purchases its fuel oil from traders or directly from a number of oil companies. As with natural gas, the price of fuel oil depends on the price of crude oil. E.ON Benelux purchases predominantly Dutch gas under one-year contracts for its gas-fired power plants.

Water. This domestic source of energy is primarily available in southern Germany due to the presence of mountains and rivers. The variable costs of production are extremely low in the case of run-of-river plants and consequently, these plants are used to cover base load requirements. Storage and pump storage facilities are used to meet peak demand and for back-up power purposes.

Waste Incineration. E.ON Energie also has a waste incineration business, led by BKB and E.ON Westfalen Weser. In 2007, incinerated waste volumes totaled approximately 2.5 million tons. The waste incineration plants have a total power generation capacity of 250 MW of electricity, of which 164 MW is attributable to E.ON Energie.

Demand for power tends to be seasonal, rising in the winter months and typically resulting in additional electricity sales by E.ON Energie in the first and fourth quarters. E.ON Energie believes it has adequate sources of power to meet foreseeable increases in demand, whether seasonal or otherwise. In order to benefit from economies of scale associated with large stations, E.ON Energie has built large capacity power station units in conjunction with other utilities where it does not require all of the electricity produced by such plants. In these cases, the purchase price of electricity is determined by the production cost plus a negotiated fee.

Although E.ON’s power plants are maintained on a regular basis, there is a certain risk of failure for power plants of every fuel type. Depending on the associated generation capacity, the length of the outage and the cost of the required repair measures, the economic damage due to such failure can vary significantly. In order to meet contractual commitments, electricity which cannot be generated at these plants has to be bought from other generators or has to be generated from more expensive plants. Thus, power plant outages can negatively affect the market unit’s financial and operating results.

Transmission The German power transmission grid of E.ON Energie, which operates with voltages of 380, 220 and 110 kilovolts, has a coverage area of nearly 200,000 km2. The 380 and 220 kilovolts extra high voltage lines have a system length of close to 11,000 km, whereas the high voltage lines have a system length of over 30,000 km. The grid is interconnected domestically, and with the western European power grid with links to the Netherlands,

101 Austria, Denmark and Eastern Europe and with other power grids in Germany. The system is mainly operated by E.ON Netz. The network of E.ON Netz allows long-distance power transport (380 and 220 kilovolts) at low transmission losses and covers about 40 percent of the surface area of Germany. This system is operated from two main system control centers, one in Lehrte near Hanover and one in Dachau near Munich, and from several regional control and service units at decentralized locations within the E.ON Netz grid area.

A new challenge to network operators are the ambitious construction plans for offshore windfarms. Transmission system operators are legally bound to connect those offshore windfarms, the construction of which is expected to have been started by 2011, to the existing transmission system onshore through new powerlines. E.ON Netz will have to build powerlines primarily in the area of the North Sea, starting the construction concurrently with the building of the wind farms. Costs for investments will initially have to be born by E.ON Netz, but are expected to be distributed among all four transmission system operators and finally be included in network charges.

Access to E.ON Energie’s power transmission grid is open to all potential users. The Company believes its usage fees and conditions comply with existing German regulations governing grid access. For further information about the impact of recent regulatory developments on E.ON Energie’s transmission business and results, see “— Regulatory Environment” and “Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2006 Compared with Year Ended December 31, 2005 — Central Europe.”

The Baltic Cable links the transmission grid of E.ON Energie to Scandinavia. For details, see “— Nordic — Regulated Business — Electricity Distribution.”

Distribution Electricity. The German utilities historically established defined supply areas which were coextensive with their distribution grids. The following map shows E.ON Energie’s current distribution area in Germany through its majority shareholdings in regional energy distribution companies as of December 31, 2007:

E.ON Hanse E.ON edis/E.ON Hanse (73.8 %)

E.ON edis (70.0 %) E.ON Westfalen Weser E.ON Avacon (65.0 %) (62.8 %)

E.ON Mitte E.ON Thüringer (73.3 %) Energie (77.0 %)

E.ON Bayern (100.0 %) Majority shareholdings

102 To meet the requirements of legal regulations and increased competition, E.ON Energie and its seven regional energy companies have started the structural project “regi.on”. With the target of increasing enterprise values and maintaining a sustainable basis for competitiveness, the goals of the project include for example the standardization and harmonization of processes as well as the bundling of overall functions in separate organizations.

In order to realize the targets of the “regi.on” project the network operating companies which have already been spun off (“small DSO”) are planned to be re-integrated into the respective regional energy company. Within these companies an explicit and non-overlapping organizational separation of the DSO, grid operation and technical grid service (TNS) is planned. To meet legal requirements, the sales units will be spun off in separate organizations. For more information, see “— Sales” below.

Access to E.ON Energie’s power distribution grid is open to all potential users. The Company believes its usage fees and conditions comply with existing German regulations governing grid access. For further information about the impact of recent regulatory developments on E.ON Energie’s distribution business and results, see “— Regulatory Environment” and “Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2006 Compared with Year Ended December 31, 2005 — Central Europe.”

In January 2007, a severe storm damaged the power grid of E.ON Energie in some areas of Germany. For more information, see “Risk Factors.”

Gas. E.ON Energie’s distribution subsidiaries supply natural gas to households, small businesses and industrial customers in many parts of Germany. Similar to “Electricity” above, E.ON Energie’s regional distribution companies had to submit their calculated gas network charges to Germany’s energy regulator by the end of January 2006. The energy regulator approved reduced charges for each of E.ON Energie’s network operators between September and November 2006. For the next regulatory period beginning in April 2008, the network operators submitted applications for charges in September 2007. For more information, see “— Regulatory Environment — Germany: Gas — Gas Network Charges.”

Sales In Germany, E.ON Energie supplies electricity, gas and heat, mainly through the regional energy companies in which it holds majority interests. As described below, E.ON Energie’s wholly-owned subsidiary EST supplies electricity to these regional energy companies as well as to large municipal distributors and very large national and international industrial customers.

E.ON Energie’s customers are interregional, regional and municipal utilities, traders, industrial and commercial customers and, through regional distributors, residential and small commercial customers predominantly in those parts of Germany highlighted on the map shown in “Distribution” above. E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in Germany in 2007. Due to competitive environment E.ON Energie lost approximately 300,000 private customers in its power and gas business with its regional distributors. In February 2007, E.ON Energie launched the new company E WIE EINFACH Strom & Gas GmbH (“EWI”), which attracted more than 450,000 residential and small business power and gas customers in the mass market throughout Germany in 2007. The introduction of EWI allowed us to increase our overall number of residential customers in a highly competitive market.

103 Electricity. The following table sets forth the sale of electric power by E.ON Energie’s German companies (excluding that used in physically settled trading activities), primarily in Germany, in 2007 and 2006:

% 2007 2006 Change in Sale of Power to million kWh million kWh Total Non-consolidated interregional, regional and municipal utilities ...... 171,375 135,112 +26.8 Industrial and commercial customers ...... 55,071 53,896 +2.2 Residential and small commercial customers ...... 28,722 29,736 -3.4 Total(1)(2) ...... 255,168 218,744 +16.7

(1) The increase in the total sale of power mainly reflects higher deliveries of renewable electricity regulated by Germany´s Renewable Energy Law, as well as higher volumes sold to sales and trading partners. (2) Total sales of power includes sales of EST in European countries other than Germany.

The supply contracts under which E.ON Energie’s regional energy companies (all are majority-owned) regularly order their required load for upcoming years have historically had relatively long terms. Typical supply contracts now last for one to three years. Potential alternative sources of electricity include the purchase of electricity from other utilities and auto-generation by municipalities, regional distributors or industrial customers. The regional distributors’ contracts with municipal utilities contain varying terms and conditions.

In the context of the “regi.on” project (see “Distribution” above), E.ON Energie intends to bundle the tasks of the regional energy companies concerning sales administration relating to marketing, product development and procurement in a company managing all sales activities: E.ON Vertrieb Deutschland GmbH ( “EVD”). Additionally EVD is also expected to direct the national wholesale sales activities of E.ON Energy Sales GmbH (“EES”). EES will take over the former sales activities of E.ON Sales & Trading GmbH (“EST”); EST’s trading activities are being transferred to EET, with retroactive effect as of January 1, 2008. However, responsibility for the long-term portion of contracts (i.e., those with obligations beyond three years) will stay with E.ON Energie and the other market units. For this purpose, the regional energy companies will transfer the relevant parts of their natural gas and power sales business (including the customer contracts) to an affiliated subsidiary (Vertriebsgesellschaft, “VG”) in which they have a 100 percent interest. Each regional energy company will have its own VG. The sales activities of the VGs will be directed by EVD and the regional energy companies will own stakes in EVD to ensure the consideration of regional interests, as well as their involvement in substantial decisions. Furthermore, it is also planned to bundle the shared service divisions of the regional energy companies into two companies (Shared Service Gesellschaften; “SSGs”). The SSGs predominantly provide customer related services (e.g. metering services, billing, customer care and receivables management) associated with the sales business of the VG´s and the distribution service business of regional energy companies. Details of the new structure still must be agreed by all relevant parties, including the decision-making bodies of the regional energy companies.

Gas. E.ON Energie’s gas sales volume in Germany amounted to 93.2 billion kWh in 2007 compared to 106.2 billion kWh in 2006. The decrease of consumption was mainly due to the warm winter at the beginning of 2007.

Heat. E.ON Energie is one of the leading suppliers of district heating in Germany. It operates its own district heating networks and supplies several additional networks owned by other companies. E.ON Energie’s regional energy companies are also involved in district heat and steam delivery. E.ON Energie’s total district heat deliveries in Western Europe decreased from 16.2 billion kWh in 2006 to 15.2 billion kWh in 2007, of which 10.5 billion kWh were supplied in Germany. The decrease primarily reflected the warm winter in 2007.

Water. E.ON’s regional water business is conducted through certain of its distribution companies, particularly E.ON Hanse, E.ON Avacon AG (“E.ON Avacon”) and E.ON Westfalen Weser.

104 Customers. Through its subsidiaries and companies in which it has shareholdings, E.ON Energie serves approximately 9.5 million electricity customers in Germany. E.ON Energie’s German operations also supply approximately 1.9 million customers with gas and more than 0.5 million customers with water.

The Netherlands. In the Netherlands, E.ON Benelux acquired the Dutch power and gas company NRE Energie b.v. (“NRE”) in 2005. In 2007, the company supplied approximately 1.2 TWh of electricity and approximately 3.5 TWh of gas to approximately 0.25 million electricity and gas customers in the Netherlands.

Italy. Sales activities in Italy are conducted through E.ON Italia (electricity) and Dalmine (electricity and gas). Both focus on industrial customers and local utilities. Both companies were handed over to the new market unit Italy on January 1, 2008. In 2007, E.ON Italia supplied 3.9 TWh of electricity and Dalmine supplied approximately 4.2 TWh of electricity and approximately 13.0 TWh of gas.

Trading Until the end of 2007, EST, the integrated wholesale and trading organization of E.ON Energie AG, was responsible for E.ON’s power and emission trading in the Central European market unit. In early 2008, E.ON started to integrate all of its European trading activities in a single entity, EET, which was formed out of EST. For information about EET, see “— New Market Units — Energy Trading” above.

EST traded electricity on the spot and forward markets and offered customized and standard products that were traded on a bilateral basis, as well as trading in standard exchange-traded instruments. EST’s trading focused on Germany and continental Europe, including important European power exchanges such as the European Energy Exchange in Leipzig, the Amsterdam Power Exchange in the Netherlands, Powernext in France and the Energy Exchange Austria. EST also supplied cross border trading and risk management processes for optimizing international power procurement to E.ON Energie’s operations in Eastern Europe and was the procurer for E.ON Energie’s operations in Italy. As the central trading desk of the E.ON Energie group, EST was also responsible for CO2 emissions trading. For further information on CO2 emissions trading, see “— Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas).” The volume of CO2 emission certificates traded by EST decreased from 15.1 million tons in 2006 to 10.6 million tons in 2007, reflecting reduced liquidity in the market in the final months of the EU scheme’s initial period.

The volume of EST’s energy trading activities decreased in 2007, reflecting lower market price volatility, especially during the second and third quarters of the year. The following table sets forth the total volume of EST’s traded electric power in 2007 and 2006.

% 2007 2006 Change Trading of Power million kWh million kWh in Total Power sold ...... 153,689 201,543 -23.7 Power purchased ...... 210,331 222,843 -5.6 Total ...... 364,020 424,386 -14.2

Other Consulting and Support Services. E.ON Engineering GmbH offers internal and external consulting, planning and construction services in the energy sector in fields such as chemical analytics and electrical, mechanical and civil engineering, with a focus on conventional and renewable power generation, cogeneration, use of biomass, pipeline construction, development of energy strategies and CO2-emissions reduction. Building on their shareholdings in municipal and regional utilities, E.ON Energie and the regional distributors also establish partnerships and cooperative relationships with local authorities. E.ON Energie and the regional distributors operate their own electricity and gas supply systems, and provide the local authorities with consulting, technical

105 and managerial support to promote the efficient use of electricity and gas. E.ON Facility Management GmbH provides technical, commercial and infrastructural facility management services, mainly for E.ON Energie group companies. E.ON IS GmbH (“E.ON IS”) is the provider for all information technology services needed in the E.ON Group. The company also offers information technology services for third parties. E.ON IS is wholly- owned by the E.ON Group.

Other Minority Shareholdings. In the Alpine region, E.ON Energie owns a 21.0 percent equity interest and 20.0 percent voting interest in BKW FMB Energie AG, an integrated Swiss utility that owns important hydroelectric assets, as well as a single nuclear power station and interests in other nuclear power stations.

Eastern Europe E.ON Energie has significant shareholdings in Hungary, the Czech Republic, Bulgaria, Romania and Slovakia. In Eastern Europe, E.ON Energie’s power generation facilities have a total installed capacity of approximately 540 MW, E.ON Energie’s attributable share of which is approximately 350 MW. National holding companies such as E.ON Hungária Energetikai ZRt. (“E.ON Hungária”), E.ON Czech Holding AG, E.ON Bulgaria EAD and E.ON Energie România S.A. (“E.ON Energie România”) coordinate E.ON Energie’s activities in the region.

The following table summarizes the most significant shareholdings in each of the specific countries:

Business Shareholding(1) Hungary E.ON Hungária Energetikai ZRt. Holding 100% Debreceni Kombinált Ciklusú Erömü Kft. Power and heat generation 100% Nyíregyházi Kombinált Ciklusú Erömü Kft Power and heat generation 100% E.ON Energiatermelö Kft. Diverse small power generation units 100% E.ON Dél-dunántúli Áramszolgáltató ZRt. Power distribution 100% (except for a “golden share”) E.ON Észak-dunántúli Áramszolgáltató ZRt. Power distribution 100% (except for a “golden share”) E.ON Tiszántúli Áramszolgáltató ZRt. Power distribution 100% (except for a “golden share”) E.ON Középdunántúli Gázszolgáltató ZRt. Gas distribution and sales 99.6% E.ON Dél-dunántúli Gázszolgáltató ZRt. Gas distribution and sales 99.9% E.ON Energiakereskedo˝ Kft. Sales of power and gas for customers 100% open to competition E.ON Energiaszolgáltató Kft. Sales of power and gas for quasi- 100% regulated customers (USP-segment) E.ON Hálózati Szolgáltató Kft. Network services 100% E.ON Ügyfélszolgálati Kft. Customer services 100% E.ON Gazdasági SzolgáltatóKft. Business services 100% Czech Republic E.ON Czech Holding AG Holding 100% Teplárna Otrokovice a.s. Power and heat generation 66.0% E.ON Distribuce, a.s. Power distribution 100% Jihoceská plynárenská Distribuce, s.r.o. Gas distribution 100% E.ON Energie, a.s. Sales of power and gas 100% E.ON Ceská republika, s.r.o. Services 100% Bulgaria E.ON Bulgaria EAD Holding & Services 100% E.ON Bulgaria Grid AD Power distribution 67.0% E.ON Bulgaria Sales AD Sales of power 67.0% Romania E.ON Energie România S.A. Holding 90.2% E.ON Moldova Distributie S.A. Power distribution 51.0% E.ON Moldova Furnizare S.A. Sales of power 51.0% Slovakia Západoslovenská energetika a.s. (ZSE) Distribution and sales of power 49.0%

(1) The minority shareholdings listed are those in which E.ON Energie has a direct interest.

106 In Hungary, E.ON Hungária provided 2.5 million customers with approximately 16.1 TWh of electricity in 2007. In the gas sector, E.ON Középdunántúli Gázszolgáltató ZRt. (“KÖGÁZ”) and E.ON Dél-dunántúli Gázszolgáltató ZRt. (“DDGÁZ”) provided approximately 0.6 million customers with approximately 12.7 TWh of gas. As of February 1, 2007, E.ON Hungária completed a reorganization to fulfill legal unbundling requirements. Business administration services are now in the newly-founded company E.ON Gazdasági Szolgáltató Kft., while the newly-founded companies E.ON Ügyfélszolgálati Kft. and E.ON Hálózati Szolgáltató Kft. handle customer services and network services, respectively. Until August 2007, all sales activities were carried out by E.ON Energiakereskedö Kft. Due to a requirement of the new Hungarian energy legislation, as of September 1, 2007 E.ON Hungária put into operation the newly founded E.ON Energiaszolgáltató Kft. to take care of the universal service provided customers (“USP”, a quasi-regulated segment) in the electricity as well as gas segment. As of September 1, 2007, E.ON Hungária’s five electricity and gas distributors transferred their retail customers to E.ON Energiaszolgáltató Kft.

In the Czech Republic, E.ON Energie controls significant participations in the energy sector. As of January 1, 2005, E.ON Energie fulfilled legal unbundling requirements by creating three wholly-owned subsidiaries, E.ON Ceská republika, s.r.o., E.ON Distribuce, a.s. and E.ON Energie, a.s. On a combined basis, these companies provided approximately 1.4 million customers with approximately 11.4 TWh of electricity in 2007. In January 2007, E.ON Energie received the remaining 1.0 percent interest of JCP from a squeeze-out. In July 2007, JCP was integrated into the structure of E.ON Energie a.s.

As of January 1, 2007, the legal unbundling requirements in Bulgaria were fulfilled through the foundation of E.ON Bulgaria Sales AD, which is now the sales company for the entire territory of northeastern Bulgaria, and E.ON Bulgaria Grid AD, which is now the distribution company for the entire territory of northeastern Bulgaria. The sales and distribution businesses of each of the former companies of Elektrorazpredelenie Varna AD (“Varna”) and Elektrorazpredelenie Gorna Oryahovitza AD (“Gorna Oryahovitza”) were integrated into these companies. In 2007, the E.ON Bulgaria Group effected annual sales for about 5.0 TWh and provided electricity to approximately 1.1 million customers.

In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution company Electrica Moldova S.A. (“Electrica Moldova”) — renamed E.ON Moldova S.A. (“E.ON Moldova”) — and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. In March, 2007, E.ON Energie România — at that time a fully owned subsidiary of E.ON Energie Group — and E.ON Energie AG agreed to transfer the shares held by E.ON Energie AG in E.ON Moldova S.A. to E.ON Energie România. E.ON Energie România is the new holding company for the activities of the E.ON Energie Group in Romania. According to the EU Directive, which imposes the legal unbundling of power distribution and supply, the electricity supply activity of E.ON Moldova S.A. has been legally transferred to the newly established E.ON Moldova Furnizare S.A. in April, 2007. As a result of these restructuring activities, E.ON Energie România holds 51.0 percent of E.ON Moldova Furnizare S.A. and 51.0 percent of E.ON Moldova Distributie S.A. (the former E.ON Moldova S.A., renamed after spin-off of the sales activities). In October, 2007 E.ON Energie AG sold a stake of 9.8 percent of E.ON Energie România to the European Bank for Reconstruction and Development (EBRD). In Romania, E.ON Moldova Furnizare S.A. and E.ON Moldova Distributie S.A. sold approximately 3.1 TWh of electricity to approximately 1.4 million customers in 2007.

In Slovakia, Západoslovenská energetika a.s. (“ZSE”) provided approximately 0.9 million customers with approximately 8.1 TWh of distributed electricity and 8.0 TWh of supplied electricity in 2007. As of July 2007, ZSE fulfilled legal unbundling requirements by creating two wholly-owned subsidiaries: ZSE Distribucia a.s. for power distribution and ZSE Energia a.s. for power retail.

Competitive Environment Since 1998, liberalization of the electricity markets in the EU has greatly altered competition in the German electricity market, which was formerly characterized by numerous strong competitors. Following liberalization,

107 significant consolidation has taken place in the German market, resulting in three mergers of major interregional utilities in recent years: VEBA and VIAG forming E.ON, RWE and Vereinigte Elektrizitätswerke AG forming RWE (both in 2000) and Hamburgische Electricitäts-Werke AG/Bewag Berliner Kraft und Licht Aktiengesellschaft/VEAG Vereinigte Energiewerke Aktiengesellschaft/Lausitzer Braunkohle Aktiengesellschaft forming Vattenfall Europe in 2002. In 2007, E.ON, RWE, Vattenfall Europe and the other remaining major interregional utility, EnBW, supplied approximately 70 percent of the total electricity production in Germany.

The interregional utilities own the high-voltage transmission lines in their traditional supply areas and are active in all phases of the electricity business. In addition to the interregional utilities, there are about 900 electric utilities in Germany at the state, regional and municipal level, many of which are partly or wholly owned by state or municipal governments. These utilities may be involved in various combinations of the generation, transmission, distribution and supply and trading functions. The liberalization of the electricity market in Germany has also led to new market structures with new market participants. The market for electricity has become more liquid and more competitive, and currently has the highest number of participants in continental Europe. Approximately 200 new market participants have entered the German market since 1998, with more than half of them engaged in electricity trading. The volume of electricity trading rose in 2007 (1,273 TWh at the European Energy Exchange’s Spot and Futures Market compared with 1,133 TWh in 2006; a 12 percent increase). The European Energy Exchange has also become a benchmark for electricity prices in central Europe.

Liberalization of the electricity market in Germany caused wholesale and consequently end customer electricity prices to decrease in 1998, with significant declines in some market segments. These declines were largely due to aggressive price setting by new competitors and suppliers, as well as other factors such as significant power plant overcapacity in Germany and Europe and relatively high and increasing price transparency. The rate of price declines began to slow in the second half of 2000, and prices have increased since 2001 but have developed differently in each of the customer segments. According to the German Energy Association, BDEW, in 2007 prices paid by household customers were about 21 percent higher than in the liberalization year 1998, while prices (including electricity tax) paid by industrial customers were about 22 percent higher than in 1998. However, when all applicable taxes are excluded from the comparison, 2007 prices were approximately 5 percent lower than those in 1998 for household customers and approximately 1 percent lower for industrial customers. In 2007, wholesale electricity prices in Germany stayed at a high level. Some industrial customers were affected by the high wholesale prices, but others had already locked in lower prices in earlier years. For this reason, the wholesale price increases did not affect the industrial customer segment to the same degree as household customers, who generally paid higher prices in 2007.

In addition to the effect of higher wholesale market prices, a significant factor in the overall price recovery are new or increased costs faced by electricity companies since the beginning of liberalization. Among these new or increased costs are the electricity tax (introduced in 1998 and subject to annual increases through 2003), duties and additional costs attributable to compliance with new legislation, including the Renewable Energy Source Act and Combined Heat and Power Act, as well as higher costs incurred in procuring balancing power to cover fluctuations in the availability of electricity from renewable resources such as wind. Most distributors have tried to pass these increases through to their customers. Taxes and duties accounted for approximately 41 percent of German electricity prices for household customers in 2007, compared with about 25 percent before deregulation in 1998. Similarly, electricity taxes and duties increased from 2 percent of German electricity prices for industrial customers in 1998 to almost 21 percent in 2007. E.ON Energie’s German regional utilities, as well as other competitors, announced in October 2007 further price increases for end customers to be effective in 2008. However, these price changes for end customers depend on the wholesale market prices for electricity. The most significant effects in this regard derive from the strong increase in procurement costs owing to the global rise in demand for energy. Subsidies for renewables-based energy are also having an impact on electricity prices, resulting in substantial additional burdens. For information about court proceedings on price increases affecting some of E.ON Energie’s majority-owned regional distribution companies, see “Risk Factors.”

High environmental and nuclear safety standards, as well as high investments in new power plants, taxes on electricity, the requirements of the Co-Generation Protection Law and the Renewable Energy Law’s requirement

108 that regional utilities purchase electricity generated from renewable resources impose a considerable burden on German electricity prices for end customers. E.ON Energie still believes that it will be able to compete effectively in Germany. In addition, E.ON Energie believes that the liberalization of the gas and electricity markets may open new business opportunities. However, E.ON Energie may be unable to compete as effectively as other electricity companies due to the factors described above, as well as due to regulatory changes described in “— Regulatory Environment.” Any of these or other factors could materially and adversely affect E.ON’s financial condition and results of operations. See also “Risk Factors.”

Outside Germany, the energy markets in which E.ON Energie operates are also subject to strong competition. In the countries of Eastern Europe where E.ON Energie has operations, full liberalization of the electricity and gas sales markets should have been formally realized by July 1, 2007 under the Directive 2003/54/EC Concerning Common Rules for the Internal Market in Electricity (“Second Electricity Directive”) and Directive 2003/55/EC Concerning Common Rules for the Internal Market in Natural Gas and Repealing Directive 98/30/EC (“Second Gas Directive”). This may alter competition in these electricity and gas markets, which could lead to decreasing end customer prices or to a loss of market shares. E.ON Energie cannot guarantee it will be able to compete successfully in electricity and gas markets where it already is present or in new electricity and gas markets it may enter.

Pan-European Gas Overview E.ON Ruhrgas is the lead company of the Pan-European Gas market unit and is responsible for all of E.ON’s non-retail gas activities in continental Europe. In terms of sales, E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas company in Germany. E.ON Ruhrgas’ principal business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas also holds numerous stakes in German and other European gas transportation and distribution companies, as well as a small shareholding in Gazprom, Russia’s main natural gas exploration, production, transportation and marketing company. In 2007, the Pan-European Gas market unit recorded revenues of €22.7 billion and adjusted EBIT of €2.6 billion. €13.7 billion of the Pan-European Gas market unit’s 2007 revenues were generated in Germany and €9.0 billion was generated abroad (measured by location of customer).

In 2001, E.ON concluded contracts for the purchase of significant shareholdings in Ruhrgas with BP p.l.c. (“BP”) and Vodafone Group Plc (“Vodafone”). E.ON also reached an agreement in principle with RAG Aktiengesellschaft (“RAG”) to acquire its Ruhrgas stake. In January and February 2002, the German Federal Cartel Office blocked the consummation of the transactions with the aforementioned parties on the grounds that the proposed purchase would have a negative effect on competition in the German gas and electricity markets. E.ON appealed the decision to the German Federal Ministry for Economics and Labor (now renamed the Federal Ministry for Economics and Technology) (Bundesministerium für Wirtschaft und Technologie), which has the power to overrule the Cartel Office if it determines a transaction would result in an overriding general benefit to the German economy.

Between May and July 2002, E.ON reached agreements with ThyssenKrupp AG, Esso Deutschland GmbH, Deutsche Shell GmbH and TUI AG with respect to E.ON’s acquisition of each company’s respective stake in Ruhrgas. E.ON also reached a definitive agreement with RAG to acquire RAG’s more than 18 percent interest in Ruhrgas and to sell E.ON’s majority interest in Degussa to RAG in a two-step transaction. The successful completion of each of these arrangements would make E.ON the sole owner of Ruhrgas.

In July 2002, E.ON was granted the ministerial approval it had requested for the acquisition of a majority shareholding in Ruhrgas. The ministerial approval was linked with stringent requirements designed to promote competition in the gas sector. Ruhrgas was required to auction a specified volume of natural gas to its

109 competitors and to legally unbundle its transmission system from its other operations. In addition, E.ON and Ruhrgas were required to divest several shareholdings. E.ON immediately completed the acquisition of 38.5 percent of Ruhrgas from BP, Vodafone and ThyssenKrupp AG.

A number of companies with alleged interests in the German energy industry filed complaints against the ministerial approval with the State Superior Court (Oberlandesgericht) in Düsseldorf and petitioned the court to issue a temporary injunction blocking the transaction. The court subsequently issued a series of orders in July, August and September 2002 that temporarily enjoined the Company’s acquisition of a majority stake in Ruhrgas and prohibited the Company from exercising its shareholders’ rights with respect to the Ruhrgas stake it had already acquired.

In September 2002, Germany’s Federal Minister of Economics confirmed the essential aspects of the July 5 ministerial approval for E.ON’s acquisition of Ruhrgas. However, the ministry linked its decision to a tightening of the requirements. Ruhrgas was also required to sell its stakes in two regional gas companies, and each of the companies required to be disposed of was granted a special right to terminate its existing purchase agreements with E.ON and Ruhrgas on a staggered basis. In addition, customers purchasing a majority of their gas requirements from Ruhrgas were granted the right to unilaterally reduce the contracted volumes, and Ruhrgas was required to auction 200 billion kWh of natural gas to its competitors, with the minimum bid in such auctions being lower than the average border-crossing price. The approval also provided that the ministry has the right to take further action in the event of any sale by E.ON of a controlling interest in E.ON Ruhrgas or a change in control over E.ON. On this basis, the ministry asked the State Superior Court to lift its temporary injunction. E.ON and E.ON Ruhrgas have complied with all of the conditions imposed by the ministerial approval.

In December 2002, the State Superior Court decided not to lift the temporary injunction, and formal proceedings (Hauptverfahren) regarding the injunction began in January 2003. On January 31, 2003, E.ON reached settlement agreements with all plaintiffs who had contested the validity of the ministerial approval. In accordance with these agreements, E.ON exchanged shareholdings with certain plaintiffs and agreed to enter into gas and/or electricity supply contracts, make certain infrastructure improvements (particularly with regard to gas distribution), and provide specified access to the gas and electricity supply grids, with others, as well as agreeing to make other financial payments to the plaintiffs. In addition, Ruhrgas reconfirmed to all the parties its commitment to open and fair competition in the gas market.

In March 2003, E.ON acquired the remaining shares of Ruhrgas. The total cost of the transaction to E.ON, including settlement costs and excluding dividends received on Ruhrgas shares owned by E.ON prior to its consolidation, amounted to €10.2 billion. Beginning as of February 1, 2003, E.ON fully consolidated Ruhrgas, which was renamed E.ON Ruhrgas on July 1, 2004.

Upon termination of the court proceedings, the Company completed the first step of the RAG/Degussa transaction, i.e., the Company acquired RAG’s Ruhrgas stake for total consideration of €2.0 billion, and E.ON tendered 37.2 million of its shares in Degussa to RAG at the price of €38 per share, receiving total proceeds of €1.4 billion. Following this transaction and the completion of the subsequent mandatory tender offer to the other Degussa shareholders, RAG and E.ON each held a 46.5 percent interest in Degussa, with the remainder being held by the public. In the second step of the transaction, E.ON sold a further 3.6 percent of Degussa’s stock to RAG with effect from June 1, 2004, giving RAG a 50.1 percent interest in Degussa. Total proceeds from the sale of this 3.6 percent stake amounted to €283 million. In December 2005, E.ON and RAG signed a framework agreement on the sale of E.ON’s remaining 42.9 percent stake in Degussa to RAG. As part of the implementation of that framework agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft mbH (“RAG Projektgesellschaft”) in March 2006 and agreed on the forward sale of that entity to RAG for a purchase price of €2.8 billion (equal to €31.50 per Degussa share). The transaction closed in July 2006. As a result, E.ON no longer holds any equity interest in Degussa.

110 In 2007, E.ON Ruhrgas entered into the following significant transactions: • In June 2007, E.ON Ruhrgas AG participated in the creation of a joint venture to plan a new European gas pipeline in Scandinavia. This Skanled pipeline is to transport Norwegian gas to Norway, Sweden and Denmark. With a 15 percent stake, E.ON Ruhrgas is one of the largest partners in the joint venture, in which a total of 10 companies from Norway, Sweden, Denmark and Poland are involved. The total investment for the pipeline is currently estimated at €1.3 billion on the basis of an updated design incorporating developments in the materiel procurement and construction markets. A final decision on construction of the pipeline is to be taken by the end of 2009. If constructed, the pipeline is then expected to come into operation by 2012 at the latest. • In August 2007, E.ON Ruhrgas acquired (through its subsidiary E.ON Ruhrgas Norge AS) an approximately 28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from Shell, with retroactive effect to January 1, 2007. E.ON Ruhrgas Norge AS’ share of the investments for developing these fields is expected to be around $1.4 billion (around €1.0 billion). Skarv and Idun are both located in the northern Norwegian Sea, just below the Arctic Circle. Skarv-Idun is thought to be among the most attractive undeveloped gas fields in Norway as the area has significant potential for reserves growth through further exploration. Gas production is expected to start in 2011.

Operations Through E.ON Ruhrgas AG and its subsidiaries, E.ON Ruhrgas is primarily engaged in the following segments of the gas industry:

Supply: The purchase of natural gas under long-term contracts with foreign and domestic producers, including the Russian gas company Gazprom, the world’s largest gas producer in terms of volume, in which E.ON Ruhrgas holds a small shareholding. E.ON Ruhrgas also engages in gas exploration and production activities and, to supplement its supply as well as its sales business and until they will be taken over by EET, in a limited amount of trading activities; Transmission: The transmission of gas within Germany via a network of approximately 11,611 km of pipelines in which E.ON Ruhrgas holds an interest; Storage: The storage of gas in a number of large underground natural gas storage facilities; and Sales: The sale of gas within Germany to supraregional and regional distributors, municipal utilities and industrial customers, as well as sales to a number of customers in other European countries.

In addition to its natural gas supply, transmission, storage and sales businesses, E.ON Ruhrgas owns numerous shareholdings in integrated gas companies, gas distribution companies and municipal utilities through its subsidiaries E.ON Ruhrgas International AG (“ERI”) and Thüga Aktiengesellschaft (“Thüga”). ERI holds both majority and minority shareholdings in German and European energy companies, while Thüga holds primarily minority shareholdings in 93 regional and municipal electricity and gas utilities in Germany, as well as majority and minority shareholdings in a number of Italian gas distribution and sales companies.

For financial reporting purposes, the Pan-European Gas market unit is divided into three business units: Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects the results of the supply, transmission, storage and sales businesses, with the midstream operations essentially including all of the supply and sales businesses other than exploration and production activities. The Downstream Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes consolidation effects.

111 Up-/Midstream The following table provides information about purchases and sales of natural gas and coke oven gas by E.ON Ruhrgas’ midstream operations for the years 2007 and 2006. The difference between gas supplies and gas sales in any given period is due to storage and metering differences and occurs routinely.

Total 2007 Total 2006 billion kWh % billion kWh % Purchases Imports ...... 570.8 81.8 609.9 84.4 German sources ...... 127.0 18.2 113.3 15.6 Total ...... 697.8 100.0 723.2 100.0 Sales Domestic distributors ...... 292.5 41.1 318.7 44.9 Domestic municipal utilities ...... 169.8 23.8 163.1 23.0 Domestic industrial customers ...... 70.1 9.8 67.6 9.5 Sales abroad ...... 180.4 25.3 160.3 22.6 Total ...... 712.8 100.0 709.7 100.0

In the table above, as well as in the descriptions of E.ON Ruhrgas’ supply and sales businesses, purchase and sales volumes are presented for all periods excluding relatively small amounts of gas that E.ON Ruhrgas does not consider part of its primary business, including volumes handled for third parties. In addition, these gas volumes do not include gas volumes attributable to ERI or Thüga, which are part of the Downstream Shareholdings business unit.

The increase in total sales volume in 2007 was primarily attributable to an increase in sales abroad, especially to customers in the Netherlands, Denmark and the United Kingdom. For more information on E.ON Ruhrgas’ gas supply contract with E.ON Sverige, see “— Nordic — Operations.”

Supply E.ON Ruhrgas purchases nearly all of its natural gas from producers in six countries: Russia, Norway, the Netherlands, Germany, the United Kingdom and Denmark. In 2007, E.ON Ruhrgas purchased a total of 690.5 billion kWh of gas, of which approximately 81.8 percent was imported and approximately 18.2 percent was purchased from German producers. E.ON Ruhrgas was the largest gas purchaser in Germany in 2007, acquiring more than half of the total volume of gas purchased for the German market. Of the 697.8 billion kWh of gas purchased in 2007, E.ON Ruhrgas bought approximately 25.5 percent from Russia and approximately 25.0 percent from Norway, its two largest suppliers. The following table provides information on the amount of gas purchased from each country and its percentage of the total volume of gas purchased by the midstream operations in the years 2007 and 2006:

Total 2007 Total 2006 billion kWh % billion kWh % Sources of Gas Germany ...... 127.1 18.2 113.3 15.6 Russia ...... 178.0 25.5 178.4 24.7 Norway ...... 174.7 25.0 196.5 27.2 The Netherlands ...... 120.3 17.2 137.5 19.0 United Kingdom ...... 68.2 9.8 67.2 9.3 Denmark ...... 20.8 3.0 22.9 3.2 Others(1) ...... 8.7 1.3 7.4 1.0 Total ...... 697.8 100.0 723.2 100.0

(1) Italy, France, Austria, Hungary and Slovakia.

112 In the table above, purchase volumes are presented for all periods excluding relatively small amounts of gas that E.ON Ruhrgas does not consider part of its primary supply business, including volumes handled for third parties. In addition, these gas volumes do not include gas volumes attributable to ERI or Thüga.

As is typical in the gas industry, these purchases were primarily made under long-term supply contracts that E.ON Ruhrgas has with one or more gas producers in each country. Purchases under such contracts provided for nearly all of the gas bought by E.ON Ruhrgas in 2007; the remaining amounts were purchased on international spot markets or pursuant to short-term contracts. E.ON Ruhrgas’ current long-term contracts with fixed terms (so-called “supply”-type contracts) have termination dates ranging from 2008 to 2036 (subject in certain cases to automatic extensions unless either party gives notice of termination), while so-called “depletion”-type contracts terminate upon the exhaustion of economic production from the relevant gas field. E.ON Ruhrgas believes that its existing contracts secure the supply of a total volume of approximately 12.5 trillion kWh of natural gas over the period to 2036. As is standard in the gas industry, the price E.ON Ruhrgas pays for gas under these contracts is calculated on the basis of complex formulas incorporating variables based upon current market prices for fuel oil, gas oil, coal and/or other competing fuels, with prices being automatically re-calculated periodically, usually monthly or quarterly. The contracts also generally provide for formal revisions and adjustments of the price or business terms to reflect changes in the market (in many cases expressly including changes in the retail market for natural gas and competing fuels), generally providing that such revisions may only be made once every few years unless the parties agree otherwise. Claims for revision are subject to binding arbitration in the event the parties cannot agree on the necessary adjustments. Certain contracts also provide E.ON Ruhrgas with the possibility of buying specified quantities of gas at prices linked to those on international spot markets. The contracts also require E.ON Ruhrgas to pay for specified minimum quantities of gas even if it does not take delivery of such quantities, a standard gas industry practice known as “take or pay.” Take-or-pay quantities are generally set at approximately 80 percent of the firm contract quantities. To date, E.ON Ruhrgas has been able to avoid the application of these take-or-pay clauses in nearly all cases. The contracts also include quality and availability provisions (together with related discounts for non-compliance), force majeure provisions and other industry standard terms. E.ON Ruhrgas also has short-term arrangements with some of its suppliers, which provided less than 3 percent of E.ON Ruhrgas’ gas supply in 2007. E.ON Ruhrgas generally takes delivery of the gas it imports at the point at which the relevant pipeline crosses the German border. For additional information on these contractual obligations, see “Operating and Financial Review and Prospects — Contractual Obligations.”

In the medium and long term, rising demand for gas in Europe, combined with falling indigenous production in European countries, particularly in the United Kingdom, will lead to a greater reliance on imports by European gas wholesalers. Accordingly, in the near future, gas producers will have to invest, in some cases quite considerably, in expanding their production capacities. In addition, the natural decline in output from older fields will need to be made up by the development of new fields. E.ON Ruhrgas believes that long-term gas purchase contracts will remain crucial to European gas supplies, ensuring a fair balance of risks between producers and importers. E.ON Ruhrgas believes the price adjustment provisions in such contracts ensure sufficient supplies of gas at competitive prices, while the take or pay provisions give producers the necessary long-term security for investing. For information about risks relating to long-term gas supply contracts, see “Risk Factors.”

E.ON Ruhrgas’ supply sources are discussed below on a country-by-country basis.

Russia. In 2007, E.ON Ruhrgas purchased 178.0 billion kWh of gas, or 25.5 percent of its total gas purchased, from Russia. Russia is the largest supplier of natural gas to E.ON Ruhrgas, while E.ON Ruhrgas is the second-largest purchaser of gas from Russia. As with most of its gas imports, E.ON Ruhrgas takes ownership of its Russian gas when it reaches the German border.

All of E.ON Ruhrgas’ purchases of Russian natural gas are made pursuant to long-term supply contracts with OOO Gazexport (now Gazprom export), the subsidiary of Gazprom responsible for exports. E.ON Ruhrgas holds a 3.5 percent direct interest in Gazprom; an additional stake of 2.9 percent in Gazprom is attributable to

113 E.ON Ruhrgas on the basis of contractual arrangements relating to its minority interest in a Russian entity that holds these shares. E.ON Ruhrgas considers its shareholding in Gazprom to be an important element supporting its long-term supply relationship with Gazprom, which is the world’s largest gas producer, having produced approximately 550 billion cubic meters (“m3”) of gas in 2007. E.ON Ruhrgas expects the importance of Russian gas exports for Europe to increase as the indigenous production of important European supply countries decreases. Gazprom has indicated it will flexibly cover about one third of E.ON Ruhrgas’ gas requirements for the German market until 2030. In July 2004, E.ON and Gazprom signed a Memorandum of Understanding for a deepened strategic cooperation between the parties, pursuant to which E.ON, Gazprom and BASF AG signed a basic agreement on the construction of the Nord Stream pipeline from Vyborg, Russia to Greifswald, Germany through the Baltic Sea. For details, see “— Transmission and Storage — Pipelines.”

In August 2006, E.ON Ruhrgas and Gazexport (now Gazprom Export) finalized a series of agreements in Moscow. These agreements, which comprise extensions of existing contracts and a new supply contract, provide for the delivery of an aggregate of approximately 400 billion cubic meters (“m3”) of gas through 2036, and E.ON believes that these contracts represent an important contribution towards safeguarding long-term European gas supplies. The two companies signed 15-year extensions of the existing contracts with Waidhaus, Germany as delivery point through 2035, as well as a new supply contract for additional gas to be delivered via the Nord Stream pipeline from 2010/2011 onwards.

Norway. In 2007, E.ON Ruhrgas purchased 174.7 billion kWh, or 25.0 percent of its total gas purchased, from Norwegian sources. E.ON Ruhrgas has supply contracts with a number of major Norwegian and international energy companies (as well as its subsidiary E.ON Ruhrgas Norge AS) that hold concessions for the exploitation of Norwegian gas fields. Some of the contracts are of the “depletion”-type while others are “supply”-type contracts. E.ON Ruhrgas takes delivery of its Norwegian supplies mainly at the gas import points near Emden along the German North Sea coast.

The Netherlands. In 2007, E.ON Ruhrgas purchased 120.3 billion kWh, or 17.2 percent of its total gas purchased, pursuant to a single long-term supply contract with GasTerra B.V. This contract provides E.ON Ruhrgas with a certain degree of flexibility in managing its supply portfolio. E.ON Ruhrgas believes such flexibility is particularly important in this case, as the Dutch gas fields are relatively close to the end consumers in E.ON Ruhrgas’ markets, making it more economically viable for E.ON Ruhrgas to react to changes in market demand by varying contract quantities. E.ON Ruhrgas takes delivery of Dutch gas at the German border.

Germany. In 2007, E.ON Ruhrgas purchased 127.1 billion kWh, or 18.2 percent of its total gas purchased, from domestic gas production companies. E.ON Ruhrgas has long-term supply contracts for German natural gas with ExxonMobil Gas Marketing Deutschland GmbH (formerly Mobil Erdgas-Erdöl GmbH), ExxonMobil Gas Marketing Deutschland GmbH & Co. KG (50 percent of the gas trading business of BEB Erdgas und Erdöl GmbH (“BEB”)), Shell Erdgas Marketing GmbH & Co. KG (the other 50 percent of the gas trading business of BEB), Gaz de France Produktion Exploration Deutschland GmbH (formerly Preussag Energie GmbH) and RWE Dea AG. The majority of the contracts provide E.ON Ruhrgas with significant additional flexibility by providing for the supply of minimum and maximum quantities of gas, rather than a single fixed amount. E.ON Ruhrgas expects the volume of gas it purchases from domestic sources to decline over the coming years due to the depletion of German gas fields.

United Kingdom. In 2007, E.ON Ruhrgas purchased 68.2 billion kWh, or 9.8 percent of its total gas purchased, from U.K. sources. These quantities were partly purchased from BP Gas Marketing Ltd under a long- term supply contract, partly purchased on the spot short-term market and partly received as “equity gas” through E.ON Ruhrgas’ subsidiary E.ON Ruhrgas UK Exploration and Production Limited (“E.ON Ruhrgas UK”), which has interests in U.K. gas fields and infrastructure. See “— Exploration and Production” below for more information on E.ON Ruhrgas UK.

In contrast to much of its other imported gas, which E.ON Ruhrgas generally takes ownership of at the German border, E.ON Ruhrgas takes delivery of its purchased U.K. gas supplies partly at Bacton and Easington

114 terminals in the United Kingdom and partly at Zeebrugge terminal in Belgium. Gas from the U.K. gas fields is transported to Belgium through the undersea gas pipeline run by the project company Interconnector (U.K.) Limited (“Interconnector”).

Denmark. In 2007, E.ON Ruhrgas purchased 20.8 billion kWh, or 3.0 percent of its total gas purchased, from the Danish supplier DONG Energy A/S (“DONG”), with which E.ON Ruhrgas has long-term supply contracts. E.ON Ruhrgas takes delivery of Danish gas at the German-Danish and Swedish-Danish border.

Gas Release Program of E.ON Ruhrgas. In accordance with the obligations set out in the ministerial approvals mandating the auctioning of an aggregate amount of 200 billion kWh of baseload gas, on May 10, 2007, E.ON Ruhrgas offered approximately 33 billion kWh of natural gas from its portfolio of long-term supply contracts in the fifth of six internet-based annual auctions. Approximately 33 million kWh of gas remains for the last of these auctions.

Trading Until the end of 2007, in order to optimize and manage price risks of its long-term gas portfolio, E.ON Ruhrgas engaged in gas, oil and coal trading. The gas trading activities are concentrated at the national balancing point in the United Kingdom, at the Zeebrugge hub in Belgium, at the Title Transfer Facility in the Netherlands and at the Virtuelle Handelspunkte in Germany, and are mainly handled via brokers participating in open markets and exchanges. Financial, oil and coal trading activities are undertaken mainly for hedging purposes. Proprietary trading is marginal compared to asset-based trading. In 2008, E.ON Ruhrgas’ trading activities will be transferred to the new Energy Trading market unit with the transfer becoming effective retroactively as of January 1, 2008. For information about EET, see “Business — Our Business.”

E.ON Ruhrgas’ total traded gas volume for 2007 was 14.8 percent of total E.ON Ruhrgas sales, as compared with 10.1 percent in 2006, with the increase being attributable to increased hedging activities reflecting the expansion of the arbitrage business in the markets in the United Kingdom, Belgium and the Netherlands.

All of E.ON Ruhrgas’ energy trading operations, including its limited proprietary trading, are subject to E.ON’s risk management policies for energy trading. For additional information on these policies and related exposures, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about Market Risk.”

Exploration and Production E.ON Ruhrgas participates in the exploration and production segment of the gas industry through its gas production companies in the United Kingdom and in Norway.

United Kingdom. In the United Kingdom, E.ON Ruhrgas operates through its subsidiary E.ON Ruhrgas UK, which directly and indirectly holds mainly minority shareholdings in a number of gas production fields, exploration blocks and pipelines in the British North Sea.

In 2007, E.ON Ruhrgas UK acquired interests in two exploration blocks in the central North Sea, as well as an interest in one additional license obtained within the 24th UK Seaward Licensing Round.

In 2007, the E.ON Ruhrgas UK group produced 8.1 billion kWh (751 million m3) of gas, compared with 7.7 billion kWh (725 million m3) of gas in 2006. The 5.2 percent increase reflects the first full year of gas production from the Merganser field and the June 2007 start of production of the Minke field. In addition, the E.ON Ruhrgas UK group produced 2.9 million barrels of liquids (oil and condensate) in 2007, compared with 2.7 million barrels in 2006. In summer 2007, E.ON Ruhrgas UK had a significant discovery in the Block 22/14b (Huntington) in the UK central North Sea that is expected to come into production in 2010. The working interest of E.ON Ruhrgas UK in this Oilexco operated field is 25 percent.

115 The following table shows the name of each producing field in which the E.ON Ruhrgas UK group holds an interest, E.ON’s ownership interest in the field, and the date each field commenced production: E.ON Ruhrgas UK Group

Name of Producing Field E.ON Share in % Start-up Date Ravenspurn North ...... 28.75 July 1990 Caister ...... 40.0 October 1993 Johnston ...... 50.107 September 1994 Schooner ...... 4.83 September 1996 Elgin/Franklin ...... 5.2 April 2001 Scoter ...... 12.0 December 2003 Hunter ...... 79.0 January 2006 Glenelg ...... 18.57 April 2006 Merganser ...... 7.9185 December 2006 Minke ...... 42.67 June 2007

The E.ON Ruhrgas UK group received its share of production from all of the producing fields in which it owned an interest in 2007.

Norway. E.ON Ruhrgas operates in Norway mainly through its subsidiary E.ON Ruhrgas Norge AS (“E.ON Ruhrgas Norge”). E.ON Ruhrgas Norge owns 30.0 percent of the Njord oil and gas field. E.ON Ruhrgas Norge obtained 2.1 million barrels of oil as a result of its stake in 2007 which were sold on the market. The field started producing gas for sale in December 2007. In January 2007, the Norwegian Ministry of Petroleum and Energy announced that E.ON Ruhrgas Norge had qualified for operatorship on the Norwegian Continental Shelf, thus expanding its potential range of business. In August 2007, E.ON Ruhrgas acquired through its subsidiary E.ON Ruhrgas Norge AS, an approximately 28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from Shell, with retroacive effect as of January 1, 2007.

Russia. In July 2006, E.ON Ruhrgas and Gazprom signed a framework agreement on the exchange of assets in the sectors of gas exploration and production as well as gas sales and trading and power. As part of this agreement, E.ON Ruhrgas is expected to acquire a stake of 25.0 percent minus one share in the company Severneftegazprom, which holds the exploration and production license for the major Yushno Russkoje gas field in Siberia. In December 2007, the companies announced that major progress has been made in the negotiations on an asset swap between Gazprom and E.ON in the framework of which E.ON will acquire a stake in the west Siberian gas field Yuzhno Russkoye and Gazprom will acquire stakes in E.ON assets in western and central Europe. In particular, the E.ON assets from which Gazprom will be able to choose shareholdings in western and central Europe were defined. They include power plants in various western and central European countries, as well as underground storage facilities. The valuation of these assets still has to be made and, in the event of a value imbalance between such values and that of the stake in Yuzhno Russkoye, additional assets would have to be agreed on. The asset swap transaction therefore could not be completed by the time of the inauguration of the field on December 18, 2007.

Liquefied Natural Gas Liquefied natural gas (LNG), which is liquefied in the gas producing country, transported by tanker and then converted back into gas at the receiving terminal, is an alternative to gas deliveries by pipeline. In 2007, E.ON Ruhrgas completed the front end engineering & design study (a so called FEED) on the construction of an LNG unloading and regasification terminal on the German North Sea coast near the city of Wilhelmshaven. This would be Germany’s first such facility. E.ON Ruhrgas has a majority shareholding in DFTG-Deutsche Flüssigerdgas Terminal Gesellschaft mit beschränkter Haftung (“DFTG”), which it recently increased through the acquisition of a 12 percent share from BFB Transport GmbH on December 19, 2007 to a total shareholding of 90 percent. DFTG owns the land on which the terminal will be built and holds a valid permit for the construction

116 of the terminal, which upon completion could handle as much as 10 billion m³ of natural gas per year. In a second phase, its capacity could be expanded to 15 billion m³ of natural gas. In August 2007, DFTG issued an invitation to tender for the turn-key construction of this terminal and in parallel conducted a so called ‘open season’ to offer regasification capacity to third parties. The implementation of this terminal project will be in line with E.ON’s strategy of expanding its sources of natural gas with the goal of enhancing and diversifying the security of its supply. The final investment decision to build the terminal is envisaged for 2008.

A consortium comprising E.ON Ruhrgas (31.15 percent), OMV Gas International (25.58 percent), TOTAL (25.58 percent), RWE (16.69 percent) and Geoplin, Croatia, (1 percent) has set up the Zagreb-based project company Adria LNG d.o.o. to build an LNG terminal in Croatia. The new terminal will have an initial regasification capacity of some 10 billion m³ per year, which can be increased to 15 billion m³ per year. It will be designed for LNG tankers carrying up to 265,000 m³ of LNG. Once further investigations and planning activities have been completed, the LNG receiving terminal could be ready to go into operation in 2012. The final investment decision on this project is expected for 2008 or later.

In May 2007, E.ON Ruhrgas agreed to lease annual regasification capacity of approximately 1.7 billion m³ for the regasification of LNG during phase III of the Isle of Grain LNG terminal project in the UK. The contract lasts until 2029 and Phase III is due to come onstream in October 2010. Synergies are expected to result from the possibility of supplying E.ON UK’s Grain power station, which is being built near the Isle of Grain terminal.

In May 2007, E.ON Ruhrgas signed a ‘Heads of Agreement’ for a new LNG terminal project in Le Havre, France. E.ON Ruhrgas currently owns a 24.5 percent stake in the project company Gaz de Normandie. The new terminal would have an annual capacity of about 9 billion m³, the E.ON Ruhrgas share being 3 billion m³ per year. Subject to further studies and planning activities, the LNG terminal could start its commercial operation as early as 2012.

Transmission and Storage E.ON Ruhrgas AG’s technical infrastructure in Germany is comprised of pipelines and transport compressor stations (together, the “transmission system”), as well as underground gas storage facilities (including storage compressor stations) owned by E.ON Ruhrgas AG, those co-owned directly by E.ON Ruhrgas AG and other gas companies, and those owned by project companies in which E.ON Ruhrgas AG holds an interest.

Project companies are entities E.ON Ruhrgas AG has set up with German or European gas companies for a special purpose, such as establishing a pipeline connection between two countries or building and operating underground gas storage facilities. The following table provides more information on the E.ON Ruhrgas AG share in each of its German project companies as of December 31, 2007:

E.ON Ruhrgas Share Project Company % DEUDAN (DEUDAN-Deutsch/Dänische Erdgastransport-Gesellschaft mbH & Co. Kommanditgesellschaft) ...... 25.0 EGL (Etzel Gas-Lager GmbH & Co. KG) ...... 74.8 GHG (GHG-Gasspeicher Hannover GmbH) ...... 13.2 MEGAL (MEGAL Mittel- Europäische-Gasleitungsgesellschaft mbH & Co. KG) ...... 51.0 METG (Mittelrheinische Erdgastransportleitungsgesellschaft mbH) ...... 100.0 NETG (Nordrheinische Erdgastransportleitungsgesellschaft mbH & Co. KG) ...... 50.0 NETRA (NETRA GmbH Norddeutsche Erdgas Transversale & Co. KG) ...... 40.6 TENP (Trans Europa Naturgas Pipeline Gesellschaft mbH & Co. KG) ...... 51.0

The E.ON Ruhrgas AG underground storage facilities are operated by E.ON Ruhrgas AG as storage system operator. The E.ON Ruhrgas AG transmission system is operated by E.ON Gastransport, a wholly-owned

117 subsidiary of E.ON Ruhrgas AG, as transmission system operator. The underground storage facilities and the transmission system, based on service contracts, are monitored and maintained largely by E.ON Ruhrgas AG. The transmission system is used to transport the gas that E.ON Ruhrgas and third party customers receive from suppliers at gas import points on the German border or at other supply points within Germany to customers or to storage facilities for later use.

In accordance with Germany’s energy law, the transmission system has been leased out to E.ON Gastransport together with all transmission rights and rights of beneficial use that E.ON Ruhrgas AG possesses in respect of third party transmission systems in Germany. For more information on this law, see “— Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas).” For more information on E.ON Gastransport, see “— E.ON Gastransport” below.

The following map shows the pipelines as well as the location of compressor stations, gas storage facilities and field stations belonging to E.ON Ruhrgas AG’s technical infrastructure:

E.ON Ruhrgas AG’s Technical Infrastructure

Flens- burg

Hamburg

Emden

Berlin

Hanover

Natural gas pipeline Compressor station Essen Underground storage facility Maintenance station Delivery station Cologne Leipzig Dresden Zwickau

Frankfurt/ Main Waidhaus

Nuremberg

Passau Stuttgart

Munich Freiburg

As shown in the map above, E.ON Ruhrgas AG’s transmission system and its underground storage facilities are located primarily in western Germany, the historical center of E.ON Ruhrgas’ operations.

Pipelines. As of the end of 2007, E.ON Ruhrgas AG owned gas pipelines totaling 6,746 km and co-owned gas pipelines totaling 1,547 km with other companies. In addition, German project companies in which E.ON Ruhrgas AG holds an interest owned gas pipelines totaling 3,318 km at the end of 2007.

118 The following table provides more information on E.ON Ruhrgas AG’s pipelines in Germany as of December 31, 2007:

Maintained by Pipelines Total km E.ON Ruhrgas AG km Owned by E.ON Ruhrgas AG ...... 6,746 6,428 Co-owned pipelines ...... 1,547 602 DEUDAN (PC) ...... 110 0 EGL (PC) ...... 67 67 MEGAL (PC) ...... 1,092 1,092 METG (PC) ...... 425 425 NETG (PC) ...... 285 144 NETRA (PC) ...... 341 106 TENP (PC) ...... 998 998 Companies in which E.ON Ruhrgas AG holds a stake through its subsidiaries ERI and Thüga ...... — 2,037 Owned by third parties ...... — 1,043 Total in Germany ...... 11,611 12,942 (PC) project company

E.ON Ruhrgas AG’s share in the use of any particular pipeline it does not wholly own is determined by contract and is not necessarily related to E.ON Ruhrgas AG’s interest in the pipeline. E.ON Ruhrgas AG’s pipeline network is comprised of pipeline sections of varying diameters originally built according to the estimated capacity needed for the relevant section of the system. Currently, the pipeline network comprises 2,019 km of pipelines with a diameter of less than or equal to 300 millimeters, 3,050 km of pipelines with a diameter of more than 300 and less than or equal to 600 millimeters, 3,040 km of pipelines with a diameter of more than 600 and less than or equal to 900 millimeters, and 3,502 km of pipelines with a diameter of more than 900 and less than or equal to 1,200 millimeters.

In 2007, E.ON Ruhrgas AG maintained 6,428 km of its own pipelines, 602 km of co-owned pipelines, 1,043 km of pipelines owned by third parties and 2,037 km of pipelines owned by companies in which E.ON Ruhrgas AG holds a stake through its subsidiaries ERI and Thüga, as well as 2,832 km of pipelines owned by project companies in which E.ON Ruhrgas AG holds an interest. In total, E.ON Ruhrgas AG maintained (including providing local monitoring) 12,942 km of pipelines in 2007. For information on pipeline monitoring and maintenance, see “— Monitoring and Maintenance” below.

In addition to E.ON Ruhrgas AG’s German transmission system, E.ON Ruhrgas has a 23.59 percent interest in Interconnector, a U.K. project company that owns the Interconnector transmission system, comprising a 235 km undersea gas pipeline from the United Kingdom to Belgium, a transport compressor station at Bacton (four units with a total installed capacity of approximately 116 MW) and a compressor station at Zeebrugge (four units with a total installed capacity of approximately 140 MW). On November 9, 2007, E.ON Ruhrgas signed a share purchase agreement to acquire an additional 1.5 percent interest in Interconnector.

In July 2004, E.ON Ruhrgas acquired a 20.0 percent interest in BBL Company V.O.F., which built a second undersea transmission system between continental Europe and the United Kingdom. This transmission system (comprising a 235 km undersea pipeline and a compressor station at Balgzand — three units with a total installed capacity of approximately 69 MW), which links Balgzand in the Netherlands to Bacton in the United Kingdom, started operation in December 2006.

E.ON Ruhrgas also owns small stakes in pipeline project companies in Switzerland and Austria.

In July 2007, Gazprom, E.ON Ruhrgas and Wintershall Aktiengesellschaft (“Wintershall”) signed the Final Shareholders’ Agreement providing for the construction of the Nord Stream pipeline (formerly the North

119 European Gas Pipeline), which is planned to connect Vyborg on Russia’s Baltic coast with Greifswald on the German Baltic coast, thereby providing an additional undersea route for the supply of Russian natural gas to Germany, as compared with the current land routes through Ukraine and Poland. The three joint venture partners have formed the Swiss company Nord Stream AG, in which Gazprom holds a 51.0 percent interest and E.ON Ruhrgas and Wintershall each hold 24.5 percent stakes. In December 2007, Gazprom signed an umbrella agreement with N.V. Nederlandse Gasunie regarding Gasunie’s participation in the Nord Stream project. Gazprom has an option to require that Wintershall and E.ON Ruhrgas each assign up to a 4.5 percent interest in the company to Gasunie, which will then become the fourth joint venture partner. It is not expected that the first pipeline could be completed before 2010 at the earliest. The current estimates of E.ON Ruhrgas’ share of the expected cost of the complete project are in the range of approximately €1.7 billion (assuming that E.ON Ruhrgas will reduce its stake in Nord Stream to 20 percent).

In June 2007, E.ON Ruhrgas participated in the creation of a joint venture to plan a new European gas pipeline in Scandinavia. This Skanled pipeline, in which E.ON Ruhrgas has a 15 percent stake, is to transport Norwegian gas to Norway, Sweden and Denmark. The total investment for the pipeline (of which E.ON expects to bear a pro rata share) is estimated at €1,300 million according to an updated design incorporating developments in the markets for the procurement of materials and construction services. A final decision on the construction of the pipeline is to be taken by the end of 2009.

Compressor Stations. Compressor stations are used to produce the pressure necessary to transport gas through pipelines and to inject gas into underground storage facilities. E.ON Ruhrgas AG owns or co-owns 15 compressor stations, nine operating for gas transportation purposes (with a total installed capacity of 305 MW), and six for gas storage purposes (with a total installed capacity of 79 MW). German project companies in which E.ON Ruhrgas AG holds an interest own an additional 17 transport compressor stations with a total installed capacity of 592 MW and two storage compressor stations with a total installed capacity of 17 MW. In 2007, E.ON Ruhrgas AG provided monitoring and maintenance services under service contracts for the nine transport compressor stations leased out to E.ON Gastransport and 13 transport compressor stations of the project companies. E.ON Ruhrgas AG also operated, monitored and maintained its six compressor stations operating for gas storage purposes. The current installed capacity of the compressor stations monitored and maintained by E.ON Ruhrgas AG totals 908 MW.

The following table provides more information about E.ON Ruhrgas AG’s and its project companies’ gas compressor stations in Germany as of December 31, 2007:

Installed Capacity of Total Compressor Units Compressor Units Installed Monitored and Monitored and Compressor Compressor Capacity Maintained by Maintained by Owned or Co-owned by Stations Units MW E.ON Ruhrgas AG E.ON Ruhrgas AG MW E.ON Ruhrgas AG (transportation and storage) ...... 15 44 384 44 384 DEUDAN (PC) (transportation) . . . 2 4 16 0 0 EGL (PC) (storage) ...... 1 2 13 0 0 GHG Hannover (PC) (storage) .... 1 3 4 0 0 MEGAL (PC) (transportation) .... 5 19 201 19 201 METG (PC) (transportation) ...... 2 11 131 11 131 NETG (PC) (transportation) ...... 2 5 50 2 20 NETRA (PC) (transportation) ..... 2 5 43 3 21 TENP (PC) (transportation) ...... 4 15 151 15 151 Total in Germany ...... 34 108 993 94 908

(PC) project company

120 Due to the complexity of the transmission system, together with transmission rights and rights of beneficial use, as well as the number and complexity of factors influencing pipeline utilization, such as temperature, the volume of gas transported and the availability of compressor units, no meaningful data on the utilization of the transmission system is available. E.ON Ruhrgas AG had sufficient pipeline capacity in prior years and booked sufficient pipeline capacity in 2007. E.ON Ruhrgas AG believes that a shortage of pipeline capacity is not a material risk in the foreseeable future.

Storage. Underground gas storage facilities are generally used to balance gas supplies and heavily fluctuating demand patterns. For example, the amount of gas sent out by E.ON Ruhrgas AG on a cold winter day is roughly four times as high as that on a hot summer day, while the flow of gas produced and purchased is much more constant. For this reason, E.ON Ruhrgas AG injects gas into storage facilities during warm weather periods and withdraws it in cold weather periods to cope with peak demand. E.ON Ruhrgas AG stores gas in large underground gas storage facilities, which are located in porous rock formations (depleted gas fields or aquifer horizons) or in salt caverns. Underground gas storage facilities consist of an underground section (cavity or porous rock and wells) and an above-ground part, namely the storage compressor station. As of the end of 2007, E.ON Ruhrgas AG owned five storage facilities, co-owned another two storage facilities and leased capacity in two storage facilities in order to meet its gas storage requirements. In addition, E.ON Ruhrgas AG had storage capacity available through two project companies in which it is a shareholder. Through these owned, co-owned, leased and project company storage facilities, a working gas storage capacity of approximately 5.3 billion m3 was available to E.ON Ruhrgas AG in 2007. Due to the number and complexity of factors influencing storage utilization, particularly temperature and the terms of supply and delivery contracts, E.ON Ruhrgas does not consider data on the utilization of gas storage capacity to be meaningful. E.ON Ruhrgas AG had sufficient storage capacity available both in 2007 and in prior years and does not consider a shortage of gas storage capacity to be a material risk in the foreseeable future. However, depending on a number of factors such as future gas sent out, E.ON Ruhrgas AG’s gas supply and delivery situation and further gas sales potential in European countries other than Germany, E.ON Ruhrgas AG intends to increase working gas capacity by enlarging existing storage facilities, building new facilities and by leasing additional gas storage capacity in the future. In November 2007, E.ON Ruhrgas AG concluded a contract with IVG Kavernen GmbH to rent storage capacities at the location of Etzel. The working gas capacity is expected to amount to up to 2.5 billion m³. Commissioning of the storage facility is planned in stages from 2011 onwards. For information about risks related to the reliability of gas supplies, see also “Risk Factors.” The following table provides more information about E.ON Ruhrgas AG’s underground gas storage facilities, all of which are situated in Germany, as of December 31, 2007:

E.ON Ruhrgas AG’s E.ON E.ON Share in Ruhrgas AG’s Ruhrgas AG’s Maximum Share in Share in Withdrawal Storage Working Rate Facility or in Operated by Underground Storage Capacity (thousand the Project E.ON Facilities (million m(3) m(3) hour) Owned by Company % Ruhrgas AG Bierwang(P) ...... 1,360 1,200 E.ON Ruhrgas AG 100.0 Yes Empelde(C) ...... 18 47 GHG-Gasspeicher Hannover 13.2 — Gesellschaft mbH(PC) Epe(C) ...... 1,761 2,450 E.ON Ruhrgas AG 100.0 Yes Eschenfelden(P) ...... 48 87 E.ON Ruhrgas AG/N-ERGIE AG 66.7 Yes Etzel(C) ...... 371 987 Etzel Gas-Lager GmbH & Co. (PC) 74.8 — Hähnlein(P) ...... 80 100 E.ON Ruhrgas AG 100.0 Yes Krummhörn(C)(1) ...... 0 0 E.ON Ruhrgas AG 100.0 Yes Sandhausen(P) ...... 15 23 E.ON Ruhrgas AG/Gasversorgung 50.0 Yes Süddeutschland GmbH Stockstadt(P) ...... 135 135 E.ON Ruhrgas AG 100.0 Yes Breitbrunn(P) ...... 992(2) 520 RWE Dea AG/ExxonMobil Leased(3) Yes(4) Gasspeicher Deutschland GmbH(3)/ E.ON Ruhrgas AG(4) Inzenham-West(P) ...... 500 300 RWEDeaAG Leased — Total ...... 5,280 5,849

121 (C) salt cavern (P) porous rock (PC) project company (1) Currently out of service for repairs/adjustments. (2) 992 million m3 is the current working gas capacity available to E.ON Ruhrgas AG. (3) Underground section. (4) Above ground part, particularly the storage compressor station.

Monitoring and Maintenance. In 2007, E.ON Ruhrgas AG carried out for itself and under service contracts for E.ON Gastransport and some of the project companies E.ON Ruhrgas AG holds an interest in, monitoring and maintenance services for almost all of E.ON Ruhrgas AG’s transmission system and its underground storage facilities.

Transmission system and underground storage monitoring operations are centered at E.ON Ruhrgas AG’s and E.ON Gastransport’s dispatching facilities in Essen. Among other tasks, the center keeps the technical infrastructure under continual surveillance, handles all reports of disturbances in the system and arranges for the necessary response to any disturbance report. In 2007, E.ON Ruhrgas AG performed this kind of system monitoring for about 12,900 km of pipelines, 23 transport compressor stations, one storage compressor station and seven underground storage facilities. Management of operations, general maintenance (including local monitoring) and troubleshooting are handled by the E.ON Ruhrgas AG field stations and facilities located along the network. E.ON Ruhrgas AG also deploys mobile units from these stations and facilities to carry out maintenance and repair work. For certain sections of pipelines, primarily those where no field station or facility is located nearby, maintenance (including local monitoring) is performed by third parties under service contracts. E.ON Ruhrgas AG’s dispatching, monitoring and maintenance processes are regularly certified under International Standards Organization (“ISO”) 9001:2000 (quality management), ISO 14001 (environmental management), OHSAS 18001, an Occupational Health and Safety Assessment Series for health and safety management systems (work safety management), and TSM, the Technical Safety Management rules of DVGW (The German Technical and Scientific Association for Gas and Water). The DVGW is a self-regulatory body for the gas and water industries, its technical rules serving as a basis for ensuring safety and reliability of German gas and water supplies.

E.ON Gastransport. On January 1, 2004, E.ON Ruhrgas transferred its gas transmission business to a new subsidiary, E.ON Ruhrgas Transport, which in mid-2006 was rebranded as E.ON Gastransport. E.ON Gastransport has sole responsibility for the gas transmission business and functions independently of E.ON Ruhrgas’ sales business, which is a customer of E.ON Gastransport. As the transmission system operator, E.ON Gastransport operates, maintains and develops the E.ON Ruhrgas AG transmission system. It handles all major functions needed for an independent gas transmission business: transmission management (including commercial transport and hub operations), transportation contracts (including access fees), shipper relations, capacity planning and allocation, controlling and billing. E.ON Gastransport obtains certain support services from E.ON Ruhrgas AG under service agreements. On November 1, 2004, E.ON Ruhrgas Transport introduced an entry/exit system called ENTRIX for access to the E.ON Ruhrgas AG gas transmission system as a result of an agreement reached with the Competition Directorate-General of the European Commission with respect to a matter that had been pending before the Competition Directorate. ENTRIX enables customers to book entry and exit capacities for the transmission of gas separately, in different amounts and at different times. Booked capacities can be transferred at short notice and combined with capacities of other customers of E.ON Gastransport.

In order to comply with requirements of the Energy Law of 2005 (described in “— Regulatory Environment”), further improvements of the E.ON Gastransport entry/exit system (now called ENTRIX 2) were launched in February 2006, giving customers more flexible services and making it possible to book freely allocable capacities online. The refined, web-based user interface of ENTRIX 2 contains all customer-relevant information on network access. Screen-based communication has been extended and simplified, serving as a user-friendly interface for all requests. A major refinement of ENTRIX 2 is the possibility to freely allocate entry and exit capacities to each other within the four market areas of the E.ON Ruhrgas AG transmission network, so

122 that capacities that are separately booked can be interlinked without any further case-by-case examination. An additional significant improvement is the replacement of cubic meters per hour as booking unit with kWh per hour, which makes transmission handling easier for customers.

In order to comply with the new gas network access requirements of Germany’s Energy Law of 2005, the gas industry negotiated and signed an agreement regarding cooperation between operators of gas supply networks located in Germany which contains principles for the cooperation of the network operators and standard terms and conditions for access to networks. The agreement uses one network access model with different market areas. Within each market area, which each include a number of network subsections, shippers are entitled to choose the following contractual alternatives for gas transportation: 1) transmission over different networks from an entry point to an exit point at the end consumer or 2) transmission from an entry point to an exit point within a network subsection (the so-called “city gate” alternative). E.ON Gastransport adjusted its entry/exit system in view of the cooperation agreement in October 2006, the date that the new network access model took effect.

Following the development of the gas industry cooperation agreement, a single gas trader and a German energy association filed claims against three network operators (including E.ON Hanse) which challenged the use of the city gate alternative. In November 2006, the German energy regulator decided that this contractual alternative does not comply with the Energy Law of 2005, thus necessitating changes to the existing gas network operators’ cooperation agreement as well as amendments of E.ON Gastransport’s existing transmission contracts. E.ON Gastransport implemented all necessary changes ahead of the October 1, 2007 deadline. For more information, see “— Regulatory Environment — Germany: Gas.”

As from October 2007, E.ON Gastransport will only have two market areas: one for high-calorific gas (H-gas) and one for low-calorific gas (L-gas). By taking this step, E.ON Gastransport is seeking to improve its competitive position on the gas market by trying to create a nationwide market area uniting large quantities of gas from all of Germany’s major international sources. E.ON Gastransport expects its nationwide market area to be highly liquid and particularly attractive for shippers and gas traders.

The level of transmission fees charged by E.ON Gastransport is determined by a revenue benchmark with reference to European peer companies and pipeline and transport competition in Germany (a so-called market- based model for network charges). However, it is possible that the BNetzA will force all gas network operators applying this market-based model to change to a cost-based model, which would result in a significant reduction of network charges of such gas network operators. For further details, see “Risk Factors.”

In September 2005, E.ON Ruhrgas Transport received certification for all of its operations under ISO 9001:2000, ISO 14001 and OHSAS 18001, and in December 2005 received certification under TSM, all of which were confirmed by a reaudit in 2006.

Sales Germany. E.ON Ruhrgas was the largest distributor of natural gas in Germany in 2007, selling a total volume of 532.4 billion kWh of gas. E.ON Ruhrgas also sold 180.4 billion kWh of gas outside of Germany in 2007.

E.ON Ruhrgas sells gas to supraregional and regional distributors, municipal utilities and industrial customers. Customers are concentrated in the western and southern parts of Germany and the areas around Berlin and Bremen, although E.ON Ruhrgas potentially serves customers throughout Germany. The following table sets forth information on the sale of gas by E.ON Ruhrgas’ sales business in Germany for the periods presented:

Total 2007 Total 2006 Sale of Gas to: billion kWh % billion kWh % Distributors ...... 292.5 54.9 318.7 58.0 Municipal utilities ...... 169.8 31.9 163.1 29.7 Industrial customers ...... 70.1 13.2 67.6 12.3 Total ...... 532.4 100.0 549.4 100.0

123 In the table above, sales volumes are presented for all periods excluding relatively minimal amounts of gas that E.ON Ruhrgas does not consider part of its primary sales business, including volumes handled for third parties. In addition, these gas volumes do not include gas volumes attributable to ERI or Thüga.

In January 2006, the German Federal Cartel Office issued a decision prohibiting E.ON Ruhrgas from enforcing its existing long-term gas sales contracts with municipal utilities after October 1, 2006 and from entering into new sales contracts with those customers that are identical or similar in nature. In justifying its decision, the Federal Cartel Office contended that the longer-term sales contracts violate German and European competition law and lead to market foreclosure as they involve long-term customer commitment and typically account for a large share of municipal utilities’ gas requirements. Accordingly, the Federal Cartel Office ruled that sales contracts that account for more than 80 percent of any such customer’s requirements may have a maximum duration of two years, contracts that account for more than 50 percent and up to 80 percent of any such customer’s requirements may have a maximum duration of four years and contracts that account for up to 50 percent of any such customer’s requirements may have longer durations. In addition, the so-called ban on participation in competition is to apply: if it already meets part of any such customer’s requirements, E.ON Ruhrgas is excluded from supplying any additional volume if it would exceed the percentage and duration criteria described above, even temporarily.

E.ON Ruhrgas unsuccessfully sought temporary relief in a summary proceeding in order to prevent the decision from taking immediate effect. Consequently, E.ON Ruhrgas had to terminate, as of September 30, 2006, the contracts with municipal utilities that were covered by the Federal Cartel Office decision. E.ON Ruhrgas challenged the Federal Cartel Office’s decision in a full proceeding before the State Superior Court in Düsseldorf, which ruled in favor of the Federal Cartel Office in October 2007. E.ON Ruhrgas has accepted the decision concerning the limitation of the duration of contracts according to the amount of a customer’s requirements supplied. As far as the decision concerned the ban on participation in competition, E.ON Ruhrgas has decided to challenge it in a proceeding before the Federal Court of Justice. In the mean time, E.ON Ruhrgas has concluded new contracts having a duration of only 1 or 2 years with virtually all of the municipal utilities whose prior contracts it has been required to cancel. See also “Risk Factors.”

As described in “E.ON Gastransport” above, Germany’s energy regulator has decided that a form of gas network access contract widely used by the gas industry does not comply with Germany’s Energy Law of 2005, and E.ON Gastransport has therefore amended its existing gas transmission contracts accordingly. This decision also requires that E.ON Ruhrgas amend its gas sales contracts, and E.ON Ruhrgas made all necessary changes ahead of the October 1, 2007 deadline.

Price terms in all types of sales contracts are generally pegged to the price of competing fuels, primarily gas oil or heavy fuel oil, and provide for automatic quarterly price adjustments based on fluctuations in underlying fuel prices. In addition, medium- and long-term contracts, with terms of over two years, usually contain clauses which enable the parties to review prices and price formulas at regular intervals (usually every one to four years) and to negotiate adjustments in accordance with changed market conditions. Contracts for industrial customers generally provide for some form of take or pay obligation, usually in an amount of 50 to 90 percent of the overall annual contract volume. Contracts with distributors and municipal utilities generally do not include fixed take or pay provisions.

In 2007, the selling prices of E.ON Ruhrgas generally tracked the level of heating oil prices with a time lag. In the course of the year, heating oil prices initially dropped, but then rose from February onwards. Due to the time lag, those increases were not reflected in the selling prices of E.ON Ruhrgas until October 2007.

Gas prices in Germany are also affected by applicable taxes on fossil fuels. In Germany, customers in the commercial/residential sector pay gas prices that include at least 0.67 €cent/kWh in duties and taxes, while industrial customers pay up to 0.47 €cent/kWh in duties and taxes.

124 International. In 2007, E.ON Ruhrgas delivered 180.4 billion kWh of gas to customers in other European countries, or 25.3 percent of the total volume of gas sold by E.ON Ruhrgas, compared with 160.3 billion kWh or 22.6 percent in 2006. The destinations for E.ON Ruhrgas’ external sales are the United Kingdom, Switzerland, the Benelux countries, Austria, France, Hungary, Italy, Sweden, Denmark, Poland, Liechtenstein and Slovakia. The 12.5 percent increase in international sales in 2007 was largely attributable to higher sales volumes in the Netherlands and UK.

Downstream Shareholdings E.ON Ruhrgas owns numerous shareholdings in integrated gas companies, gas distribution companies and municipal utilities through its subsidiaries ERI and Thüga.

ERI holds both majority and minority shareholdings in European and German energy companies, while Thüga holds primarily minority shareholdings in about 90 regional and municipal utilities in Germany. In addition, Thüga’s international shareholdings, which are held through its wholly-owned Italian subsidiary Thüga Italia S.r.l. (“Thüga Italia”), consist of interests in a number of Italian energy companies. Effective as of January 1, 2008, Thüga has sold its wholly-owned Italian subsidiary Thüga Italia together with all its majority and minority shareholdings in Italy to E.ON Italia Holding S.r.l.

ERI: As of December 31, 2007, ERI’s portfolio of shareholdings included stakes in three domestic and 22 foreign companies. In 2007, ERI (including its fully consolidated shareholdings) contributed sales of €4.6 billion (approximately 20.3 percent of E.ON Ruhrgas’ total sales, excluding natural gas and electricity taxes) and had sales volumes of 177.6 billion kWh in 2007 (2006: 152.0 billion kWh).

In May 2007, E.ON Gaz România S.A. was transferred from E.ON Ruhrgas AG to ERI. According to legal unbundling requirements E.ON Gaz România S.A. was split into the two companies E.ON Gaz România S.A. and E.ON Gaz Distributie S.A. at the beginning of July 2007. As of January 15, 2008, the shares in both companies were assigned by ERI to E.ON Gaz Romania Holding S.A.

Germany. As of December 31, 2007, ERI held interests in the following regional gas distribution companies in Germany:

Share held by ERI Shareholding % Ferngas Nordbayern GmbH(1) ...... 53.10 Gas-Union GmbH(1) ...... 25.93 Saar Ferngas AG(1) ...... 20.00 (1) Interest held via ERI’s wholly-owned subsidiary RGE Holding GmbH.

These companies are also customers of E.ON Ruhrgas. Other German gas companies also hold interests in certain of these companies.

125 International. As of December 31, 2007, ERI held interests in the following companies in countries outside of Germany, primarily in central Europe and the Nordic region:

Share held by ERI Shareholding % Gasnor AS, Norway ...... 14.00 Swedegas AB ( formerly: Nova Naturgas AB), Sweden ...... 29.59 Gasum Oy, Finland ...... 20.00 AS Eesti Gaas, Estonia ...... 33.66 JSC Latvijas Gaze, Latvia ...... 47.23 AB Lietuvos Dujos, Lithuania ...... 38.91 Rytu Skirstomieje Tinklai, Lithuania ...... 20.28 Inwestycyjna Spólka Energetyczna Sp.z o.o. (IRB), Poland ...... 50.00 EUROPGAS a.s., Czech Republic(1) ...... 50.00 E.ON Földgáz Trade ZRT, Hungary ...... 100.00 E.ON Földgáz Storage ZRT, Hungary ...... 100.00 Panrusgáz Zrt., Hungary ...... 50.00 Colonia-Cluj-Napoca-Energie S.R.L. (CCNE), Romania ...... 33.33 E.ON Ruhrgas Mittel- und Osteuropa GmbH(2) ...... 100.00 Nafta a.s., Slovakia ...... 40.45 S.C. Congaz S.A., Romania ...... 28.59 E.ON Servicii Romania S.R.L., Romania ...... 50.00 Ekopur d.o.o., Slovenia(3) ...... 100.00 SOTEG — Société de Transport de Gaz S.A., Luxembourg ...... 20.00 Holdigaz SA, Switzerland ...... 2.21 E.ON Gaz Distributie S.A., Romania ...... 51.00 E.ON Gaz România S.A., Romania ...... 51.00 (1) EUROPGAS a.s. holds 50.0 percent of SPP Bohemia a.s. and 48.18 percent of Moravské naftové doly a.s. (MND) in the Czech Republic. (2) E.ON Ruhrgas Mittel- und Osteuropa GmbH has an indirect interest of 24.50 percent in SPP, Slovakia. (3) Ekopur d.o.o. holds 6.52 percent of Geoplin d.o.o. in Slovenia.

As with its German shareholdings, ERI holds some stakes in companies which are customers of E.ON Ruhrgas.

Thüga: As of December 31, 2007, Thüga holds primarily minority shareholdings in about 90 regional and municipal utilities in Germany. In addition, Thüga’s international shareholdings are held through its wholly- owned Italian subsidiary Thüga Italia, and consist mainly of interests in a number of majority and minority shareholdings in Italian gas distribution and sales companies. Through its shareholdings in Italian energy companies, Thüga supplied natural gas to approximately 900,000 end customers in Italy by the end of December 2007, primarily in the regions of Lombardy, Emilia Romagna, Veneto, Friuli-Venezia Giulia and Piedmont. Effective as of January 1, 2008, Thüga has sold its wholly-owned Italian subsidiary Thüga Italia together with all its majority and minority shareholdings in Italy to E.ON Italia Holding S.r.l.

With respect to its minority shareholdings, Thüga is an active shareholder, offering operational competence as well as other services. In 2007, Thüga contributed sales of €1.1 billion (4.6 percent of E.ON Ruhrgas’ total sales, excluding natural gas and electricity taxes). Thüga’s gas sales volumes decreased by 13.8 percent to 19.9 billion kWh in 2007 from 23.1 billion kWh in 2006, primarily as a result of unfavorable weather conditions.

As of December 31, 2007, E.ON Ruhrgas Thüga Holding GmbH held 81.1 percent of Thüga and E.ON Ruhrgas AG, through its subsidiary CONTIGAS Deutsche Energie-Aktiengesellschaft (“Contigas”), held the remaining 18.9 percent.

126 Germany. As of December 31, 2007, Thüga held interests in operating companies which are primarily municipal utilities. The top ten shareholdings in terms of total sales in 2007 are as follows:

Share held by Thüga Shareholding % Stadtwerke Hannover Aktiengesellschaft ...... 24.00 N-ERGIE Aktiengesellschaft ...... 40.81 Mainova Aktiengesellschaft ...... 24.44 Gasag Berliner Gaswerke Aktiengesellschaft ...... 36.85 badenova AG & Co. KG ...... 47.30 HEAG Südhessische Energie AG (HSE) ...... 40.01 DREWAG-Stadtwerke Dresden GmbH ...... 10.00 Erdgas Südbayern GmbH ...... 50.00 Stadtwerke Duisburg AG ...... 20.00 Stadtwerke Karlsruhe GmbH ...... 10.00

International. Effective as of January 1, 2008, Thüga sold its wholly-owned Italian subsidiary Thüga Italia together with all its majority and minority shareholdings in Italy, to E.ON Italia Holding S.r.l. As of December 31, 2007, Thüga held, through its subsidiary Thüga Italia, mainly the following shareholdings in privately owned gas distribution and sales companies as well as in one municipal utility in Italy:

Share held by Thüga Shareholding % E.ON Vendita S.r.l ...... 100.00 Thüga Laghi S.r.l ...... 100.00 Thüga Mediterranea S.r.l ...... 100.00 Thüga Orobica S.r.l ...... 100.00 Thüga Padana S.r.l ...... 100.00 Thüga Triveneto S.r.l ...... 100.00 G.E.I. S.p.A...... 48.94 AMGA Azienda Multiservizi S.p.A ...... 21.60

Competitive Environment Along with oil and lignite/hard coal, natural gas is one of the three primary sources of energy used in Germany. Gas is currently used for a little more than 23 percent of Germany’s energy consumption, and satisfies about a third of the energy demand of the German industrial and commercial/residential sectors. Competing sources of energy include electricity and coal in all sectors, gas oil and district heating in the commercial/ residential sector and gas oil and heavy fuel oil in the industrial sector. Natural gas is also used, but on a limited basis, as an energy source for power stations. Since the 1970s, natural gas has made particular gains in the residential space heating market, where it is marketed as a modern and environmentally-friendly energy source for heating homes. At year-end 2007, approximately 48 percent of German homes were heated using gas, making gas the leading energy source for this market. In 2007, gas was chosen as the heating method for the majority of new homes under construction. Although renewable energies are increasingly popular, natural gas was able to defend its leading position in the heating market.

Within the German gas market, E.ON Ruhrgas competes with domestic and foreign gas companies, the gas subsidiaries of oil producers and pure trading companies. Major domestic competitors include RWE Energy, Verbundnetz Gas AG and Wingas. Foreign competitors include Gaz de France, Econgas, Essent and Nuon. E.ON Ruhrgas currently enjoys a strong market position, supplying approximately 49 percent of all gas consumed in Germany in 2007. Nevertheless, E.ON Ruhrgas considers competition in the German gas market to be vigorous,

127 with both new and established competitors vying for the business of E.ON Ruhrgas’ direct and indirect customers. E.ON Ruhrgas believes it was able to successfully compete in 2007 by remaining flexible in its contract and price negotiations and by offering attractive terms and services to its established and potential customers. In the future it is expected that the new network access model described above in “— Transmission and Storage — E.ON Gastransport” will lead to further intensification of competition.

For information about the debate on long-term gas sales contracts, which the Federal Cartel Office considers to be an obstacle to competition, as well as information about gas price trends in 2007, see “— Sales” above. For information about regulatory developments which are affecting or may affect competition in the German gas market, see “— Regulatory Environment” and “Risk Factors,” which also includes information on investigations of gas prices charged by some German utilities, including utilities in which E.ON Ruhrgas and E.ON Energie hold interests.

Outside Germany, the gas markets in which E.ON Ruhrgas operates are also subject to strong competition. The Company cannot guarantee it will be able to compete successfully in the gas markets in which it is already present or in new gas markets E.ON Ruhrgas may enter.

U.K. Overview E.ON UK is one of the leading integrated electricity and gas companies in the United Kingdom. It was formed as one of the four successor companies to the former Central Electricity Generating Board as part of the privatization of the electricity industry in the United Kingdom in 1989. E.ON UK and its associated companies are actively involved in electricity generation, distribution, retail and trading. As of December 31, 2007, E.ON UK owned or through joint ventures had an attributable interest in 10,581 MW of generation capacity, including 359 MW of CHP plants and 251 MW of operational wind and hydroelectric generation capacity. E.ON UK served approximately 8.0 million electricity and gas customer accounts at December 31, 2007 and its Central Networks business served 4.9 million customer connections. The U.K. market unit recorded sales of €12.6 billion in 2007 and adjusted EBIT of €1.1 billion.

Operations In the United Kingdom, electricity generated at power stations is delivered to consumers through an integrated transmission and distribution system. For information about the principal segments of the electricity industry, see “— Central Europe — Operations.” All electricity transmission in Great Britain is operated by National Grid Transco plc (“National Grid”).

E.ON UK operates significant wholesale and retail gas and electricity businesses and engages in gas and electricity trading. The company served approximately 8.0 million customer accounts at December 31, 2007, including approximately 5.3 million electricity customer accounts and 2.7 million gas customer accounts. As planned, E.ON UK exited the telecoms business in March 2007, and now has no fixed line telephone customer accounts. E.ON UK’s Central Networks distribution business served 4.9 million customer connections as of the end of 2007.

The U.K. market unit comprises the non-regulated business, including energy wholesale (generation and energy trading), retail and energy services, the regulated distribution business, and other activities, such as certain non-distribution assets and the E.ON UK corporate center. In 2007, electricity accounted for 65 percent of E.ON UK’s sales, gas revenues accounted for 33 percent and other activities accounted for 2 percent.

128 The following table sets forth the sources and sales channels of electric power in E.ON UK’s operations during each of 2007 and 2006:

Total 2007 Total 2006 % million kWh million kWh Change Sources of Power Own production(1) ...... 41,236 35,866 +15.0 Purchased power from power stations in which E.ON UK has an interest of 50 percent or less ...... 1,239 731 +69.5 Power purchased from other suppliers(2) ...... 35,499 38,131 -6.9 Power used for operating purposes, network losses and pump storage ...... (159) (971) -83.6 Net power supplied(5) ...... 77,815 73,757 +5.5 Sales of Power Mass market sales (residential customers and small and medium sized enterprises)(3) ...... 34,164 37,893 -9.8 Industrial and commercial sales ...... 18,363 18,371 0 Market sales(4) ...... 25,288 17,493 +44.6 Net power sold(5) ...... 77,815 73,757 +5.5

(1) The increase in own production in 2007 was primarily attributable to improved plant availability and a reduction in wholesale gas prices, which made generation more economically attractive than buying power. (2) The decrease in power purchased from other suppliers and increase in market sales in 2007 compared with 2006 primarily reflects the significant increase in own generation. (3) Mass market sales were lower in 2007 due to lower customer numbers, customer behavior and warmer weather. (4) The increase in market sales results from the reduction in mass market sales and the increase in own generation. (5) Excluding proprietary trading volumes. For information on proprietary trading volumes, see “Non-regulated Business — Energy Wholesale — Energy Trading.”

The following table sets forth the sources and sales channels of gas in E.ON UK’s operations during each of the periods presented:

Total 2007 Total 2006 % million kWh million kWh Change Sources of Gas Long-term gas supply contracts(1) ...... 39,205 42,918 -8.7 Market purchases(2) ...... 167,185 151,064 +10.7 Total gas supplied(3) ...... 206,390 193,982 +6.4 Sales and Use of Gas Gas used for own generation(4) ...... 49,347 38,632 +27.7 Sales to industrial and commercial customers(5) ...... 23,352 28,663 -18.5 Sales to retail mass market customers(6) ...... 55,518 63,888 -13.1 Market sales(7) ...... 78,173 62,799 +24.5 Total gas used and sold(3) ...... 206,390 193,982 +6.4

(1) The reduction in the volume of gas purchased under long-term gas supply contracts in 2007 was primarily the result of reductions in wholesale gas prices, which made spot purchases more economic. (2) The increase in the volume of market gas purchases was attributable to the decline in supply contract volumes as well as an increase in activities to optimize E.ON UK’s gas position.

129 (3) Excluding proprietary trading volumes. For information on proprietary trading volumes, see “Non-regulated Business — Energy Wholesale — Energy Trading.” (4) The increase in gas used for own generation reflects the increase in own generation and excellent rates of plant availability (5) During 2007, the industrial and commercial sales business continued to focus on securing higher value customers, which resulted in lower sales volume in 2007 compared with 2006. (6) Mass market sales were lower in 2007 due to lower customer numbers, customer behavior and warmer weather. (7) Market sales in 2007 were higher than in 2006, reflecting a more dynamic marketplace and increased utilization of trading activity to drive margins combined with reduced mass market sales (see note 6)

Market Environment E.ON UK primarily operates in the electricity generation, electricity and gas trading and the electricity and gas retail energy markets in Great Britain (England, Wales and Scotland) and in the market for electricity distribution in England.

Electricity. Demand for electricity in the United Kingdom has been relatively stable in recent years. In the near term, E.ON UK expects electricity demand in the United Kingdom to grow by an average of approximately 1 percent per annum under normal weather conditions.

The principal commercial features of the electricity industry in the United Kingdom in recent years have been increasing competition in supply through a principle of open access to the transmission and distribution systems. Suppliers are free to compete with each other in supplying electricity to consumers anywhere within England, Wales and Scotland. All electricity supply (retail) and distribution activities were separated in Great Britain in 2001, splitting the market into a liberalized supply sector and a regulated network distribution sector.

On April 1, 2005, a new set of rules known as the British Electricity Trading and Transmission Arrangements (“BETTA”) was introduced in England, Wales and Scotland. This extended the existing NETA arrangements in force in England and Wales to Scotland, providing a market-based framework for electricity trading and wholesale sales, as well as a method of settling trading imbalances and a mechanism for maintaining the stability of the network. Trading activities are characterized by bilateral contracts for the purchase and sale of bulk power and are carried out both on exchanges and over the counter. The Office of Gas and Electricity Markets (“Ofgem”) is responsible for regulatory oversight of BETTA.

E.ON UK believes that it is able to compete more effectively in Scotland (which represents approximately 10 percent of the electricity market in Great Britain as a whole) following BETTA’s introduction.

Gas Market, The UK gas market has been shaped by the decline in the UK’s indigenous production sources on the UK Continental Shelf (“UKCS”). The UK has become increasingly reliant on gas imports and this trend can be expected to continue in the future. New build supply import capacity initially lagged behind the pace of UKCS decline but has been remedied by the completion of the Langeled gas pipeline, BBL gas pipeline and the Teesside Gassport LNG terminal. In general, reliance on imported gas sources has led to greater uncertainty in the market, as UK gas deliveries are heavily influenced by conditions in both the continental European and global gas market. Uncertainty in the market has generally resulted in increased price volatility, which is often further exacerbated by the activities of speculative traders in the market, driving sharp changes in forward prices.

Gas Prices. Prices saw substantial declines during the first quarter of 2007, as mild weather and oversupply on the continent impacted the market. Norwegian deliveries to the UK were very strong, as a result of reduced continental demand. Prices fell further in April, to around 16p/therm, but experienced significant correction at the start of May, to around 25p/therm, as volumes from pipelines reduced when producers experienced production problems. In the third quarter, the market experienced a supply shock in the form of an unplanned outage to the

130 UK CATS pipeline and prices rose to around 30p/therm. In September, the damaged pipeline returned to operation and prices were briefly depressed. A slight upturn in demand however prompted prices to rise to around 40p/therm, as simultaneous planned outages at Rough and IUK storage facilities limited the availability of marginal gas volumes. The fourth quarter saw prices sensitive to weather conditions with storage withdrawals limited.

Power Market. The first quarter of 2007 saw a decline in gas prices which also reduced power prices, keeping spark spreads (difference between power prices and gas and carbon prices) relatively constant. Static coal prices meant that gas generation was the preferable source of power. Towards the end of the second quarter gas prices began to strengthen. The third quarter saw steadily rising coal prices, and some spikes in gas prices, leading to a steady increase in power prices. Gas and coal prices rose sharply in the fourth quarter, leading to sharp increases in power prices. In the fourth quarter, spot power prices have been at their highest levels since March 2006 due to nuclear outages, increased demand during cold weather, extreme supply tightness on the continent, and rising gas prices. Coal prices almost doubled between the first half of the year and November 2007.

Competition. E.ON UK’s exposure to wholesale electricity prices in the United Kingdom is partially hedged by the balance provided by its retail business. The retail energy market in the United Kingdom has consolidated over the last few years into six major competitors. Based on data from Datamonitor, Centrica, previously the monopoly gas supplier branded as British Gas, is currently the market leader in terms of size in both gas and electricity with approximately 17.0 million customer accounts. According to Datamonitor, E.ON UK is now the third largest energy retailer with approximately 8.0 million accounts, during 2007 Scottish and Southern Electricity moved into second place with approximately 8.1 million accounts. The market is characterized by substantial levels of customers switching suppliers in any given year; approximately half of the customers in Great Britain have now switched either their gas or electricity supplier since market liberalization. Churn levels, which measure the percentage of customers switching suppliers, fell generally from 2002 through 2005 as the market matured, before increasing in 2006 in the context of significant price increases. 2007 saw a reduction from 2006 rates, but the increased price sensitivity meant levels remained relatively high. This resulted in E.ON UK’s annual churn rate decreasing from 15.4 percent in 2006 to 15.1 percent in 2007.

Impact of Environmental Measures. The ongoing implementation of environmental legislation is expected to have a significant impact on the energy market in the United Kingdom in coming years. In response, E.ON UK is increasing its production of electricity from renewable sources, as described in more detail below. Environmental measures of particular importance include: • The U.K.’s Renewables Obligation requires electricity retailers to source an increasing amount of the electricity they supply to retail customers from renewable sources. Under the current regime, for the period from April 1, 2007 until March 31, 2008, the renewables obligation is equal to 7.9 percent, rising to a figure of 15.4 percent by 2015/2016. The U.K. government is currently consulting on options to potentially extend targets to a maximum of 20 percent by 2020. The requirement applies to all retail sales over a twelve-month period beginning on April 1 of each year, and Renewables Obligation Certificates (“ROCs”) are issued to generators as evidence of qualified sourcing. ROCs are tradeable, and retailers who fail to present Ofgem with ROCs representing the full amount of their renewables obligation are required to make a balancing payment in the amount of any shortfall into a buy-out fund. Receipts from the buy-out fund are re-distributed to holders of ROCs. • The application in the United Kingdom of the EU Large Combustion Plant Directive prevents coal- and oil-powered generation facilities that have not been fitted with specified sulphur oxide and oxides of nitrogen and particulate matter reduction measures from operating for more than a total of 20,000 hours starting in 2008.

Further information on the emissions allowance trading scheme and the Large Combustion Plant Directive is given in “— Regulatory Environment” and “— Environmental Matters.”

131 Non-regulated Business Energy Wholesale During 2007, E.ON UK’s power generation and energy trading activity was operated and managed under the name of “Energy Wholesale.” This had been the case since 2004, a measure designed to provide a greater strategic focus in the management of E.ON UK’s generation and trading activities and reinforce the close operational ties between the two businesses. For example, the energy trading business is responsible for purchasing commodities used in the production of energy from the generation portfolio. The trading business is best positioned to decide whether E.ON UK should generate or purchase electricity to cover its retail obligations, depending upon the prevailing market price of electricity. For the purpose of describing the business activities of E.ON UK, the two businesses are described separately since they each cover distinct areas of activity.

Power Generation E.ON UK focuses on maintaining a low cost, efficient and flexible electricity generation business in order to compete effectively in the wholesale electricity market. As of December 31, 2007, E.ON UK owned either wholly, or through joint ventures, power stations in the United Kingdom with an attributable registered generating capacity of 10,581 MW, including 359 MW of CHP plants and 50 MW of hydroelectric plant, while its attributable portfolio of operational wind capacity stood at 201 MW. E.ON UK’s share of the generation market in Great Britain remained relatively stable in 2007, at approximately 10 percent.

E.ON UK generates electricity from a diverse portfolio of fuel sources. In 2007, approximately 52.3 percent of E.ON UK’s electricity output was fuelled by coal and approximately 46.2 percent by gas, of which approximately 1.9 percent was from CHP schemes, with the remaining 1.5 percent being generated from hydroelectric, wind and oil-fired plants. E.ON UK is continuing its effort to secure a balanced and diverse portfolio of fuel sources, giving it the flexibility to respond to market conditions and to minimize costs. E.ON UK also regularly monitors the economic status of its plant in order to respond to changes in market conditions.

E.ON UK also owns a minority interest in a company that operates a gas-fired power plant in Turkey (see “— Midlands Electricity Non-Distribution Assets” below).

E.ON UK is progressing with significant investments to improve its generation capacity. This is partly to replace capacity which will be taken out of production in coming years due to applicable environmental regulations. In 2007, E.ON UK started construction of one of the largest gas fired CHP stations in the U.K. at the Isle of Grain in Kent. The scheme is expected to generate 1,200 MW of power and export up to 340 MW of heat and is due to be commissioned in 2009. Progress is also being made on regulatory consents for the construction of two new highly efficient coal units at the Kingsnorth power station site in Kent. The two new units would be built next to the existing four units, incorporating ‘super critical’ boiler technology and are currently expected to come on line during 2012.

Nuclear. E.ON UK does not operate any nuclear power plants.

Renewable Energy. E.ON UK plans to grow its renewable electricity generation business in response to the U.K. regulatory initiatives summarized above. E.ON UK is already one of the leading developers and owner/ operators of wind farms in the United Kingdom, with interests in 21 operational onshore and offshore wind farms with total capacity of 212 MW, of which 201 MW is attributable to E.ON UK.

Potential onshore and offshore projects with an aggregate capacity of approximately 1,134 MW are now in the development phase. In 2007, E.ON UK completed construction of the 18 MW Stags Holt onshore wind farm in Cambridgeshire which became operational in the third quarter.

In 2007, E.ON UK commenced construction of the Robin Rigg offshore wind farm in the Solway Firth on the northwest coast of England. Due for completion in the second quarter of 2009, the 180 MW wind farm is

132 expected to be one of the United Kingdom’s largest offshore wind farms to date, with plans for 60 turbines, each with a capacity of 3 MW. In terms of generating capacity, Robin Rigg is expected to generate 550 GWh each year.

In addition to the planned expansion of its wind farm portfolio, E.ON UK generated from biomass in 2007 (co-firing with coal at the Kingsnorth and Ironbridge power stations), generating a total of 192 GWh of renewable energy by this method during the year. During 2007, work was completed on the construction of a 44 MW wood-burning plant at Steven’s Croft, near Lockerbie in southwest Scotland which is currently being commissioned. Steven’s Croft will be one of the United Kingdom’s largest dedicated biomass plants with annual generation of 330 GWh.

During 2008, E.ON UK expects to continue to develop its capability in marine generation (using tidal, stream and wave power) to position itself to capture future opportunities in this area.

As a part of its balanced approach, E.ON UK seeks to fulfill its renewables obligation through a combination of its own generation, renewable energy purchased from other generators under tradeable ROCs, and direct payment of any residual obligation into the buy-out fund. For the period from April 1, 2006 to March 31, 2007, E.ON UK achieved 46 percent of its renewables obligation through own generation and purchases.

CHP. E.ON UK also operates large scale CHP schemes. CHP is an energy efficient technology which recovers heat from the power generation process and uses it for industrial processes such as steam generation, product drying, fermentation, sterilizing and heating. E.ON UK’s total operational CHP electricity capacity at December 31, 2007 was 359 MW. Clients range across a number of sectors, including healthcare, pharmaceuticals, chemicals, paper and oil refining.

Energy Trading During 2007, E.ON UK’s energy trading unit engaged in asset-based energy trading in gas and electricity markets to assist E.ON UK in commercial risk management and the optimization of its U.K. gross margin. The energy trading unit has played a key role in E.ON UK’s integrated electricity and gas business in the United Kingdom by acting as the “commercial hub” for all energy transactions. It manages price and volume risks and seeks to maximize the integrated value from E.ON UK’s generation and customer assets. In 2008, management responsibility for E.ON UK’s trading activities will be transferred to the new Energy Trading market unit. For information about EET, see “Business — Our Business.”

Energy trading activities include: • Purchasing of coal, gas and oil for power stations; • Dispatching generation and selling the electrical output and ancillary services provided by E.ON UK’s power stations; • Purchasing gas and electricity as required for E.ON UK’s retail portfolio; • Managing the net position and risks of E.ON UK’s generation and retail portfolio; • Managing renewable obligations for the retail portfolio through long-term purchases and trading of ROCs;

• Purchasing and/or trading of CO2 emission certificates and other environmental products, including Levy Exempt Certificates (issued in relation to the U.K. Climate Change Levy); and • Achieving portfolio optimization and risk management.

E.ON UK also engages in a controlled amount of proprietary trading in gas, power, coal, oil and CO2 emission certificates markets in order to take advantage of market opportunities and maintain the highest levels

133 of market understanding required to support its optimization and risk management activities. The following table sets forth E.ON UK’s electricity and gas proprietary trading volumes for 2007 and 2006:

2007 2006 2007 2006 Electricity Electricity Gas Gas Proprietary Trading Volumes billion kWh(1) billion kWh billion kWh(1) billion kWh Energy bought ...... 32.3 14.0 127.4 57.7 Energy sold ...... 32.3 14.0 127.4 57.7 Gross volume ...... 64.6 28.0 254.8 115.4

(1) The increase in traded gas and electricity volumes in 2007 was primarily attributable to favorable market opportunities.

In its energy trading operations, E.ON UK uses a combination of bilateral contracts, forwards, futures, options contracts and swaps traded over-the-counter or on commodity exchanges. E.ON UK also undertakes relatively low levels of trading in other commodities, including ROCs, environmental products and weather derivatives. All of E.ON UK’s energy trading operations, including its limited proprietary trading, are subject to E.ON’s risk management policies for energy trading. For additional information on these policies and related exposures, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about Market Risk.”

E.ON UK has in place a portfolio of fuel contracts of varying volume, duration and price, reflecting market conditions at the time of commitment. Coal contracts with a variety of suppliers within the United Kingdom and overseas ensure that supplies are secured for E.ON UK’s coal-fired plants, while maintaining enough flexibility to minimize the cost of generation across the total generation portfolio. E.ON UK’s coal import facilities at Kingsnorth power station and Gladstone Dock, Liverpool, provide secure access to international coal supplies.

The supply of gas for E.ON UK’s CCGT and CHP plants is sourced through non-interruptible long-term gas supply contracts with gas producers (certain of which contain take or pay provisions), and through purchases on the forward and spot markets. Since October 2004, E.ON Ruhrgas has been a significant supplier of natural gas to E.ON UK pursuant to a long-term supply contract between the parties. The agreed framework for the E.ON Ruhrgas contract is essentially that of a “take or pay” arrangement. Risk management arrangements in respect of the volume and price risks associated with E.ON UK’s gas supply contracts are conducted through trading on the spot, over-the-counter and bilateral markets. For additional details on these contractual commitments, see “Operating and Financial Review and Prospects — Contractual Obligations” and Notes 24 and 25 of the Notes to Consolidated Financial Statements.

Retail E.ON UK sells electricity, gas and other energy-related products to residential, business and industrial customers throughout Great Britain. As of December 31, 2007, E.ON UK supplied approximately 8.0 million customer accounts, of which 7.4 million were residential customer accounts and 0.6 million were small and medium-sized business and industrial customer accounts. During the year, there was a net decrease in the total number of customer accounts of approximately 0.4 million as some customers switched suppliers as a consequence of E.ON’s retail price position in the market. E.ON UK continues to focus on reducing the costs of its retail business, through efficiency improvements, more economical procurement of services and the utilization of lower cost sales channels.

Residential Customers. The residential business had approximately 7.4 million customer accounts as of December 31, 2007. Approximately 65 percent of E.ON UK’s residential customer accounts are electricity

134 customers and 35 percent are gas customers. Individual retail customers who buy more than one product (i.e., electricity, gas or other energy-related products) are counted as having a separate account for each product, although they may choose to receive a single bill for all E.ON UK-provided services. In the residential customers sector, E.ON UK sold 24.6 TWh of electricity and 48.3 TWh of gas in 2007, as compared with 26.5 TWh of electricity and 52.4 TWh of gas in 2006. The lower volumes reflected in both lower customer numbers and warmer weather.

E.ON UK targets residential customers through national marketing activities such as media advertising (including print, television and radio), targeted direct mail, public relations and online campaigns. During 2007, there was a gradual transition from the former Powergen brand to the E.ON brand, with the E.ON brand being used exclusively since December. E.ON seeks to create significant national brand awareness through high profile sponsorships under its E.ON brand. This includes the sponsorship of the FA Cup, England’s most historic soccer competition, which commences each year in August. E.ON UK also sponsors the Tour of Britain cycle race and the King of the Mountains. E.ON UK is in the last year of sponsoring Ipswich Town, a soccer team playing in the English Championship league.

2007 initially saw an environment of falling wholesale energy prices, which drove reductions in electricity and gas retail prices across the industry, although specific decreases varied by supplier. In January, E.ON UK reduced gas and electricity prices for average customers by 16 percent and 5 percent, respectively. The fall in wholesale prices was partially offset by increases in transport costs, distribution costs and environmental costs, and in the final quarter of 2007 wholesale prices rose significantly, putting upward pressure on retail prices. Wholesale costs (calculated during the first quarter 2008) have gone up by 60 percent for gas and 88 percent for electricity since February 2007. As a consequence a number of suppliers increased their prices during the first quarter of 2008; RWE NPower announced price rises of 17.2 percent for gas and 12.7 percent for electricity; EDF Energy announced price rises of 12.9 percent for gas and 7.9 percent for electricity, British Gas announced price rises of 15.4 percent for both gas and electricity and Scottish Power announced price rises of 15 percent for gas and 14 percent electricity. E.ON UK has also announced price rises of 15 percent for gas and 9.7 percent for electricity from February 8, 2008. Approximately 550,000 customers on price protection, fixed price or Staywarm products will be unaffected. E.ON UK has also implemented a package of measures to limit the effects of rising wholesale costs by offering subsidized energy efficient products including cavity wall and loft insulation to a significant proportion of its customers and delaying the price increases to vulnerable customers until after the winter months. Some of these initiatives contribute to the requirements placed on suppliers in relation to the Energy Efficiency Commitment, which is described in “— Regulatory Environment — U.K.”

Small and Medium-Sized Business and Industrial and Commercial Customers. E.ON UK’s number of accounts in this sector totaled approximately 0.6 million at year-end 2007. In this sector, E.ON UK sold 27.9 TWh of electricity and 30.6 TWh of gas in 2007, as compared with 29.7 TWh of electricity and 40.1 TWh of gas in 2006. E.ON UK’s focus in this area remains on acquiring and retaining the most profitable contracts available.

Energy Services E.ON UK’s Energy Services business was created in July 2005, bringing together the new connections and metering businesses from Central Networks and the home installation activities from Retail with the vision of providing E.ON UK customers with all the services they need to get connected to energy supplies, heat their homes and understand their energy use. As well as establishing a profitable growth business, Energy Services has three further aims in the medium term: (1) to deliver products and services for the Retail and Central Networks businesses; (2) to improve the level of customer service E.ON UK provides; and (3) to demonstrate the E.ON brand values of ‘Performance and Expertise’. Energy Services employs more than 4,000 people, undertakes more than 50 million meter readings and carry out work in around 400,000 homes per year, playing a key part in E.ON UK’s low carbon agenda by delivering energy efficiency measures such as loft and cavity wall insulation services. The results of this business have been reported within the non-regulated business unit since 2006.

135 Regulated Business Distribution The electricity distribution business in the United Kingdom is effectively a natural monopoly within the area covered by the existing network due to the cost of providing an alternative distribution network. Accordingly, it is highly regulated. However, new distribution licenses are available for network developments, including for those areas already covered by an existing distribution license, and electricity distribution could also face indirect competition from alternative energy sources such as gas. For details on the license system, see “— Regulatory Environment — U.K.”

Within the UK there are 14 licensed distribution network operators (DNOs), each responsible for a distribution services area. EON UK’s Central Networks business owns and manages two DNO licenses through Central Networks East plc and Central Networks West plc. The combined service area covers approximately 11,312 square miles, extending from the Welsh border in the West to the Lincolnshire coast in the East and from Chesterfield in the North to the northern outskirts of Bristol in the South and contains a resident population of about 10 million people. The networks distribute electricity to approximately 4.9 million homes and businesses in the combined service area and transport virtually all electricity supplied to consumers in the service area (whether by E.ON UK’s retail business or by other suppliers). Separate distribution licenses are issued for the operation of the two networks but the combined business is managed by a centralized management team and uses the same methodology and staff to operate both networks.

The following table sets forth the total distribution of electric power by E.ON U.K.’s Central Networks business for each of the periods presented:

Total Total 2007 2006 % Distribution of Power to million kWh million kWh Change Large non-domestic customers ...... 25,579 25,915 -1.3 Domestic and small non-domestic customers ...... 30,426 31,238 -2.6 Total ...... 56,005 57,153 -2.0

The decline in the volume of power distributed reflected usage declines following retail price increases to residential and business customers and the mild winter and spring in 2007, which resulted in much less demand for heat.

Distribution charges are billed on the basis of published tariffs, which are set by the company and adhere to Ofgem’s price control formulas. The current price controls that run from April 2005 until March 2010 were agreed with Ofgem in December 2004. The price controls incorporate an allowed rate of return for investing in and operating the network, as well as a five year performance target.

Other Midlands Electricity Non-Distribution Assets E.ON UK also acquired a number of non-distribution businesses in the Midlands Electricity plc (“Midlands Electricity”) transaction, including an electrical contracting operation and an electricity and gas metering business in the United Kingdom, as well as minority equity stakes in companies operating electricity generation plants in England, Pakistan and Turkey. Following disposals in 2004 and 2005, the only remaining generation stake is a 31.0 percent interest in Trakya Electric Uretin ve Ticaret A.S., which owns and operates a 478 MW Combined Cycle Gas Turbine (“CCGT”) plant in Turkey. E.ON UK has decided to retain the electricity and gas metering services business and core parts of the contracting business (including street lighting) within the newly- formed Energy Services business, but has closed or sold the non-core parts of the contracting business.

136 Nordic Overview E.ON Nordic’s principal business, carried out mainly through E.ON Sverige, is the generation, distribution, sales, and trading of electricity, gas and heat, mainly in Sweden. E.ON Sverige is the second-largest Swedish utility (on the basis of electricity sales and production capacity). E.ON Nordic is the largest shareholder in E.ON Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent voting interest. On October 12, 2007, E.ON and Statkraft signed a letter of intent on an asset swap under which E.ON will acquire the 44.6 percent stake in E.ON Sverige held by Statkraft and will thus become the sole shareholder of E.ON Sverige, aside from a small remaining minority interest of 0.05 percent. In return, Statkraft will receive from E.ON power generation assets in Sweden, Germany and the United Kingdom, as well as shares of E.ON AG to make up for the remaining difference in value. The transaction is expected to close in the third quarter of 2008. It requires the consent of the responsible boards and institutions.

For the first half of 2006, E.ON Nordic also held a majority shareholding in E.ON Finland. On June 26, 2006, E.ON Nordic and Fortum Power and Heat Oy (“Fortum”) finalized the transfer of this interest pursuant to an agreement signed on February 2, 2006. In total, 10,246,565 shares, equivalent to 65.56 percent of the share capital and voting interest of E.ON Finland, were transferred to Fortum for total consideration of €393 million. For additional information, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations.”

E.ON Nordic and its associated companies are actively involved in the ownership and operation of power generation facilities. As of December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power stations with a total installed capacity of approximately 18,300 MW, of which its attributable share was approximately 7,400 MW (not including mothballed and shutdown power plants).

In 2007, about 51 percent of the electric power generated by E.ON Nordic through E.ON Sverige was generated at nuclear facilities and about 44 percent at hydroelectric plants. The remaining approximately 5 percent was generated using fuel oil, biomass, natural gas, wind power and waste. E.ON Nordic also supplies gas, is active in the heat and waste business and conducts electricity trading activities. In 2007, E.ON Nordic had sales of €3.7 billion (including €337 million of energy taxes) and adjusted EBIT of €670 million. Electricity contributed 75 percent, heat 12 percent, gas 6 percent and other 7 percent of 2007 sales, net of energy taxes. Other sales are mainly attributable to the waste business, as well as contracting activities. E.ON Nordic traded a total of approximately 62.5 TWh of electricity in 2007 (including both purchases and sales). E.ON Nordic is primarily active in Sweden, but also operates to a minor degree in Finland, Denmark and Poland. In 2007, E.ON Nordic estimates that it supplied about 21 percent of the electricity consumed by end users in Sweden.

In January 2007, a severe storm hit Sweden cutting power to approximately 300,000 households, including approximately 170,000 E.ON Nordic customers. The expenses incurred by E.ON Nordic for providing mandatory compensation to affected customers in accordance with newly enacted Swedish legislation, as well as rebuilding infrastructure, amounted to €95 million.

Operations In the Nordic region, electricity generated at power stations is delivered to consumers through an integrated transmission and distribution system. For information about the principal segments of the electricity industry, see “— Central Europe — Operations.” E.ON Nordic and its associated companies are actively involved in electricity generation, distribution, sales, and trading.

137 The following table sets forth the sources and sales channels of electric power in E.ON Nordic’s operations during each of 2007 and 2006:

Total Total 2007 2006 % million kWh million kWh Change Sources of Power Own generation ...... 30,150 27,901 +8.1 Purchased power from jointly owned power stations ...... 9,845 10,173 -3.2 Power purchased from outside sources ...... 5,473 4,646 +17.9 Total power procured ...... 15,318 14,819 +3.4 Power used for operating purposes and network losses ...... (2,065) (2,154) -4.1 Total ...... 43,403 40,566 +7.0 Sales of Power Residential customers ...... 6,113 6,618 -7.6 Commercial customers ...... 12,027 12,845 -6.4 Sales partners(1)/Nord Pool ...... 25,264 21,103 +19.7 Total ...... 43,403 40,566 +7.0

(1) Sales partners are co-owners in E.ON Nordic’s majority-owned power plants, primarily nuclear power plants, to which E.ON Nordic sells electricity at prices equal to the cost of production.

In 2007, E.ON Nordic produced and procured a total of 43.4 billion kWh of electricity, including 2.1 billion kWh used for operating purposes and network losses. E.ON Nordic purchased a total of 9.8 billion kWh of power from power stations in which it has an interest of 50 percent or less. In addition, E.ON Nordic purchased 5.5 billion kWh of electricity from other sources, mainly from the Nord Pool power exchange. In 2007, E.ON Nordic’s own generation volumes increased by approximately 2.2 billion kWh, primarily as a result of higher water reservoir inflow in the beginning of 2007 and end of 2006. Nuclear power production declined by approximately 0.3 billion kWh due to unplanned outages at Oskarshamn 2 and 3. As a result of lower power production volumes in its jointly owned power plants, E.ON Nordic purchased significantly more power from outside sources (0.8 billion kWh). Sales to residential and commercial customers decreased by approximately 0.5 billon kWh in 2007, mainly due to the unseasonably warm weather during the first half of 2007. Sales to sales partners and Nord Pool increased by approximately 4.2 billion kWh in 2007, mainly due to higher hydroelectric production.

E.ON Nordic also operates wholesale and retail gas businesses in Sweden, Denmark and Finland. The following table sets forth the sources and sales channels of gas in E.ON Nordic’s operations during each of 2007 and 2006:

Total Total 2007 2006 % million kWh million kWh Change Sources of Gas Long-term gas supply contracts ...... 6,796 7,156 -5.0 Market purchases ...... 121 400 -69.9 Total gas supplied ...... 6,917 7,556 -8.5 Sale and Use of Gas Gas used for own generation ...... 1,609 1,775 -9.3 Sales to industrial and distribution customers ...... 4,997 5,006 -0.2 Sales to residential customers ...... 228 257 -11.3 Market sales ...... 82 518 -84.1 Total gas used and sold ...... 6,917 7,556 -8.5

138 Since September 2005, E.ON Ruhrgas has been the sole supplier of natural gas to E.ON Nordic pursuant to long-term supply contracts between the parties. The agreed framework for the E.ON Ruhrgas contracts is essentially that of a “take or pay” arrangement, though it will provide E.ON Nordic with a certain amount of flexibility in relation to the purchase of additional quantities and the deferral of quantities not taken

Market Environment Electricity. The electricity market in the Nordic countries has undergone major and far-reaching changes since the mid-1990s. Electricity market reforms have been instituted with the goal of increasing efficiency. Market integration and increased competition were seen as means to attain this objective. Privatization has not been an objective, and consequently the degree of public ownership in the electricity supply industry is essentially unaffected by the electricity market reforms.

The first major step in Swedish market reform was taken in 1991, with the decision to separate transmission from generation. Svenska Kraftnät, established to manage the main Swedish 200-400 kV transmission network, started operating in 1992. The networks were opened to new participants, and legislation providing for competition became effective January 1, 1996.

Today, the key feature of the Nordic electricity market is that there is a strict separation between the natural monopoly and the competitive parts of the industry. Thus, transmission and distribution, which are seen as natural monopolies, are separated from generation, retail sales and trading. The transmission network in Sweden is therefore owned and managed by Svenska Kraftnät, a state agency controlled by the Swedish state, while distribution activities must be carried out by a legal entity separate from those engaged in retail sales (though common ownership is allowed). In order to make competition in generation and retail sales possible in the Nordic area, third party access to transmission and distribution networks is guaranteed. The prices and quality of transmission and distribution services are subject to regulation by a sector-specific regulator in each country. Moreover, in each country a central transmission system operator is responsible for the stability of the system. Thus, although there is a common spot market and free trade across the national borders, system control remains a national responsibility.

Following deregulation, the electricity trading market in the Nordic countries is a liquid and transparent commodity market with trading taking place through the Nordic electricity exchange Nord Pool. The market participants at Nord Pool include power generators, retail companies, end users, traders and portfolio managers. The electricity exchange markets consist of a physical market (day-ahead for delivery in the next 24-hour period and an intra-day market) and a financial market (contracts of up to six years for hedging and trading). Nord Pool also has clearing operations where all financial contracts traded at Nord Pool and most OTC contracts for Nordic power, contracts for differences between price areas, and emissions allowances are cleared. The current volume of electricity traded at the Nord Pool spot market exchange is equal to more than 60 percent of underlying consumption in the Nordic countries and the volume traded at the financial market is about 6 times the underlying physical consumption in the Nordic countries. The pricing in the Nordic market is therefore efficient, with low transaction costs and high transparency. In addition, the exchange price is used as a reference price for a large part of bilateral trading contracts. The prices on the spot and forward markets are generally used as the price basis in sales contracts with end customers.

The electricity supply system in the Nordic countries is highly dependent on the hydroelectric systems in Norway and Sweden. In a normal year, total hydroelectric generation in the Nordic countries amounts to approximately 190-200 TWh. Hydropower has low variable costs and is highly flexible due to the possibility to regulate the flow of water from the reservoirs. Weak hydrologic balance, meaning less hydropower being produced, entails that more thermal production units with considerable higher marginal costs will have to be put into operation, implying increasing wholesale prices. Although long-term precipitation is relatively stable in the region, wide variations occur in the short term both within individual years and between years. As a result, the price on the Nord Pool electricity spot market can vary widely both within a given year and between years.

139 Since the introduction of the EU emissions trading scheme on January 1, 2005, CO2 emission certificates have had a significant impact on electricity prices in the Nordic countries. The price of CO2 emission certificates is set on the European emissions market, through trading on marketplaces such as ECX and Nord Pool and on the

European OTC market for CO2 emission certificates. The price of CO2 emission certificates for 2007 declined steadily from 5.6 to 0.2 €/ton during 2007.

In 2006, which had a dry start of the year and a wet autumn, the total volume of electrical energy generated by hydropower in the Nordic countries was 191 TWh. The hydrological balance started at a level slightly below normal and reached its lowest level at more than 30 TWh below normal at the end of the summer before increasing to levels near normal at the end of the year. The development of the hydrological situation and the impact of the EU emissions trading scheme resulted in generally high and volatile prices for electricity. The daily average Nordic spot price peaked in August above 80 €/MWh when four nuclear reactors had to be shut down due to the Forsmark incident described below. The monthly average spot price was 40 €/MWh in January, reached its highest value of 66 €/MWh in August and ended up with its lowest value, 33 €/MWh, in December. The volatile spot prices during the year caused an increase in the average electricity spot price in 2006, which reached 49 €/MWh compared with only 29 €/MWh in 2005.

2007 started with high hydroelectric production due to more precipitation than normal in the beginning of the year. Throughout the rest of 2007 the hydrological balance stabilized at above average levels. The overall water inflow amounted to about 220 TWh, roughly 10 percent higher than in a normal year. At the end of 2007, reservoir levels were approximately 10 percent above normal. With a production volume of about 87 TWh, nuclear production developed at nearly the same level as 2006. While 2006 production volumes were negatively affected by precautionary shut downs of nuclear power plants due to the Forsmark 1 incident, production in 2007 was again negatively influenced by unplanned outages of all Swedish power plants, especially Ringhals 1-3 in the beginning of the year. Altogether, the generally good hydrological situation and much lower emission costs resulted in a lower average spot price of 28 €/MWh in 2007 compared to 49 €/MWh in 2006. The spot prices remained rather stable until autumn 2007, when increasing fuel prices led to a sharp rise in the system spot prices, reaching its top at 53 €/MWh in the end of November 2007.

In 2006, the Swedish parliament decided to prolong the electricity certificate system until 2030 in order to support renewable electrical energy. This system, which was introduced in 2003, is a market-based support system in which the price of electricity certificates is the result of the relation between supply and demand on the electricity certificate market. The aim of the system is to increase the volume of electricity produced from renewable sources by 17 TWh by 2016 as compared with the 2002 level. Electricity certificates are granted by the Swedish government to generators of electricity from certain types of renewable sources. For every MWh of electricity produced from such sources the generator is given one certificate that it can sell in addition to the electricity generated. In order to create a demand for electricity certificates, it is mandatory for most electricity end users (including residential end users) to purchase a certain number of certificates in proportion to their consumption. This is known as the quota obligation. During 2004, the quota obligation amounted to 8.1 percent of electricity consumed, and has since risen to 10.4 percent in 2005, 12.6 percent in 2006 and 15.1 percent in 2007. The quota obligation is scheduled to peak at 17.9 percent in 2010-2012 and thereafter decline to 8.9 percent in 2013 due to the phase out of some production units from the system. Any applicable end user who fails to meet this quota obligation must instead pay a quota obligation charge to the Swedish government. E.ON Nordic generally has earned a sufficient number of electricity certificates through its own wind power and biomass production, and also has purchasing agreements with a number of small renewable electricity producers.

E.ON Nordic’s main competitors in the Nordic wholesale market are the Swedish energy company Vattenfall AB (“Vattenfall”), the Finnish utility Fortum and the Norwegian energy company Statkraft. Vattenfall and Fortum are also the main competitors of E.ON Nordic in the Swedish retail market, which is completely deregulated.

Natural Gas. The Swedish gas pipeline system is constructed along the western coast of Sweden, starting in Dragör, Denmark and ending in Gothenburg, Sweden. Gas represents 20 percent of the total energy supply in this

140 region, while at the national level, it comprises somewhat less than 2 percent of Sweden’s total energy supply. In 2007, gas consumption in Sweden amounted to approximately 10 TWh. The Swedish gas market is characterized by a small number of companies and a high degree of vertical integration. There are currently about five competitors active in the Swedish market, with E.ON Nordic accounting for the distribution and sale of approximately half of all gas distributed and sold in Sweden in 2007. The major competitor in the end customer market is the Danish gas company DONG and to a smaller extent municipally owned companies with customers mainly in the geographic area of their municipality. The Finnish pipeline system is constructed in southern part of Finland, and there is only one supply connection, coming from Russia. Total natural gas consumption volumes in Finland are about 40 TWh, of which E.ON Nordic covers 0.7 TWh.

District Heating. District heating supplies residential buildings, commercial premises, and industry with heat for space heating and residential hot water production.

In Sweden, most district heating companies are still owned by municipalities, although the current trend is for large energy groups to acquire municipal companies. E.ON Nordic is actively participating in this privatization process. District heating is not price-controlled. The price of competing alternatives serves, however, as a ceiling for the prices that district heating companies can charge. E.ON Nordic also conducts some heating operations in Denmark and Finland.

Non-regulated Business Power Generation General. E.ON Nordic owns interests in electric power generation facilities, mainly in Sweden, with a total installed capacity of approximately 18,300 MW, of which its attributable share is approximately 7,400 MW (not including mothballed, shutdown or reduced power plants).

E.ON Nordic generates electricity primarily at nuclear and hydroelectric plants, with a small percentage generated at other types of power plants. In 2007, approximately 51 percent of E.ON Nordic’s electric output was generated by nuclear, 44 percent by hydroelectric, and the remaining 5 percent by other fuels including oil, hard coal, biomass, natural gas, wind and waste.

Based on the consolidation principles under IFRS, E.ON Nordic reports 100 percent of revenues and expenses from majority-owned power plants in its consolidated accounts without any deduction for minority interests. Conversely, 50 percent and minority-owned power plants are accounted for by the equity method. Power generation in jointly owned plants is generally reported based on E.ON’s ownership percentage.

The construction of a new gas-fired CHP facility in the Swedish city of Malmö was initiated by E.ON Nordic during 2006. The new plant is expected to begin commercial operation in early 2009 and to contribute a total capacity of 440 MW of electricity and 250 MW of heat. In addition, efficiency improvements, which are aimed at increasing generation capacity, are planned for the nuclear reactors in Forsmark, Ringhals and Oskarshamn. The implementation of these efficiency measures was started in 2005. Pending receipt of the necessary approvals, E.ON Nordic expects that all major efficiency improvements will be completed by 2011.

Nuclear Power. E.ON Nordic operates three Swedish nuclear power plants (Oskarshamn 1 — 3), which provided 51 percent of E.ON Nordic’s total power output in 2007. In addition, E.ON Nordic holds minority participations in all other Swedish nuclear power reactors. E.ON Nordic receives a share of the electrical power produced at these plants according to its respective shareholding. The purchase price for this electricity is determined on the basis of the total costs for each facility and is paid according to the shareholding in each reactor.

E.ON Nordic’s nuclear power plants are required to meet applicable Swedish safety standards, which are described in “— Environmental Matters — Nordic.” In Sweden, nuclear waste is handled by Svensk

141 Kärnbränslehantering AB (“SKB”), which is owned by the domestic nuclear power producers and supervised by various state institutions. Sweden’s low and intermediate-level nuclear waste is deposited in the Repository for Radioactive Operational Waste, located at the Forsmark nuclear power plant. Spent nuclear fuel and other high- level nuclear waste are placed in temporary storage at the Central Interim Storage Facility for Spent Nuclear Fuel, situated near the Oskarshamn nuclear power plant. No long-term repository has yet been constructed for spent nuclear fuel, but SKB is planning to build a deep repository for the long-term storage of all spent nuclear fuel. E.ON Nordic expects that a decision will be taken on where the deep repository is to be built at the earliest by 2012, with the first nuclear waste expected to be stored there after 2020.

In 1997, a law concerning the phase out of nuclear power was passed pursuant to which the government can decide to revoke a license to conduct nuclear operations, but must compensate the owner of the nuclear plants that are phased out. E.ON Nordic’s Barsebäck 1 reactor was closed under this law in 1999, while Barsebäck 2 was closed in 2005, with E.ON Nordic receiving compensation in each case. During 2006, the compensation agreement concerning the closure of Barsebäck 2 was fully and finally implemented, with E.ON Sverige’s interest in Ringhals AB being increased to 29.56 percent at no cost to E.ON Nordic.

E.ON Nordic currently has no other nuclear power plants that have been explicitly targeted for early phase-out by the Swedish government. However, it is unclear if and to what extent such shutdowns may be required in the future.

In Sweden, the financing system for the handling of high-level nuclear waste as well as the dismantling of nuclear facilities is currently based on a fee charged per generated kWh of electricity. The exact amount is regularly calculated based on assumptions about the expected period of operation for each reactor by the Swedish Nuclear Power Inspectorate and ultimately determined by the Swedish government. Nuclear power operators include this fee in the price of electricity and transfer it to the national Nuclear Waste Fund. The purpose of this fund is to cover all expenses incurred for the safe handling and final disposal of spent nuclear fuel, as well as for dismantling nuclear facilities and disposing of decommissioning waste. For information on changes to this financing system, see “— Environmental Matters — Nordic.” Expenses for other low and intermediate-level operational nuclear waste have to be directly covered by the nuclear operators. For this purpose, E.ON Nordic has provisions totaling €8.2 million as of December 31, 2007.

In Sweden, taxes are levied on the production of nuclear power based on the installed nuclear power capacity. This tax amounted to approximately €7,230 per MW of thermal power in 2005. In December 2005, the Swedish parliament approved an 85 percent increase in the nuclear tax effective as of January 2006, at which time the tax increased to approximately €13,400 per MW of thermal power. As a consequence, E.ON Nordic’s related tax expense increased by €36 million in 2006. In 2007, there was no further increase in nuclear production tax. In December 2007, the Swedish parliament approved a further 24 percent increase in the nuclear tax effective as of January 2008, at which time the tax increased to approximately €16,620 per MW of thermal power. As a consequence, E.ON Nordic’s related tax expense will increase by €25 million in 2008.

E.ON Nordic purchases fuel elements for nuclear power plants from international suppliers. E.ON Nordic considers the supply of uranium and fuel elements on the world market to be adequate.

Nuclear generated electricity in the Swedish market decreased significantly in 2007 compared to 2006. 2006 was characterized by high production during the first half of the year and low production during the second half of the year due to the Forsmark incident (a transmission related incident at Forsmark 2 in late July 2006 that resulted in an emergency shutdown of Forsmark 2, and the precautionary shutdown of Oskarhshamn 1 and Oskarshamn 2). The reduced nuclear generation in Sweden during 2007 compared to 2006 was mainly a consequence of prolonged outages at Ringhals and Oskarshamn. Due to the 2006, Forsmark incident, the availability of Forsmark was naturally higher than in 2006 thus partly offsetting lower production from the other Swedish nuclear power plants. Total nuclear generation in the Swedish market was 0.7 TWh lower than in 2006.

142 Hydroelectric. E.ON Nordic operates 115 Swedish hydroelectric plants, which provided approximately 44 percent of E.ON Nordic’s total power output in 2007. Due to the presence of mountains and rivers, hydroelectric plants are generally located in northern Sweden. Due to natural variances in annual water inflow to the hydro reservoirs, hydroelectric plants can be subject to reduced operations during periods of low precipitation. Notably, during periods of low precipitation market prices for electricity increase, while during periods with high precipitation market prices decrease. Thus, variances in rainfall in the region can have a significant positive or negative effect on the Nordic market unit’s financial and operating results. In 2007, the inflow to E.ON Nordic’s hydro reservoirs was about 10 percent above normal inflow. Therefore, the production from hydroelectric assets was significantly higher in the year 2007 compared to 2006. According to the letter of intent signed by E.ON AG and Statkraft, approximately one third of E.ON Nordic’s hydropower plant capacity will be transferred to Statkraft.

Hydropower plants in Sweden are subject to real estate taxes. In 2006, the Swedish parliament approved an increase of the real estate tax rate from 0.5 percent to 1.7 percent. As a consequence, E.ON Nordic’s real estate tax expense increased by €27 million in 2006. In 2007, the Swedish parliament approved a further increase of the real estate tax rate from 1.7 percent to 2.2 percent effective as of January 2008. As a consequence, E.ON Nordic’s real estate tax expense will increase by €13 million in 2008.

Other Power Plants. Power plants fuelled by fuel oil, hard coal, biomass, natural gas, wind power and waste provided the remaining 4 percent of E.ON Nordic’s total power output in 2007. Wind power plants are usually used for electricity base load operations. Oil- and gas-fired plants are only used for peak load operations, when market prices cover the operational cost. The production planning of CHP plants is to a large degree dependent on temperature conditions. Fuel oil, natural gas, hard coal and biomass are generally available from multiple sources, though prices are determined on international commodities markets and are therefore subject to fluctuations. Waste is purchased under supply contracts with local providers.

Demand for power tends to be seasonal, rising in the winter months and typically resulting in additional electricity sales by E.ON Nordic in the first and fourth quarters.

Although E.ON Nordic’s power plants are maintained on a regular basis, there is a risk of failure for power plants of every fuel type. Depending on the associated generation capacity, the length of the outage and the cost of the required repair measures, the economic damage due to such failure can vary significantly. Thus, as with water shortages, power plant outages can negatively affect the market unit’s financial and operating results.

Retail E.ON Nordic and its associated companies sell electricity, gas and district heating, as well as other energy- related services, to residential and commercial customers, mainly in the southern parts of Sweden. In addition, E.ON Nordic sells a limited amount of electricity, gas and district heating to end customers in Denmark, Finland and Poland.

Electricity. As of December 31, 2007, E.ON Nordic supplied electricity to approximately 833,000 electricity customer accounts in Sweden and to a minor degree in Denmark. Through its subsidiaries E.ON Suomi Oy, Kainuun Energia Oy and Karhu Voima Oy, E.ON Nordic supplied approximately 87,000 customers in Finland. Although the majority of E.ON Nordic’s customer accounts are with residential customers, the majority of its sales volumes are with commercial customers. E.ON Nordic sold a total of 18.0 TWh of electricity in 2007, of which 5.5 TWh was delivered to residential customers and 12.5 TWh was delivered to commercial customers (including municipal distributors). E.ON Nordic’s electricity customers are concentrated in the south of Sweden, the areas of Stockholm, Örebro and Norrköping, the Mid-Norrland region, as well as in the eastern and southern parts of Finland, although E.ON Nordic potentially serves customers throughout the Nordic region.

Gas. In the Swedish gas market, E.ON Nordic supplied approximately 13,500 customers with gas in 2007; 3.5 TWh were delivered to large industrial and (mostly municipal) distribution customers, and 0.1 TWh was delivered to residential customers. E.ON Nordic also supplied a small amount of gas in Denmark (0.4 TWh) and Finland (0.7 TWh) in 2007.

143 Heat & Waste. E.ON Nordic sells heating, primarily district heating, to approximately 31,500 customers in Sweden, Denmark and Finland. In 2007, sales of district heating amounted to 5.3 TWh in Sweden, 0.1 TWh in Denmark, and 0.3 TWh in Finland. In addition, E.ON Nordic sold a de minimis amount of heat in Poland in 2007.

E.ON Nordic is also active in the Swedish waste business, mainly through SAKAB Ecoplus AB and SAKAB AB (“SAKAB”). SAKAB’s operations focus on recycling and destroying hazardous waste. In addition, SAKAB treats a small portion of household waste and industrial refuse for heat-recovery purposes. In 2007, E.ON Nordic’s waste activities had combined sales of approximately €60 million. Waste volumes handled amounted to approximately 590,000 tons.

Other Activities. E.ON Nordic provides services for distribution networks and other services primarily in Sweden through E.ON Sverige’s subsidiary E.ON ES AB (formerly ElektroSandberg AB). In August 2006, E.ON Sverige sold a 75.1 percent interest in the broadband communication business E.ON Sverige Bredband AB (“E.ON Sverige Bredband”) to Tele2 Sverige AB (“Tele2”). In June 2007, E.ON Sverige exercised its put option on the remaining 24.9 percent interest in E.ON Sverige Bredband and no longer holds any interest in the company.

Trading Until the end of 2007, E.ON Nordic’s energy trading activities focused on electricity trading on the Nord

Pool exchange, but also to a lesser extent include other commodities such as oil, natural gas, CO2 emission certificates and propane. As soon as E.ON AG takes over Statkraft’s 44.6 percent interest in E.ON Sverige, E.ON Nordic’s trading activities will be transferred to the new Energy Trading market unit. For information about EET, see “Business — Our Business.”

E.ON Nordic uses energy trading to optimize the value of and manage risks associated with its energy portfolio. E.ON Nordic also performs a limited amount of proprietary trading, as well as providing portfolio management services for external clients, including access to energy exchanges, advice and risk management for their portfolios. Since 1999, E.ON Trading Nordic AB has been fully authorized by the Swedish Financial Supervisory Authority to advise and conduct trading on behalf of portfolio management clients.

All of E.ON Nordic’s energy trading operations, including its limited proprietary trading, are subject to E.ON’s risk management policies for energy trading.

The following table sets forth the total volume of E.ON Nordic’s traded electric power in 2007 and 2006.

2007 2006 % Trading of Power million kWh million kWh Change Power sold ...... 31,023 28,281 +9.7 Power purchased ...... 31,508 28,304 +11.3 Total ...... 62,531 56,585 +10.5

The major part of realized trading volumes is usually contracted in the year prior to realization. Trading volumes increased in 2007 compared with 2006 due to higher volumes being contracted as well as realized during 2007.

Regulated Business Electricity Distribution E.ON Nordic and its associated companies are actively involved in electricity distribution activities in both Sweden and Finland.

144 In Sweden, the 200-400 kV electricity grid is owned and managed by Svenska Kraftnät, a state agency controlled by the Swedish state. 30-130 kV electricity is transmitted through a regional distribution network with a length of around 40,000 km, of which E.ON Nordic owns and manages 8,000 km, located in southern Sweden and around Sundsvall in the north of Sweden. The local distribution networks are managed by about 180 different grid companies, including E.ON Nordic. The length of the total local network for Sweden is about 550,000 km, of which E.ON Nordic owns 117,000 km. Balance control for the whole system is managed by Svenska Kraftnät.

In January 2007, Sweden was hit by storm “Per”. This storm caused significant damage to E.ON’s distribution network. In addition, outage compensation to the customers had to be paid according to the current regulatory framework. Approximately 300,000 households in Sweden, including approximately 170,000 of E.ON Sverige’s customers, were affected by power outages. Some customers, including E.ON Sverige customers, were left without electricity for up to ten days. In total, storm-related costs amounted to €95 million, which were accounted for as non-operating expenses.

As a result of a similarly severe storm in 2005, the Swedish government passed new legislation concerning electricity distribution in December 2005. Under the new law, the major part of which came into force on January 1, 2006, a customer shall be compensated for power outages that last more than 12 hours, with the compensation payment being equal to at least 12.5 percent and up to 300 percent of the customer’s annual network charges, with compensation being based on the length of the outage. With effect from January 1, 2011, the maximum allowable period of time for a power outage is 24 hours. Following this new legislation, E.ON Nordic has set the timetable for a major part of the ongoing reinvestments in the electricity network to be completed by 2010. E.ON Nordic expects that this will to a large extent reduce its exposure to weather-related damage in the future. The investments done in “Krafttag”, the major reinvestment program launched after storm “Gudrun” in 2005 to secure and increase the reliability of the local and regional distribution grids, have so far resulted in the number of customers being affected by major disturbances, as well as related costs for the outage fee, being reduced by about 25 percent.

The electricity grid in Sweden is linked to the power transmission grids in Norway, Finland and Denmark. In addition, the Baltic Cable links the Swedish transmission grid to the grid of E.ON Netz in Germany. The Baltic Cable is one of the longest (250 km) direct current submarine cables in the world, with a capacity of 600 MW. E.ON Nordic owns one-third of the cable through E.ON Sverige, with the remaining two-thirds owned by the Norwegian company Statkraft.

In 2007, E.ON Nordic’s distribution network served approximately one million customers, including approximately 593,000 customers in southern Sweden, 325,000 customers in the metropolitan areas of Stockholm/Örebro/Norrköping and 83,000 customers in the Mid-Norrland region. The areas around the cities of Malmö (in southern Sweden), Stockholm, Örebro and Norrköping belong to the more densely populated areas of Sweden, but parts of southern Sweden and Norrland are more rural areas with a lower density.

E.ON Nordic also owns and operates local power distribution grids in Finland through Kainuun Energia Oy (approximately 54,800 customers in eastern Finland), with a length of 12,663 km, and Karhu Voima Oy (16 industrial customers in southern Finland), with a length of 17 km.

145 The following map shows E.ON Nordic’s current distribution areas.

Kainuun Energia

Mid-Norrland

Stockholm

Mälardalen/Örebro Norrköping

Southern Sweden

Malmö

In Sweden and Finland, electricity customers have separate contracts with a retail supplier and an electricity distributor. For this reason, distribution customers of E.ON Nordic may choose other retail suppliers and E.ON Nordic may sell electricity to customers not covered by its own distribution grids. For information on grid access, see “— Regulatory Environment — Nordic.”

Gas Transmission, Distribution and Storage The Swedish gas pipeline system is constructed along the western coast of Sweden, starting in Dragör, Denmark and ending in Gothenburg, Sweden. Gas represents approximately 20 percent of total energy supply in the Nordic region, while at the national level, it comprises somewhat less than 2 percent of Sweden’s total energy supply. The 320 km national gas transmission pipeline is owned by Swedegas AB, a consortium in which E.ON Ruhrgas International AG holds a 29.6 percent interest. E.ON Nordic owns, operates and maintains a regional high-pressure gas pipeline with a length of 202 km and a low-pressure gas distribution pipeline with a length of 1,700 km. In addition, E.ON Nordic has an underground gas storage facility in Getinge with a working capacity of 8.5 million m3 and a maximum withdrawal rate of 40 thousand m3/hour. In 2006, E.ON Nordic transported a total of 6.0 TWh of gas through its gas pipeline system.

The Swedish natural gas market is currently connected to the Danish natural gas market through one supply route. Sweden’s strategic location between two of the largest producers, Russia and Norway, has led to the initiation of several studies and projects with the aim of increasing supplies to or via Sweden.

U.S. Midwest Overview E.ON U.S. is a diversified energy services company with businesses in power generation, retail gas and electric utility services, as well as asset-based energy marketing. Asset-based energy marketing involves the

146 off-system sale of excess power generated by physical assets owned or controlled by E.ON U.S. and its affiliates. E.ON U.S.’s power generation and retail electricity and gas services are located principally in Kentucky, with a small customer base in Virginia and Tennessee. As of December 31, 2007, E.ON U.S. owned or controlled aggregate generating capacity of approximately 7,500 MW. In 2007, E.ON U.S. served more than one million customers. The U.S. Midwest market unit recorded sales of €1,819 million in 2007 and adjusted EBIT of €388 million.

Operations In the areas of the United States in which E.ON U.S. operates, electricity generated at power stations is delivered to consumers through an integrated transmission and distribution system. For information about the principal segments of the electricity industry, see “— Central Europe — Operations.” In 2007, E.ON U.S. was actively involved in generation, transmission, distribution, retail and trading in the states in which it had utility operations.

E.ON U.S. divides its operations into regulated utility and non-regulated businesses. Utility operations are subject to state regulation that sets rates charged to retail customers.

In the regulated utility business, which accounted for 97 percent of E.ON U.S.’s revenues in 2007 (85 percent electricity, 15 percent gas), E.ON U.S. operates two wholly-owned utility subsidiaries: Louisville Gas and Electric Company (“LG&E”), an electricity and natural gas utility based in Louisville, Kentucky, which serves customers in Louisville and 17 surrounding counties, and Kentucky Utilities Company (“KU”), an electric utility based in Lexington, Kentucky, which serves customers in 77 Kentucky counties, five counties in Virginia and one county in Tennessee.

E.ON U.S.’s non-regulated business, which accounted for 3 percent of E.ON U.S.’s sales in 2007, is comprised of the operations of E.ON U.S. Capital Corp. (“ECC”).

Market Environment In the United States, the market environment for electricity companies varies from state to state, depending on the level of deregulation enacted in each jurisdiction.

The electric power industry remains highly regulated at the retail level in much of the U.S., including Kentucky, although in some parts of the country, it has become more competitive as a result of price and supply deregulation and other regulatory changes. In approximately one-third of the United States, retail electricity customers can now choose their electricity supplier; however, some states have taken steps to halt deregulation or implement re-regulation, including Virginia. To better support a competitive industry, federal regulators are transforming the manner in which the electric transmission grid is operated. Transmission owning entities are generally encouraged by federal regulators to transfer individual control over the operation of their transmission systems to regional transmission organizations (“RTOs”). These RTOs are intended to ensure non-discriminatory and open access to the nation’s electric transmission system. Depending on the specifics of deregulation in the states in which they operate, U.S. electric utilities have adopted different strategies and structures, sometimes divesting one or more of the generation, transmission, distribution or supply components of their businesses. E.ON U.S. was previously part of MISO. See the further discussion under “Transmission” below.

E.ON U.S.’s electric service territories are located in Kentucky, Virginia and Tennessee. At present, due to the absence of customer choice or competitive market requirements in Kentucky and Tennessee and the passage of legislation in Virginia exempting KU from the provisions of that state’s liberalization measures, none of E.ON U.S.’s retail utility operations are subject to customer choice or competitive market conditions. E.ON U.S.’s customers are therefore generally required to purchase their electric service from E.ON U.S.’s utility subsidiaries at prices approved by state governmental regulators.

147 E.ON U.S.’s primary retail electric service territories are located in Kentucky, which accounted for 74 percent of E.ON U.S.’s total revenues in 2007. To date, neither the Kentucky General Assembly nor the Kentucky Public Service Commission (“KPSC”) have adopted or announced a plan or timetable for retail electric industry competition in Kentucky. However, the nature or timing of any new legislative or regulatory actions regarding industry restructuring or the introduction of competition and their impact on LG&E and KU cannot currently be predicted.

Although retail choice became available for many customers in Virginia in January 2002 pursuant to the Virginia Electric Restructuring Act (the “Restructuring Act”), KU remains exempt from the provisions of the Restructuring Act until such time as KU provides competitive electric service to retail customers in any other state. Further, in April 2007, Virginia enacted legislation which will terminate competitive electric service in the state at the end of 2008 and adopt a hybrid model of re-regulation, whereby utility rates would be reviewed biannually and a utility’s rate of return on equity will be set so as not to be lower than the average of the rates of return for other regional utilities, subject to certain caps, floors or adjustments. Subject to further developments, KU may or may not undertake such a rate proceeding in early 2009 under this legislation based upon calendar year 2008 financial data. During 2007, KU’s Virginia operations accounted for 5 percent of KU’s total revenues and 2 percent of E.ON U.S.’s total revenues. E.ON U.S.’s very limited Tennessee operations accounted for less than 1 percent of its total revenues in each of 2007 and 2006.

Seasonal variations in U.S. demand for electricity reflect the summer cooling period as the time of peak load requirements, with a lesser peak during the winter heating period, the latter primarily in regions which do not have extensive gas distribution networks. The peak period of retail gas demand is the winter heating period.

Regulated Business LG&E. LG&E is a regulated public utility that generates and distributes electricity to approximately 401,000 customers and supplies natural gas to approximately 326,000 customers in Louisville and adjacent areas of Kentucky as of December 31, 2007. LG&E’s service area covers approximately 700 square miles in 17 counties. LG&E’s coal-fired electric generating plants, most of which are equipped with systems to reduce SO2 emissions, produce a significant amount (97 percent) of LG&E’s electricity; the remainder is generated by gas-fired combustion turbines (approximately 2 percent) and by a hydroelectric power plant. Underground natural gas storage fields assist LG&E in providing economical and reliable gas service to customers. As of December 31, 2007, LG&E owned steam and combustion turbine generating facilities with an attributable capacity of 3,083 MW and a 50 MW hydroelectric facility on the Ohio River.

KU. KU is a regulated public utility engaged in producing, transmitting, distributing and selling electric energy. KU provides electric service to approximately 506,000 customers in 77 counties in central, southeastern and western Kentucky and approximately 30,000 customers in five counties in southwestern Virginia as of December 31, 2007. In Virginia, KU operates under the name Old Dominion Power Company. KU also sells wholesale electric energy to 12 municipalities and five customers in Tennessee. KU’s coal-fired electric generating plants produce a significant amount (96 percent) of KU’s electricity; the remainder is generated by gas-fired combustion turbines (approximately 4 percent) and a hydroelectric facility. As of December 31, 2007, KU owned steam and combustion turbine generating facilities with an attributable capacity of 4,362 MW and a 24 MW hydroelectric facility.

Power Generation Fuel. Coal-fired steam and combustion turbine generating units provided approximately 97 percent of LG&E’s and KU’s net kWh generation for 2007. The remainder of 2007 net generation was produced by natural gas-fueled combustion turbine peaking units (approximately 3 percent) and hydroelectric plants. E.ON U.S. is currently building a second coal-fired (750 MW) unit at Trimble County which is expected to come on line in 2010. E.ON U.S.’s interest will be 75.0 percent. E.ON U.S. has no nuclear generating units and coal will

148 continue to be the predominant fuel used by E.ON U.S.’s subsidiaries for the foreseeable future. LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries for 2008 and beyond and normally augment their coal supply agreements with spot market purchases. The companies have coal inventory policies which they believe provide adequate protection under most contingencies. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine labor issues and other supplier or transporter operating or contractual difficulties.

Each of LG&E and KU expect to continue purchasing much of their coal, which has varying sulphur content ranges, from western Kentucky, southern Indiana, southern Illinois, Ohio and West Virginia, with additional KU purchases from eastern Kentucky. In general, the delivered cost of coal has been rising since late 2002.

LG&E purchases natural gas transportation services from both of the major, trans-continental natural gas transmission pipeline companies operating in the southern Midwest region. LG&E also has a portfolio of gas supply arrangements with a number of suppliers in order to meet its firm sales obligations. These gas supply arrangements have various terms and include pricing provisions that are market-responsive. LG&E believes these firm supplies, in tandem with the pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s gas customers. LG&E operates five underground gas storage fields with a current working gas capacity of 15.1 billion cubic feet. Gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season. LG&E and KU primarily buy natural gas and oil fuel used for generation on the spot market.

LG&E and KU have limited exposure to market price volatility in prices of coal and natural gas, as long as cost pass-through mechanisms, including the fuel adjustment clause and gas supply clause, exist for retail customers. For a more detailed explanation of these mechanisms, see “— Regulatory Environment — U.S. Midwest.”

Asset-Based Energy Marketing. LG&E and KU conduct energy trading and risk management activities to maximize the value of power sales from physical assets they own. These off-system sales accounted for 1.6 TWh in 2007. Energy trading activities are principally forward financial transactions to hedge price risk and are accounted for on a mark-to-market basis in accordance with IAS 39. Prior to the Midwest Independent Transmission System Operator, Inc. (“MISO”) establishing its energy market in April 2005, wholesale forward transactions were treated as own use under IAS 39 and were not marked-to-market.

Transmission E.ON U.S.’s utility subsidiaries LG&E and KU operate 4,924 miles of transmission line. In September 2006, these entities withdrew from MISO, in which they had participated as transmission owning members since 1998 and which commenced commercial operations in February 2002. In connection with their withdrawal from MISO, LG&E and KU paid an exit fee of $33 million, which remains subject to certain adjustments, including a potential partial refund of $6.4 million over eight years, subject to regulatory approval and future calculations. Following exit from MISO, LG&E and KU have contractually engaged two independent third parties to perform certain of oversight and function control activities formerly performed by MISO relating to their transmission systems, in accordance with applicable Federal Energy Regulatory Commission (“FERC”) regulations. The Southwest Power Pool, Inc. (“SPP”) now functions as the transmission system operator and the Tennessee Valley Authority (“TVA”) now functions as the reliability coordinator, respectively, for LG&E and KU.

For additional information about transmission developments, see “— Regulatory Environment — U.S. Midwest.”

Distribution/Retail The electric retail activities of LG&E and KU are limited to their respective service territories in Kentucky, with a small KU service region in Virginia and service to five customers in Tennessee. In 2007, LG&E’s total

149 electric retail sales to residential, commercial and industrial customers were 11.3 billion kWh and its total aggregate electric sales, including off-system sales, were 14.2 billion kWh. In 2007, KU’s total electric retail sales to residential, commercial and industrial customers were 17.1 billion kWh and its total aggregate electric sales were 21.7 billion kWh.

The following table sets forth LG&E’s and KU’s sale of electric power for the periods presented:

Total 2007 Total 2006 Sales of Electric Power to million kWh million kWh Residential ...... 11,333 10,330 Commercial and industrial customers ...... 17,038 16,628 Municipals ...... 2,059 1,978 Other retail ...... 3,871 3,703 Off-system sales ...... 1,629 2,650 Total ...... 35,930 35,289

The gas retail activities of LG&E are limited to its service territory in Kentucky. In 2007, LG&E’s total retail gas sales were 13.1 billion kWh (2006: 12.3 billion kWh) and its total aggregate gas sales (including off-system sales) were 13.6 billion kWh (2006: 12.4 billion kWh).

Non-regulated Businesses

ECC. ECC is the primary holding company for E.ON U.S.’s non-regulated businesses, which now consist primarily of interests in Argentine gas distribution operations which provide natural gas to approximately one million customers in Argentina through two distributors, Distribuidora de Gas del Centro S.A. (“Centro”) and Distribuidora de Gas Cuyana S.A. (“Cuyana”)). ECC owns 45.9 percent of Centro, and 14.4 percent of Cuyana. These operations continue to be subject to economic and political risks typical of emerging markets. In June 2007, ECC sold its interests in the Argentine gas distribution company, Gas Natural BAN S.A. (“Ban”) and related companies for €37 million. ECC had held an approximate 19.6 percent interest in Ban since 1999. In June 2006, ECC sold (i) its 50.0 percent ownership interest in a coal-fired facility in North Carolina and (ii) its remaining operations and maintenance contracts relating to the North Carolina plant and four independent power generation facilities for total consideration of €21 million. ECC also currently owns the discontinued operations of Western Kentucky Energy Corp. and affiliates (“WKE”). For further details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations.”

Environmental Matters General

E.ON is subject to numerous national and local environmental laws and regulations concerning its operations, products and other activities in the various jurisdictions in which it operates. Although E.ON believes that its domestic and international production facilities and operations are currently in material compliance with the laws and regulations with respect to environmental matters, such laws and regulations could require E.ON to take future action to remediate the effects on the environment of prior disposal or release of substances or waste. Such laws and regulations could apply to various sites, including power plants, pipelines and gas storage facilities, and waste disposal sites. Such laws and regulations could also require E.ON to install additional controls for certain of its emission sources or undertake changes in its operations in future years. For greater detail on the application of environmental laws and regulations to E.ON’s operations, see below. E.ON has established and continues to establish accruals for environmental liabilities where it is probable that a liability will be incurred and the amount of the liability can be reasonably estimated. The provisions made are considered

150 to be sufficient for known requirements. E.ON adjusts accruals as new remediation commitments are made and as information becomes available which changes estimates previously made.

The extent and cost of future environmental restoration and remediation programs are inherently difficult to estimate. They depend on the magnitude of any possible contamination, the timing and extent of corrective actions required and E.ON’s share of liability relative to that of other responsible parties.

Any failure to comply with present or future environmental laws or regulations could result in the imposition of fines, suspension of operations or production or alteration of production processes. Such laws or regulations could also require acquisition of expensive remediation equipment or other expenditures to comply with environmental regulation.

Germany During the conference in Meseberg in 2007, the Federal Government enacted the main issues of the Integrated Energy and Climate program (Integriertes Energie- und Klimaprogramm, or “IEKP”). This program aims at the national implementation of the European decisions of spring 2007 concerning climate protection, expansion of renewable energy and energy efficiency. The targets are documented in a package of measures, which is to be concretized in 2008 and to be achieved continuously until 2020. The IEKP has basic consequences for the environmental policy of energy supply companies including E.ON.

A first package of 14 measures on energy efficiency (revision of CHP law, liberalization metering, outline for a new Energy Savings Act, Power Plant Emissions Act, guideline for public sourcing), renewable energies for power and heat (Renewables Act, Regenerative Heat Act, Access Rules for Biogas), biofuels, motor vehicle taxation and on other GHG emissions was adopted by the German Federal Government on December 5, 2007. The legislative procedure started in January 2008.

Combined heat and power generation. To employ fuels more efficiently, the proportion of combined heat and power generation is supposed to be doubled from currently about 12 percent to approximately 25 percent. In order to hit this target, an amendment of the Combined Heat and Power Act (Kraft-Wärme-Kopplungs-Gesetz)is planned to financially support new combined heat and power plants — also for industrial use — and district heating grids.

Renewable Energy Sources Act. The Federal Government aims to increase the share of renewable energies in the electricity sector from currently 14 percent to 25 – 30 percent in 2020 and a continuous increase thereafter. For that purpose, an amendment of the Renewable Energy Sources Act (Erneuerbare-Energien-Gesetz)is envisioned to rearrange among other things the remuneration for the feed in to the network of electricity from offshore wind parks.

Regenerative Heat Act. The Federal Government sees a high potential for renewable energy sources in the heat sector in order to support climate protection and the reduction of fossil fuel consumption. The share of renewable energy in heat supply is to be increased from 6.5 percent in 2007 up to 14 percent by 2020. For these purposes the Regenerative Heat Act (Erneuerbare-Energien-Wärmegesetz) shall define obligations to use renewable energy sources in new buildings.

Main issues to draft an amendment of the Ordinance on Energy Savings. In the building sector, energy requirements determined by the Ordinance on Energy Savings (Energieeinsparverordnung) are going to be raised successively (30 percent in 2009, a post 2012 increase of comparable magnitude). Furthermore the Federal Government envisages the interdiction of electric night storage heaters post 2020. The Cabinet is expected to enact a complete amendment of the Ordinance on Energy Savings in May 2008.

151 Support programs for energy-efficient construction and refurbishment of buildings and social infrastructure. The existing CO2- refurbishment program for buildings (CO2-Gebäudesanierungsprogramm)is going to be enhanced and continuously advanced till 2011. Moreover the support program is intended to tap the full potential of energy savings in urban structures and social infrastructure. Up to €200 million is being provided for reductions in the interest rates of related loans to local authorities.

Research and innovation in the energy sector. The Federal Government strives for new initiatives focusing on climate protection, energy efficiency, renewable energy sources and storage of CO2, thus strengthening the technological leadership of German companies on the global market.

Allocation of funds from the federal budget. The integrated energy and climate policy is also reflected in the federal budget. Approximately €3.3 billion (including up to €400 million from sales of emission certificates and about €700 million from bilateral and multilateral development cooperation) are to be available for climate policy during the fiscal year 2008.

Europe 2007 marked a turning point for the European Union’s climate and energy policy. The European Council agreed in March 2007 to set legally binding targets: A reduction of at least 20 percent in greenhouse gases by 2020 — rising to 30 percent if there is an international agreement committing other developed countries to “comparable emission reductions and a 20 percent share of renewable energies in EU energy consumption by 2020. To translate the European Union’s political decision into action the European Commission proposed a package of measures (Green Package) on January 23, 2008. The proposals are now going into the EU legislative codecision procedure. The process will most likely not be finished before end of 2008. The two major aspects of the package are: • Promotion of Renewable Energies: Today, the share of renewable energy in the EU’s final energy consumption is 8.5 percent. An increase of 11.5 percent is needed on average to meet the target of 20 percent in 2020. The Commission’s proposal is based on a methodology according to which half of the additional effort is shared equally between Member States. The other half is modulated according to GDP per capita. The Commission is not setting sectoral targets except of a minimum requirement of 10 percent for biofuels. Further, the proposed directive aims at removing unnecessary administrative barriers to the growth of renewable energy. • New Emission Trading Scheme post-2012: The European Commission has submitted its proposal

concerning the energy policy aiming at the reduction of CO2-emissions. Based on the decision of the EU Council from March 2007, a decrease of greenhouse gas emissions of 20 percent by 2020 compared to the year 1990 is assumed in the proposal. According to the concept of the Commission, as from 2013 industry, heat production from CHP, refineries and the aviation sector have to purchase by auction on average 20 percent of the hitherto predominantly freely allocated certificates, with the quota rising to 100 percent in 2020. Energy suppliers are supposed to pay for all emission rights as from 2013. A

further shortage of CO2 rights could have consequences for the energy suppliers strategies. With regard to the energy mix, the price for power from coal could increase in relation to gas and consequently influence investment decisions concerning the construction of new power plants. • The EU directive on energy end-use efficiency and energy services (Directive 2006/32/EC of the European Parliament and of the Council of April 5, 2006 on Energy End-Use Efficiency and Energy Services Repealing Council Directive 93/76/EEC) was adopted in February 2006 and must be implemented into national law by May 2008. It provides for indicative targets for member states to reduce overall end energy consumption by nine percent over a nine-year period (ending in 2016), which would be achieved by boosting energy efficiency measures in the EU. The deadline for member states to propose national action plans on end-user energy efficiency was July 2007. The German action plan was submitted in September 2007. The EU Commission is currently monitoring all the national action plans and will then deliver further proposals in the field of energy efficiency. The action plan is currently without legal effect and we cannot predict when the Commission will come out with new proposals.

152 U.K. While E.ON UK in the United Kingdom is subject to the same EU environmental legislation as is E.ON Energie (described above under “— Germany: Electricity”), details of the implementation of that legislation as adopted in the United Kingdom differ from those implemented by the German government. E.ON UK is also subject to national legislation which includes the obligations of the United Kingdom and international conventions to which the United Kingdom adheres. These obligations relate principally to emissions from generating facilities to air, notably of SO2, NOx and dust. Although historically such legislation has primarily affected coal-fired plants, all fossil-fuelled generation may be impacted in the future. E.ON UK is currently in compliance with all applicable emissions regulations.

As an alternative to setting rigid emission limit values, the EU Large Combustion Plants Directive (LCPD) allows each member state to include its existing large combustion plants within a single National Emissions Reduction Plan. The European Commission has agreed to the United Kingdom using a “combined approach” scheme which would allow individual plants to elect to either to be subject to emission limit values, to be part of the National Emissions Reduction Plan or to opt out of the scheme (in which case the plant must shut by the end of 2015 and is limited to 20,000 hours of operation in the period from 2008 to 2015). E.ON UK has decided to opt out the Grain, Kingsnorth and Ironbridge power stations (which it must therefore close by 2015) and to use the emission limit value option for the Ratcliffe power station. The scheme is scheduled to take effect as of January 1, 2008.

The U.K. government has implemented a greenhouse gas emissions allowance trading scheme, as required by the EU’s Emissions Trading Directive. For more information on the Emissions Trading Directive, see “— Regulatory Environment.” The trading scheme requires that each participating plant be covered by one or more CO2 emission certificates, which initially were issued free of charge. E.ON UK has obtained the necessary certificates and is currently participating in the trading scheme. The second commitment period of the trading scheme commenced on January 1, 2008 and will continue until the end of 2012. Installations in the large electricity producer sector, including participating plants operated by E.ON UK, have been allocated certificates according to a set of technology based benchmarks with the level of free allocation varying in relation to the technology of the plant. In addition, large electricity producers, including E.ON UK, have received a reduced level of free allocation compared to the first period, requiring a greater proportion of allowances to be bought from the market to offset actual emissions.

Each of E.ON UK’s fossil-fuelled power stations in the United Kingdom is required to have a Pollution Prevention and Control (PPC) Authorization, issued by a government agency, which regulates releases into the environment and seeks to minimize their impact. The current system of authorizations has been expanded via a new permit system to cover a wider range of matters such as noise, waste minimization and energy conservation, reflecting extended requirements now applicable to all new installations. Applications were made for the necessary permits to bring existing power stations into compliance with the newly-expanded Integrated Pollution Prevention and Control regime during 2006. The permits were all successfully issued during 2007.

Using the flexibility available to it, E.ON UK has responded to the requirements imposed by emission controls with a combination of actions, notably the increased use of gas-fired CCGT plants, the use of low sulphur content fuels, the installation of emission abatement equipment and the development of renewable energy systems.

E.ON UK has operated its own environmental management system since 1991. On January 1, 1999, E.ON UK achieved corporate certification to ISO 14001, the international standard for environmental management, for its electricity production, gas operations and associated services. The certificate was updated to the revised standard ISO 14001:2004 on November 13, 2006 and is valid for a further three years.

E.ON UK is also subject to further environmental regulations affecting its business, including packaging waste regulations and oil storage regulations. In order to comply with the applicable packaging waste regulations, E.ON UK has joined an appropriate recycling scheme. The majority of the waste involved is paper.

153 Nordic Air Pollution. The power and heat production plants of E.ON Nordic’s subsidiaries are subject to EU, international and/or national regulations, and are equipped where necessary with pollution removal devices. The production plants are subject to emission limits for air pollutants such as SOx, NOx and dust, and relevant emissions are continuously measured and reported. In Sweden, there are taxes attached to emitting SOx (for coal, oil and peat) and CO2 (applicable primarily to heat production from coal, oil, natural gas and liquefied petroleum gas). There is also a fee for emitting NOx (applicable to large combustion plants).

Emissions trading for carbon dioxide started in the EU on January 1, 2005. For details on the Emissions Trading Directive, as well as information on the Swedish electricity certificate system, see “— Regulatory Environment.”

The major subsidiaries within E.ON Nordic are operated according to certified environmental management systems (ISO 14001).

Nuclear Energy. In Sweden, the regulatory framework regarding nuclear power regulations is also governed by the international agreements discussed in “— Germany: Electricity” above. In addition, Swedish nuclear power regulations are governed by Swedish law, mainly the Act on Nuclear Activities (SFS 1984:3), the Nuclear Liability Act (SFS 1968:45) and the Act on Financial Measures for handling of Nuclear Waste from Nuclear Operations (SFS 2006:647). Under Swedish law, the owner of a nuclear power station is obliged to conduct operations in such a manner that the required safety standards are maintained and is responsible for nuclear waste management and decommissioning of nuclear facilities. A license is required in order to own or operate a nuclear facility, which is granted by the Swedish government on recommendation by the Swedish Nuclear Power Inspectorate, which supervises all nuclear facilities in Sweden.

According to the Act on Financial Measures for handling of Nuclear Waste from Nuclear Operations (SFS 2006:647), the owner of a nuclear facility in Sweden is under the obligation to pay an amount determined by the Swedish government for each kWh produced in the facility to the Swedish Nuclear Waste Fund. The amounts thus paid, together with any capital gains on the amounts, are to cover the costs for nuclear waste management and the decommissioning of nuclear facilities. In accordance with Swedish law, E.ON Sverige has also given guarantees to governmental authorities to cover possible additional costs related to the disposal of high-level radioactive waste and nuclear power plant decommissioning. See also Note 27 of the Notes to consolidated financial statements.

The main change in the new Financing Act is that the licensed owner and operator of a nuclear reactor, when the reactor is closed, can be obligated to pay an additional fee (in addition to the fee per kWh produced mentioned above) until all the costs of the final disposal of nuclear waste are covered.

For more information about E.ON Nordic’s nuclear power operations, see “— Nordic — Non-Regulated Business — Power Generation.”

Liability. In Sweden, the owner of a nuclear facility is liable for damages caused by accidents in the nuclear facility and accidents caused by nuclear substances to and from the facility. As of December 31, 2007, the liability is limited to an amount equal to SEK 3,063 million (€322 million) per accident, which must be insured according to the Nuclear Liability Act. E.ON Sverige has the necessary insurance for its nuclear power plants.

In November 2004, the Swedish government began an inquiry on Swedish nuclear liability. In May 2006, a final report issued by the inquiry proposed unlimited liability for the proprietor of the facility and that proprietors should be obligated to purchase insurance covering an amount of €700 million per nuclear facility, with an upper limit on obligations to finance the unlimited liability set at €1.2 billion per nuclear facility. If at any given facility one reactor fails, it is not possible to run the remaining reactors. The inquiry has also proposed that the Swedish government — within the model of state guarantees — enter into a reinsurance agreement with the Nordic Nuclear Insurers as direct insurer to cover any remaining liability. It is still unclear when the inquiry’s report will lead to a legislative proposal from the government.

154 U.S. Midwest E.ON U.S.’s operations are subject to a number of environmental laws and regulations in each of the jurisdictions in which it operates, governing, among other things, air emissions, wastewater discharges, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety.

Clean Air Act Requirements. The Clean Air Act (“CAA”) establishes a comprehensive set of programs aimed at protecting and improving air quality in the United States by, among other things, controlling stationary sources of air emissions such as power plants. While the general regulatory framework for these programs is established at the federal level, most of the programs are implemented and administered by the states under the oversight of the U.S. EPA. The key CAA programs relevant to E.ON U.S.’s business operations are described below.

Ambient Air Quality. The CAA requires the EPA to periodically review the available scientific data for six criteria pollutants and establish concentration levels in the ambient air sufficient to protect the public health and welfare with an extra margin for safety. These concentration levels are known as national ambient air quality standards (“NAAQS”). Each state must identify “non-attainment areas” within its boundaries that fail to comply with the NAAQS and develop a state implementation plan (“SIP”) to bring such non-attainment areas into compliance. If a state fails to develop an adequate plan, the EPA must develop and implement a plan. As the EPA increases the stringency of the NAAQS through its periodic reviews, the attainment status of various areas may change, thereby triggering additional emission reduction obligations under revised SIPs aimed at achieving attainment.

In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional reductions in SO2 and NOx emissions from power plants. In 1998, the EPA issued its final “NOx SIP Call” rule requiring reductions in NOx emissions of approximately 85 percent from 1990 levels in order to mitigate ozone transport from the midwestern United States to the northeastern United States. To implement the new federal requirements, in 2002 Kentucky amended its SIP to require electric generating units to reduce their NOx emissions to 0.15 pounds weight per million British thermal units (“lb./mmBtu”) on a company-wide basis. In

2005, the EPA issued the Clean Air Interstate Rule (“CAIR”), which requires additional SO2 emission reductions of 70 percent and NOx emission reductions of 65 percent from 2003 levels. The CAIR provides for a two-phase cap and trade program, with initial reductions of NOx and SO2 emissions due by 2009 and 2010, respectively, and final reductions due by 2015. The final rule is currently being challenged in a number of federal court proceedings. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAIR. Depending on the level of action determined necessary to bring local non-attainment areas into compliance with the new ozone and fine particulate standards, E.ON U.S.’s power plants are potentially subject to additional reductions in SO2 and NOx emissions. LG&E’s and KU’s weighted-average company-wide emission rates for SO2 in 2007 were approximately 0.50 and 1.33 lbs/MMBtu of heat input, respectively, with every generating unit below its emission limit established by the Kentucky Division for Air Quality and the Louisville Metro Air Pollution Control District (with respect to LG&E).

Hazardous Air Pollutants. As provided in the 1990 amendments to the CAA, the EPA investigated hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”), establishing mercury standards for new power plants and requiring all states to issue new SIPs including mercury requirements for existing power plants. The EPA issued a model rule which provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by 2018. The CAMR provides for reductions of 70 percent from 2003 levels. The EPA closely integrated the CAMR and CAIR programs to ensure that the 2010 mercury reduction targets will be achieved as a “co-benefit” of the controls installed for purposes of compliance with the CAIR. The CAMR is also currently under challenge in the federal courts. In February 2008, in one proceeding, a federal appellate court has issued a decision vacating the current CAMR, an outcome which may have the effect of resulting in more stringent mercury reduction rules, but

155 which ruling could be subject to further appeal. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the federal CAMR. In addition, in 2006 and 2007 state and local air agencies in Kentucky have proposed or adopted rules aimed at regulating additional hazardous air pollutants from sources including power plants. To the extent those rules are final, they are not expected to have a material impact on E.ON U.S.’s power plant operations.

Acid Rain Program. The 1990 amendments to the CAA imposed a two-phase cap and trade program to reduce SO2 emissions from power plants that were thought to contribute to “acid rain” conditions in the northeastern United States. The 1990 amendments also contained requirements for power plants to reduce NOx emissions through the use of available combustion controls.

Regional Haze. The CAA also includes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing future impairment and remedying any existing impairment of visibility in those areas. In 2005, the EPA issued its Clean Air Visibility Rule (“CAVR”), detailing how the CAA’s best available retrofit technology (“BART”) requirements will be applied to facilities, including power plants, built between 1962 and 1974 that emit certain levels of visibility impairing pollutants. Under the final rule, since the CAIR will result in more visibility improvement than BART, states are allowed to substitute the CAIR requirements in their regional haze SIPs in lieu of controls that would otherwise be required by BART. The CAVR is also currently being challenged in the federal courts.

Installation of Pollution Controls. Many of the programs under the CAA utilize cap and trade mechanisms that require a company to hold sufficient emissions allowances to cover its authorized emissions on a company- wide basis and do not require installation of pollution controls on every generating unit. Under cap and trade programs, companies are free to focus their pollution control efforts on plants where such controls are particularly efficient and utilize the resulting emission allowances for smaller plants where such controls are not cost effective. LG&E had previously installed flue gas desulphurization equipment on all of its generating units prior to the effective date of the acid rain program, while KU met its acid rain Phase I SO2 requirements primarily through installation of flue gas desulphurization equipment on Ghent Unit 1. E.ON U.S.’s combined strategy for its acid rain Phase II SO2 requirements, which commenced in 2000, uses accumulated emissions allowances to defer additional capital expenditures and also includes fuel switching or the installation of additional flue gas desulphurization equipment. In order to achieve the NOx emission reductions and associated obligations, E.ON U.S. installed additional NOx controls, including selective catalytic reduction technology, during the 2000 to 2007 time period. In 2001, the KPSC granted approval to recover the costs incurred by LG&E and KU for these projects through the environmental cost recovery surcharge mechanism. Such monthly recovery is subject to periodic review by the KPSC.

In order to achieve the emissions reductions mandated by the CAIR and CAMR, E.ON U.S. expects to incur additional capital expenditures totaling approximately $850 million, during the 2008 through 2010 time period, for pollution controls including flue gas desulphurization and selective catalytic reduction, and to incur additional operating and maintenance costs in operating such controls. In 2005, the KPSC granted recovery in principal of these costs incurred by LG&E and KU, with approval of specific expenditures to occur via its periodic environmental surcharge rate review mechanisms. E.ON U.S. believes its costs in reducing SO2, NOx and mercury emissions to be comparable to those of similarly situated utilities with like generation assets. E.ON U.S.’s compliance plans are subject to many factors including developments in the emissions allowance and fuels markets, future legislative and regulatory enactments, legal proceedings and advances in clean air technology. E.ON U.S. will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

Potential Greenhouse Gas Controls. In 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change (“Kyoto Protocol”) for reducing greenhouse gas emissions took effect, obligating

156 37 industrialized countries to undertake substantial reductions in greenhouse gas emissions. For details, see “Risk Factors — External Risks.” The U.S. has not ratified the Kyoto Protocol and there are currently no mandatory greenhouse gas emissions reduction requirements at the federal level. Legislation mandating greenhouse gas reductions has been introduced in the Congress, but no federal legislation has been enacted to date. In the absence of a program at the federal level, various states have adopted their own greenhouse gas emissions reduction programs, including approximately 12 northeastern states under the Regional Greenhouse Gas Initiative program as well as California. Substantial efforts to pass federal greenhouse gas legislation are ongoing. In addition, litigation is currently pending before various courts to determine whether the EPA and the states have the authority to regulate greenhouse gas emissions under existing law. In one such proceeding, in April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions under the CAA. E.ON U.S. is monitoring ongoing efforts to enact greenhouse gas reduction requirements at the state and federal level and is assessing potential impacts of such programs and strategies to mitigate those impacts. E.ON U.S. is unable to predict whether mandatory greenhouse gas reduction requirements will ultimately be enacted or to determine the reduction targets and deadlines that would be applicable under such programs. As a company with significant coal-fired generating assets, E.ON U.S. could be substantially impacted by programs requiring mandatory reductions in greenhouse gas emissions, although the precise impact on the operations of E.ON U.S. cannot be determined prior to the enactment of such programs.

Brown New Source Review Litigation. During 2006, the EPA issued notices alleging that KU had violated certain provisions of the CAA’s new source review rules relating to work performed in 1997 on a unit at KU’s E.W. Brown generating station and that such unit exceeded heat input values in violation of its air permit. In March 2007, the Department of Justice filed a complaint in federal court in Kentucky alleging the same violations specified in the EPA’s prior notices of violations. The complaint seeks civil penalties, including potential per-day fines, remedial measures and injunctive relief. In April 2007, KU filed an answer in the civil suit denying the allegations. In July 2007, a July 2009 date for trial on the merits was scheduled. The parties continue periodic settlement discussions and a $2 million accrual has been recorded based on the current status of those discussions, however, KU cannot determine the overall outcome or potential effects of these matters, including whether substantial fines, penalties or required remedial construction may result.

General Environmental Proceedings. From time to time, E.ON U.S. appears before the EPA, various state or local regulatory agencies, and state and federal courts regarding matters involving compliance with applicable environmental laws and regulations. Such matters include a notice of violation for alleged noncompliance with the opacity provisions of the CAA at KU’s Ghent station; administrative requests for information issued by the EPA under Section 114 of the CAA requesting new source review data regarding certain construction and maintenance activities at units of LG&E’s Mill Creek and Trimble County and KU’s Ghent generating stations; remediation obligations for former manufactured gas plant sites; liability under the Comprehensive Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; ongoing claims regarding alleged particulate emissions from LG&E’s Cane Run station; and ongoing claims regarding greenhouse gas emissions from E.ON U.S. generating stations. Based on analysis to date, the resolution of such matters is not expected to have a material impact on the operations of E.ON U.S.

Property, Plants And Equipment General The Company owns most of its production facilities and other properties. Some of E.ON’s facilities are subject to mortgages and other security interests granted to secure indebtedness to certain financial institutions. As of December 31, 2007, the total amount of indebtedness collateralized by these facilities was approximately €1.4 billion. E.ON believes that the Group’s principal production facilities and other significant properties are in good condition and that they are adequate to meet the needs of the E.ON Group. E.ON’s headquarters are located at E.ON-Platz 1, D-40479 Düsseldorf, Germany. E.ON owns its headquarters.

157 Production Facilities Central Europe E.ON Energie produces electricity at jointly and wholly-owned power plants. Its power generation facilities have a total installed capacity of approximately 37,200 MW, E.ON Energie’s attributable share of which is approximately 28,500 MW (not including mothballed, shutdown and reduced power plants). Electricity is transmitted to purchasers by means of high-voltage transmission lines and underground cables owned by E.ON Energie. For further details, see “— Central Europe.” E.ON Energie believes that its power plants are in good operating condition and that its machinery and equipment have been well maintained. E.ON Energie’s German base load nuclear power plants operated at approximately 86 percent of available capacity in 2007. E.ON Energie believes that average utilization data calculated on the basis of all of its international and German power stations would not reflect differences between base load and peak load requirements or differential costs of generation and would therefore dilute the significance of such a measure.

Pan-European Gas E.ON Ruhrgas AG owns, co-owns or has interests through project companies in gas pipelines in Germany totaling 11,611 km. In addition, E.ON Ruhrgas AG owns, co-owns or has interests through project companies in 34 compressor stations in Germany. The current installed capacity of these compressor stations totals 993 MW. E.ON Ruhrgas AG also owns, co-owns, leases or has interests through project companies in 11 underground gas storage facilities in Germany; E.ON Ruhrgas AG’s share in the usable working gas storage capacity of these facilities is approximately 5.3 billion m3. Due to the number and complexity of factors influencing gas pipeline and storage utilization, E.ON Ruhrgas AG does not consider data on the utilization of the transmission system and gas storage capacity to be meaningful. E.ON Ruhrgas AG also owns interests in six project companies operating and developing gas transmission systems outside of Germany. For further details, see “— Pan-European Gas — Transmission and Storage.”

E.ON Ruhrgas AG believes that its transmission system (including transport compressor stations) and gas storage facilities (including storage compressor stations) are in good operating condition and that its machinery and equipment have been well maintained.

U.K. E.ON UK produces electricity at jointly and wholly-owned power plants. Its power generation facilities have a total installed capacity of approximately 10,793 MW, E.ON UK’s attributable share of which is approximately 10,581 MW. Electricity is transmitted to purchasers by means of the National Grid transmission network in the United Kingdom. For further details, see “— U.K.” E.ON UK believes that its power plants are in good operating condition and that its machinery and equipment have been well maintained. In 2007, E.ON UK’s power plants operated at approximately 44 percent of theoretical capacity. This average utilization is calculated for all U.K. power stations and does not reflect differences between base load and peak load power stations.

Nordic E.ON Nordic produces electricity at jointly and wholly-owned power plants. Its power generation facilities have a total installed capacity of approximately 18,300 MW, its attributable share of which is approximately 7,400 MW (not including mothballed and shutdown power plants). In Sweden and Finland, electricity is transmitted to purchasers via 200-400 kV electricity grids, which are operated by state-owned companies, and through regional and local distribution networks. E.ON Nordic owns and operates regional and local electricity distribution networks in Sweden and Finland through E.ON Sverige. Through E.ON Sverige, E.ON Nordic also owns one-third of the Baltic Cable, an undersea electricity cable linking the Swedish electricity grid to the grid of E.ON Energie in Germany. In Sweden, E.ON Nordic also owns and operates high-and low-pressure gas pipelines through E.ON Sverige. For more information, see “— Nordic.” E.ON Nordic believes that its power plants,

158 electricity distribution networks and gas pipelines are in good operating condition and that its machinery and equipment have been well maintained. The Swedish base load nuclear power plants in which E.ON Nordic holds an interest operated at approximately 79 percent of available capacity in 2007. E.ON Nordic believes that average utilization data calculated on the basis of all of its power stations would not reflect differences between base load and peak load requirements or differential costs of generation and would therefore dilute the significance of such a measure.

U.S. Midwest E.ON U.S. produces electricity at jointly and wholly-owned power plants. Its power generation facilities have a total installed capacity of approximately 7,600 MW, E.ON U.S.’s attributable share of which is approximately 7,500 MW (not including mothballed and shutdown power plants). Electricity is transmitted to purchasers by means of E.ON U.S.’s transmission network (for which certain functional control is provided by third parties pursuant to FERC regulation) in the United States. For further details, see “— U.S. Midwest.” E.ON U.S. believes that its power plants and transmission networks are in good operating condition and that its machinery and equipment have been well maintained. In 2007, E.ON U.S.’s power plants operated at approximately 55 percent of theoretical capacity. This average utilization is calculated for all U.S. power stations and does not reflect differences between base load and peak load power stations.

Employees As of December 31, 2007, E.ON had 87,815 employees. This increase of 8.9 percent from year-end 2006 is mainly due to the inclusion of the staff from the newly acquired Russian company OGK-4 at the Corporate Center segment. Of the total number of employees, 39.4 percent were based in Germany. The following table sets forth information about the number of employees of E.ON as of December 31, 2007, 2006 and 2005, not including apprentices and managing directors or board members:

Employees at Employees at Employees at December 31, 2007 December 31, 2006 December 31, 2005 Total Germany Foreign Total Germany Foreign Total Germany Foreign Central Europe ...... 44,051 30,598 13,453 43,546 30,199 13,347 44,476 30,307 14,169 Pan-European Gas ...... 12,214 3,446 8,768 12,417 3,371 9,046 13,366 3,411 9,955 U.K ...... 16,786 23 16,763 15,621 13 15,608 12,891 10 12,881 Nordic ...... 5,804 5 5,799 5,693 3 5,690 5,424 2 5,422 U.S. Midwest ...... 2,977 3 2,974 2,890 2 2,888 3,002 2 3,000 Corporate Center ...... 5,983 540 5,443 445 426 19 411 395 16 Total ...... 87,815 34,615 53,200 80,612 34,014 46,598 79,570 34,127 45,443

In addition, E.ON employed 2,656, 2,574 and 2,471 apprentices with limited contracts in Germany at year-end 2007, 2006 and 2005, respectively.

Personnel expenses totaled €4.6 billion in 2007, compared with €4.5 billion in 2006.

Many of the Group’s employees are members of labor unions. Almost all of the union members in Germany belong to the national chemicals/mining/energy and the united services unions. None of E.ON’s facilities in Germany is operated on a “closed shop” basis. In Germany, employment agreements for blue collar workers and for white collar employees below management level are generally collectively negotiated between the association of the companies within a particular industry and the respective unions. In addition, under German law, works councils comprised of both blue collar and white collar employees participate in determining company policy with regard to certain compensation matters, work hours and hiring policy. Management believes its relations with the German trade unions may be characterized as constructive and cooperative.

159 E.ON U.K.’s organizational structure comprises a number of businesses which are supported by a common services business and central functional teams, including finance, legal and human resources. E.ON U.K. has in place a framework, at company and business level, for consultation and collective bargaining with its recognized trade unions. At company level, the E.ON UK Consultative Forum considers matters of common interest across all business units (e.g. E.ON UK performance, business plans, etc.) and consults about UK wide employment policies. At the individual business level, detailed negotiation of pay and other business-specific terms and conditions is negotiated by business level employee forums. These forums consist of representatives from management, trade unions and employees and fulfill a consultative, as well as a negotiating role. Since privatization, E.ON U.K. believes it has maintained constructive relationships with its recognized unions.

In Sweden, approximately 80 percent of E.ON Sverige’s employees are members of various trade unions. E.ON Sverige adheres to two main central collective labor agreements at the national level, on the basis of which E.ON Sverige’s corporate human resources department and representatives from the different trade unions have negotiated a framework for E.ON Sverige. Local human resources departments and local trade union representatives negotiate at the local level. Pursuant to Swedish law, representatives of the unions are members of E.ON Sverige’s board of directors. According to Swedish law, all issues that have an impact on the employees’ working conditions must be negotiated with the trade unions. Management believes its relations with the Swedish trade unions may be characterized as constructive and cooperative.

The level of trade union participation is very high in the eastern European countries in which the Company has operations. Almost all of the Company’s employees in Romania, Hungary, Bulgaria and the Czech Republic are members of the trade unions in the energy and gas sector or at least participate in the collective bargaining agreements that are used in the energy and gas industries. These collective bargaining agreements, which are negotiated between the association of the companies within a particular industry or the individual employer and the respective unions, stipulate compensation levels and most other working conditions for employees. Management believes that its relations with the relevant trade unions may be characterized as constructive and cooperative, and that the continuation of a constructive and cooperative relationship is of great importance for the successful integration of the Company’s recently-acquired operations in Eastern Europe.

The employees of E.ON U.S. who are members of labor unions belong to local units of the International Brotherhood of Electrical Workers (“IBEW”) and The United Steelworkers of America. Most of these union employees are involved in operational and maintenance work in power generation and distribution operations. The majority of E.ON U.S.’s employees are not union members. In the United States, Collective Bargaining Agreements (“CBA”) are negotiated between the local management (i.e., LG&E and KU) and local union representatives. Each CBA generally has a term of three to four years and includes no strike or lock out clauses during the term of the agreement. While E.ON U.S. had an adversarial relationship in the past with the IBEW, its primary union, management believes relations have significantly improved and may now be characterized as cooperative.

Pursuant to EU requirements, E.ON also established a European works council in 1996 that is responsible for cross-border issues. The Company believes that it has satisfactory relations with its works councils and unions and therefore anticipates reaching new agreements with its labor unions on satisfactory terms as the existing agreements expire. There can be no assurance, however, that new agreements will be reached without a work stoppage or strike or on terms satisfactory to the Company. A prolonged work stoppage or strike at any of its major facilities could have a material adverse effect on the Company’s results of operations. The Group has not experienced any material strikes during the last ten years.

Legal Proceedings A number of different court actions (including product liability lawsuits), governmental investigations and proceedings, and other claims are currently pending or may be instituted or asserted in the future against companies of the E.ON Group. This in particular includes legal actions and proceedings concerning alleged

160 price-fixing agreements and anti-competitive practices. In addition, there are lawsuits pending against E.ON AG and U.S. subsidiaries in connection with the disposal of VEBA Electronics in 2000. E.ON Ruhrgas is a party to a number of different arbitration proceedings in connection with the acquisition of Europgas a.s. and in connection with gas delivery contracts entered into with Norsk Hydro Produksjon AS, Gasversorgung Süddeutschland GmbH and Gas Terra B.V. Since litigation or claims are subject to numerous uncertainties, their outcome cannot be ascertained; however, in the opinion of management, any potential obligations arising from these matters will not have a material adverse effect on the financial condition, results of operations or cash flows of the Company.

For information about the conditions and obligations imposed on E.ON in connection with the ministerial approval for E.ON’s acquisition of E.ON Ruhrgas, see “Business — History and Development of the Company.”

For information about proceedings instituted by German or European antitrust authorities affecting E.ON Ruhrgas, E.ON Energie and certain of their subsidiaries, see “Risk Factors.”

E.ON maintains general liability insurance covering claims on a worldwide basis with coverage limits and retention amounts which management believes to be adequate and appropriate in light of E.ON’s businesses and the risks to which they are subject. For a discussion of E.ON Energie’s and E.ON Sverige’s nuclear accident protection, see “— Environmental Matters.”

REGULATORY ENVIRONMENT

EU/Germany: General Aspects (Electricity and Gas) Overview In order to promote competition in the EU energy market, the EU adopted electricity and gas directives (Directive 96/92/EC Concerning Common Rules for the Internal Market in Electricity, or the “First Electricity Directive” and Directive 98/30/EC Concerning Common Rules for the Internal Market in Natural Gas, or the “First Gas Directive”) in 1996 and 1998, respectively.

The First Electricity Directive was intended to open access to the internal electricity markets of EU member states. Germany implemented the First Electricity Directive by enacting an Energy Law (Energiewirtschaftsgesetz, or the “Energy Law”) that entered into force on April 29, 1998.

The First Gas Directive was intended to open access to the internal gas markets of EU member states. The Energy Law already included elements of the First Gas Directive, while an amendment to the Energy Law, which came into effect on May 24, 2003, completed the implementation of the First Gas Directive in German law.

In June 2003, the EU Energy Council amended the First Electricity Directive and replaced it with a new electricity directive (Directive 2003/54/EC Concerning Common Rules for the Internal Market in Electricity, or the “Second Electricity Directive”) and also adopted a second gas directive (Directive 2003/55/EC Concerning Common Rules for the Internal Market in Natural Gas and Repealing Directive 98/30/EC, or the “Second Gas Directive”), which replaced the First Gas Directive. Germany implemented these directives by enacting the new Energy Law of 2005 (Zweites Gesetz zur Neuregelung des Energiewirtschaftsrechts, or the “Energy Law of 2005”), which came into force on July 13, 2005. Corresponding network access and network charges ordinances for electricity and gas came into force on July 29, 2005.

The following paragraphs outline relevant aspects of the Energy Law, the Second Electricity and Gas Directives, and amendments to the Energy Law, as well as other EU proposed and adopted directives and regulations that affect the German energy industry.

E.ON’s operations outside of Germany are subject to the different national and local regulations in the relevant countries.

161 The German Energy Law of 1998 Germany’s Energy Law of 1998 implemented the First Electricity Directive. The Energy Law abolished exclusive supply contracts, thereby introducing competition in the supply of electricity to all consumers and provided (in addition to the so-called “single-buyer” system) for non-discriminatory negotiated third party access to electricity networks (“nTPA”) for all utilities. The German market was opened for all customers in one step, going far beyond the requirements of the First Electricity Directive and also beyond the steps taken by Germany’s neighboring countries. Specifically, in assessing a request for energy transmission, the Energy Law required a transmission company to take into account the extent to which such transmission displaced electricity generated from CHP plants, renewable energy sources and, in eastern Germany, lignite-based power plants and the extent to which it impedes the commercial operation of such power plants. Furthermore, the Energy Law introduced a provision for third party access into the Law Against Restraints of Competition (Gesetz gegen Wettbewerbsbeschränkungen, or “GWB”). In 1998, the first electricity association agreement provided the main basis for an nTPA network access system for electricity in Germany. See “— Germany: Electricity — Electricity Network Access” below.

The Energy Law of 1998 also included — prior to the adoption of the First Gas Directive — certain parts of the First Gas Directive. The Energy Law of 1998 enhanced competition in gas supply to consumers and provided for non-discriminatory nTPA for all utilities. The German gas market was opened for all customers in one step in the year 1998, in this respect going far beyond the requirements of the First Gas Directive and also beyond the steps taken by Germany’s neighboring countries. In 2000, the first gas association agreement provided the main basis for an nTPA network access system for gas in Germany. Technical access rules for household and small commercial customers were introduced in September 2002.

The Second Electricity and Gas Directives Completion of the Internal Electricity Market/The Second Electricity Directive. On June 26, 2003, the EU Energy Council adopted the Second Electricity Directive, which replaced the First Electricity Directive. The Second Electricity Directive required full market opening to competition in each member state by July 1, 2004 for commercial customers and by July 1, 2007 for household customers. The Directive also sets forth general rules for the organization of the EU electricity market, such as the option of the member states to impose certain public service obligations, customer protection measures and provisions for monitoring the security of the EU’s electricity supply. The previous framework of negotiated third party access in Germany is no longer allowed under the Second Electricity Directive. Instead, the Directive requires, at a minimum, that a methodology for calculating network charges be fixed by law or approved by an independent regulatory body, the establishment of which the Second Electricity Directive requires. In addition, the Second Electricity Directive contains provisions requiring the organizational and legal unbundling of transmission and distribution system operators, as well as mandatory electricity labeling for fuel mix, emissions and waste data.

The following paragraphs provide more detail on the independent regulatory authority, legal unbundling, electricity labeling and certain of the public service requirements.

The Second Electricity Directive (as well as the Second Gas Directive, see below) requires the establishment of a regulatory body that is independent of the interests of the electricity and gas industries. According to the Directive, the independent regulator shall be responsible for ensuring non-discriminatory network access, monitoring effective competition and ensuring the efficient functioning of the market. Further, the regulator shall be responsible for fixing or approving the terms and conditions for connection and access to national transmission and distribution networks (or at least the methodologies to calculate such terms), including transmission and distribution charges, and for the provision of balancing services, and shall also have the authority to require transmission and distribution system operators, if necessary, to modify their terms and conditions in order to ensure that they are proportionate and applied in a non-discriminatory manner.

162 In addition, the Second Electricity Directive requires that each transmission and distribution system operator be independent, at least in terms of legal form, organization and decision-making, from other activities not relating to transmission or distribution (“legal unbundling”). This requirement does not imply or result in the requirement to separate the ownership of assets of the transmission network from the vertically integrated undertaking. The Second Electricity Directive enabled member states to postpone the implementation of provisions for legal unbundling of distribution system operations until July 1, 2007 at the latest. Derogations from legal unbundling may also be granted to distribution companies serving less than 100,000 connected customers or small isolated networks. Member states can request an exemption from legal unbundling if they can prove that total and non-discriminatory access to the distribution networks can be achieved by other means.

The Second Electricity Directive requires electricity suppliers to specify in or with bills, as well as in promotional materials for end-user customers, the following information: • The contribution of each energy source to the overall fuel mix of the supplier over the preceding year; and • A reference to where information is publicly available on the environmental impact of the supplier’s

activities, including the amount of CO2 and radioactive waste produced.

Finally, the Second Electricity Directive requires that household customers and — where member states deem it appropriate — small companies must be provided with “universal service,” i.e., the right to be supplied with electricity of a specified quality at reasonable prices.

Completion of the Internal Gas Market/The Second Gas Directive. On June 26, 2003, the EU also adopted the Second Gas Directive, which replaced the First Gas Directive. Similar to the Second Electricity Directive, the Second Gas Directive required full opening of each member state’s gas market to competition by July 1, 2004 for all non-household customers and by July 1, 2007 for all customers. The Directive also sets forth similar general rules for the organization of the EU gas market. The previous framework of negotiated third party gas network access in Germany is no longer allowed under the Second Gas Directive. Instead, as in the Second Electricity Directive, the Second Gas Directive requires regulated third party access and at least a methodology for calculating network charges to be fixed by law or approved by an independent regulatory authority, the establishment of which, the Second Electricity Directive requires. The Directive also requires integrated gas companies to legally unbundle their transmission and distribution system operators from other operations.

The Second Electricity and Gas Directives were required to be implemented by each member state by July 1, 2004.

Revisions of the German Energy Law Prior to the adoption of the Second Gas Directive, the German government amended the Energy Law in May 2003. The amended Energy Law (Erstes Gesetz zur Änderung des Gesetzes zur Neuregelung des Energiewirtschaftsrechts) fully completed the implementation of the First Gas Directive into national law. Apart from provisions to facilitate the opening of the gas market, a new section determined the legal basis for non-discriminatory access to gas networks. In addition, the amended Energy Law formally recognized the relevant electricity and gas association agreements (Verbändevereinbarung Strom II+ and Verbändevereinbarung Gas II) as good commercial practice until December 31, 2003. Furthermore, this amendment modified the provisions of the GWB concerning the suspensive effect of appeals made against decisions of the Federal Cartel Office, so that decisions issued pursuant to the third party access provision of the GWB become immediately applicable.

In order to implement the Second Electricity and Gas Directives, the German legislature passed the Energy Law of 2005 (Zweites Gesetz zur Neuregelung des Energiewirtschaftsrechts), which came into force on July 13, 2005. Corresponding network access and network charge ordinances for electricity and gas came into force on July 29, 2005.

163 Under this new legal framework, the German legislature has authorized the Federal Network Agency (Bundesnetzagentur, or the “BNetzA,” previously called the Regulatory Authority of Telecommunications and Post) to act as the independent regulatory body required by the Second Electricity and Gas Directives, initially with ex-ante supervisory powers. The BNetzA is responsible for fixing or approving or controlling the terms and conditions for connection and access to national transmission and distribution networks, including transmission and distribution charges. The BNetzA (and the state-level regulators) also have the authority to require transmission and distribution system operators, if necessary, to modify their conduct in order to ensure that they act in a non-discriminatory manner.

The following paragraphs provide more detail on the most significant elements of the Energy Law of 2005 for German utilities:

Network access and network charge regulation: The Energy Law of 2005 provides for two phases of regulation. In the starting phase of regulation, the BNetzA and the state-level regulators have to approve the network charges which are calculated by the utilities using a cost-based rate-of-return model if an exemption from cost calculations is not granted for gas transmission networks in case of actual or potential pipeline competitions. If the cost-based rate-of-return-model is applied, the BNetzA and the state-level regulators effectively set the network charges for network operators ex-ante. The allowed capital costs for existing investments are derived from a regulated asset base that is partly valued at current cost. For new investments, the allowed capital costs are derived from a regulated asset base valued at historic cost. See also “— Germany: Electricity — Electricity Network Charges” and “— Germany: Gas — Gas Network Charges” below. A second phase of regulation envisages a new incentive-based regulation system which will replace the current cost-based rate-of-return model. The original BNetzA proposal to the Ministry of Economics in the summer of 2006 was followed by intense political discussion. Due to delay in the legislative process, which only was overcome in November 2007, a second cost-based ex-ante approval scheme of network charges is being used for 2008; the allowed network charges for 2008 will be the starting point for the incentive regulation system in 2009. Under the incentive regulation system, within 10 years, network operators will be expected to lower costs to the level of the most efficient network operators. In addition to individual efficiency (or x-) factors, every electricity network operator will be expected to accomplish a general efficiency gain of 1.25 percent in the first five-year period (four years for gas) and 1.5 percent in the second such period. The individual x-factors are based upon different benchmarkings reflecting network operators’ varying supply situations. Major investments are to be supported by investment budgets, smaller investments to be covered by a flat-rate investment premium of up to 1 percent of annual capital costs. Since major parameters are still to be determined by BNetzA, at this time, E.ON is unable to predict its effects on the Company and on the German energy industry generally.

The Energy Law of 2005 contains an exemption from cost calculations for gas transmission networks if actual or potential pipeline competition can be proven. The law also provides for the development of a special entry/exit system for gas network access, whereby network operators have to offer entry and exit capacities for the transmission of gas separately to system users in order to ensure that system users only need one contract for entry capacities and one contract for exit capacities. The gas network operators together with the Association of the German Gas Industry (Bundesverband der deutschen Gas- und Wasserwirtschaft or “BGW”) developed an entry/exit model in 2006, offering two variants for gas transportation. Following proceedings instituted by a gas trader and a German energy association, however, the BNetzA determined in a November 2006 decision that one of the variants for gas transportation does not comply with the Energy Law of 2005 and required that the gas network operators change their contracts to comply by October 1, 2007. For more information, see “— Germany: Gas — Gas Network Access” below.

Unbundling of network operators: The Energy Law of 2005 requires legal as well as operational (organizational), information and accounting unbundling of each transmission and distribution system operator from the other activities of the utilities. Network operators serving less than 100,000 connected customers are exempt from the legal and operational unbundling obligations.

164 The Company’s German transmission and distribution system operations comply with the legal, operational (organizational), informational and accounting unbundling requirements contained in the Energy Law of 2005.

New Ordinances. The exact interpretation of some of the new regulatory rules is still unclear. Therefore, the Company cannot predict all consequences of the new legal framework for its operations or the overall effect of the new law on its future earnings and financial condition. However, the BNetzA has already interpreted some of the new regulatory rules and ordinances to reach a conclusion that is different than that reached by, and in some cases less favorable to, the Company as well as other German network operators. For more information, see “— Germany: Electricity — Electricity Network Charges” and “— Germany: Gas” below. In 2006, the following ordinance came into effect under the Energy Law of 2005:

Network Connection Ordinance: In November 2006, the network connection ordinance came into force. This ordinance increases potential liability for network operators for damages caused by energy supply disturbances by lowering the negligence threshold required for customers to collect damages. Under the ordinance, simple rather than gross negligence is the required threshold, while damages are capped at a maximum of €5,000 per customer.

In addition, the following ordinance came into effect in 2007: Power Station Grid Connection Ordinance: In June 2007, the German Ministry of Economics issued a power station grid connection ordinance in the same package with its incentive regulation ordinance. The power station ordinance addresses regulatory aspects of power station connection to the electricity grid, and gives certain preferential treatment to the grid connection of new power stations with respect to capacity bottlenecks.

For the ordinance which has replaced the Federal Electricity Charge Regulation (Bundestarifordnung Elektrizität, or “BTOElt”), see “— Germany: Electricity — Electricity Rate Regulation” below.

Further German Legislation Law on the Acceleration of Planning Procedures for Infrastructure. The Law on the Acceleration of Planning Procedures for Infrastructure (Infrastrukturplanungsbeschleunigungsgesetz) came into force in December 2006. Pursuant to this law the costs for the connection of offshore wind power plants will not be paid by the plant operator, but will be borne by all grid users via an apportionment of indirect costs. The additional costs through 2020 are initially distributed among all four transmission system operators in Germany (including E.ON) and will lead to increased grid fees for all grid users.

Energy Tax Act. On August 1, 2006, the Energy Tax Act (Energiesteuergesetz) came into force. The Energy Tax Act, which is based on and incorporates the old Oil Taxation Law (Mineralölsteuergesetz), is the national implementation of the EU energy taxation directive from October 27, 2003 that requires certain minimal tax rates for different forms of energy. Furthermore, the former taxation of gas as an input in electricity generation has been abolished in order to comply with the EU directive, which stipulates that there be no taxation for inputs for electricity production. Since all proposed tax rates in the EU directive are below the actual German tax rates that apply to E.ON, there is currently no risk for the Company of a higher tax burden.

Revisions of the German Competition Law. In Germany, an amendment to the GWB was approved by both houses of parliament in November and December 2007, respectively, was published on December 21, 2007 in the Official Law Bulletin (Bundesgesetzblatt) and entered into force on December 22, 2007. The law extends the competences of the FCO and tightens the rules concerning the abuse of a dominant position. The amendment, which will expire in 2012, stipulates that entities holding a dominant position in an energy market shall not charge or impose prices or other commercial conditions that are less favorable than those of other entities in comparable markets or charge prices that disproportionately exceed their costs. Moreover, the amendment stipulates a shift in the burden of proof to the affected energy companies in antitrust administrative proceedings

165 (but not in civil/private proceedings). We believe that these provisions, if enforced by the FCO or privately, would significantly reduce competition in Germany’s energy markets. The FCO has established, as of January 1, 2008, a new unit dealing with the implementation of this new section of the GWB. Presumably, the FCO will open inquiries about the gas and electricity pricing systems during the course of 2008. Currently we are unable to give any indication about the outcome of possible inquiries or any effects that they could have on us.

European Regulation on Cross-Border Trading The Second Electricity Directive was accompanied by a new EU regulation on cross-border electricity trading (Regulation (EC) No. 1228/2003 on Conditions for Access to the Network for Cross-Border Exchanges in Electricity, or the “Regulation on Cross-Border Electricity Trading”). This regulation required the establishment of a committee of national experts chaired by the European Commission. The committee will adopt guidelines on inter-transmission system operator compensation (“ITC Guidelines”) for electricity transit flows, on the harmonization of national transmission charges and on network congestion management. The applicable guidelines have already been drafted; the congestion management guidelines entered into force at the beginning of December 2006. The ITC Guidelines are expected to enter into force sometime in 2008.

At the EU level, a provisional charge system for cross-border electricity trading came into effect in March 2002. The system provides a fund mechanism to cover costs resulting from cross-border trades. Until 2003, money for the fund was raised from two sources: a charge on exports and socialized costs charged to all electricity customers. As of January 1, 2004, a modified cross-border charge system has taken effect. Instead of charging export fees for international electricity flows, transmission system operators must now pay into a fund according to their net physical import and export flows. As before, the distribution of the funds depends on transit volume, so, as a large transit country, Germany continues to be a net receiver of funds. The transitional system will be continued until the end of 2009, with the relevant contracts already being signed. It is expected that the succeeding system will be based on the above mentioned ITC Guidelines.

Energy Infrastructure and Security of Supply In December 2003, the European Commission proposed a legislative package on energy infrastructure and security of supply. In January 2006, the EU adopted Directive 2005/89/EC Concerning Measures to Safeguard Security of Electricity Supply and Infrastructure Investment (the “Security of Supply Directive”), which requires EU member states to ensure a high level of security of electricity supply by taking necessary measures to facilitate a stable investment climate. The Security of Supply Directive stipulates that transmission system operators set minimum operational rules and obligations for network security, which then may require approval by the relevant authority. Member states must also prepare, in close cooperation with the transmission system operators, a system adequacy report according to EU reporting requirements. Member states were required to transpose the Security of Supply Directive into national law by February 24, 2008. The German Ministry of Economics did not make any amendments as a result, since fundamental rules concerning security of electricity supply are laid down in the German Energy Law of 2005 (operation of energy supply networks, system responsibilities).

In addition, in November 2005 the EU adopted a regulation on conditions for access to gas transmission networks, which covers access to all gas transmission networks in the EU and addresses a number of issues such as access charges (which must reflect the actual costs incurred), third party access services, capacity allocation mechanisms, congestion management, transparency requirements, balancing and imbalance charges, secondary markets (introducing a “use-it-or-lose-it” principle), and information and confidentiality provisions. The regulation also requires the establishment of a committee of national experts chaired by the European Commission, which has the authority to revise the rules annexed to the regulation. The regulation came into effect on July 1, 2006, except for provisions concerning amendment of the rules in the regulation annex, which came into effect on January 1, 2007. The regulation directly affects E.ON Gastransport, which has to comply with these binding rules in its function as a transmission system operator.

166 Security of Energy Supply (Gas) On April 26, 2004, the EU adopted a directive establishing measures to safeguard the security of the EU’s gas supply (Directive 2004/67/EC Concerning Measures to Safeguard Security of Natural Gas Supply, or the “Gas Supply Directive”). The Gas Supply Directive establishes a common framework within which member states must define general, transparent and non-discriminatory security of supply policies compatible with the requirements of a competitive internal gas market, and focuses on measures to be taken if severe difficulties arise in the supply of natural gas. The key elements of the Gas Supply Directive are: • Member states must adopt adequate minimum security of supply standards, and • A “three-step procedure” will take effect in the event of a major supply disruption for a significant period of time. Under the “three-step procedure,” the gas industry should take measures as a first response to such a disruption, followed by national measures taken by member states. In the event of inadequate measures at the national level, the Gas Coordination Group, consisting of representatives of member states, the gas industry and relevant consumers under the chairmanship of the European Commission would then decide on necessary measures.

The Gas Supply Directive was required to be implemented by each member state by May 19, 2006. This directive has been implemented into German law through the Energy Law of 2005.

Regional Markets Electricity. In June 2005, the European Regulator Gas and Electricity Group (“ERGEG”) published a consultation paper on the creation of regional electricity markets and initiated a consultation procedure. The paper identified four action areas: availability of transmission capacity, availability of information, cooperation between network operators and incompatibility of wholesale market arrangements. In its conclusion paper dated February 8, 2006, ERGEG confirmed its intention to pursue the action areas and has therefore set up an “Electricity Regional Initiative.” The objective of the Regional Initiative is to make concrete improvements in the development of a single electricity market in Europe by first integrating national markets into regional markets. The Regional Initiative brings together regulators, the European Commission, member state governments, companies and other relevant parties to focus on the way in which regional energy markets can develop. For each of seven identified European electricity regions, a regional coordination committee has been set up that coordinates the development of harmonized regional network and market rules. The Regional Initiative for the time being focuses on congestion management and transparency of network and market data.

Gas. After publishing a “roadmap” for the development of EU gas markets in April 2006, which contained the introduction of three regional gas markets in Europe, ERGEG drafted a detailed program for the regional market initiative in the summer of 2006 which was discussed in a consultation process during 2007 and will continue to be discussed throughout 2008. The roadmap contains the following measures for the improvement of the current EU gas markets: • closer cooperation between national regulatory authorities; • strict control of unbundling fulfillment, especially in the case of activities in several member states; • ad hoc and transparent publication of non-confidential information; • improvement of third party access at access points; • an improved environment for cross-border trading; and • the creation of regional gas markets.

As part of the consultation process and the workstreams within three designated regional gas markets, North West, South South East and South, all regional gas markets have identified and will continue to pursue the following topics during 2008: • Interconnection and capacity;

167 • Transparency

• Interoperability; and

• Development of gas hubs.

Other issues that are being discussed are the regulatory gaps for cross-border cooperation between regulators.

New European Energy Policy

On January 10, 2007, the European Commission published an “energy package” containing proposals how to establish a new energy policy and strategy for a more integrated and competitive EU internal energy market, for ensuring security of energy supply and to combat climate change. The package of proposals included a series of ambitious targets, but does not yet have any legal impact. The targets were confirmed by the European Council in March 2007.

• One EU-wide energy market. In its policy and strategy package of January 2007, the European Commission announced its strong preference for ownership unbundling, i.e. the separation of ownership of the electricity and gas transmission networks and the other commercial activities of the utilities. As an alternative that does not require ownership unbundling the Commission proposed the use of an independent system operator to operate the electricity and gas transmission networks. Consequently the European Commission on September 19, 2007 published a proposal for a third energy legislative package amending the Second Electricity and Gas Directives as well as the regulations on cross-border electricity trading and on conditions for access to natural gas transmission networks. The draft amendments propose the introduction of ownership unbundling or independent system operators for electricity and gas transmission system operators and the formation of European Networks of Transmission System Operators (ENTSO) formally representing the European electricity / gas transmission system operators. In addition, the powers of national regulators would be harmonized and extended. Further, a new regulation on the cooperation of energy regulators has been proposed by the European Commission which envisages the formation of a new agency for the cooperation of energy regulators that aims at centralizing regulatory decisions to some extent. The directive and regulation proposals are currently in the EU co-decision legislative procedure between the European Parliament and the European Council. In particular, the issue of ownership unbundling is controversial. The German government has clearly announced that it does not support ownership unbundling but that it will analyze all possible options. France and Germany, supported by six other member states, have developed and signed an alternative solution to ownership unbundling. The proposal — the so-called “Third Option” was sent on January 29, 2008, to the Commission, the Council and the European Parliament. The “Third Option” is a complex proposal for “Effective and Efficient Unbundling” which is based on two pillars. The first is related to organization and governance of the undertaking so as to guarantee effective independence of the transmission system operator. The second is related to grid investments, market integration and connection of new power plants. Competences and rules are defined, aiming to ensure sufficient and efficient investment into the grid. It is at this time impossible to predict if the “Third Option” or any of the other proposals will be enacted into law. For details on E.ON’s recent agreement with the Commission on unbundling, see “Risk Factors”.

• Targets and Objectives for reducing Greenhouse gas emissions and promoting renewable energies.In its energy and strategy package of January 2007 the Commission stipulated the objective of a 20 percent cut in greenhouse gas emissions compared to 1990 levels by 2020 at the latest. Should other countries initiate similar plans to combat climate change, the Commission has expressed the possibility of a 30 percent abatement target. For the sectors subjected to emissions trading until 2020 the European

168 Commission aims at a CO2-reduction of 21 percent compared to 2005. In parallel, the EU’s objective for energy generated from renewable sources has been set to account for 20 percent of total energy consumption by 2020 and increasing the level of biofuels in transport fuel to 10 percent by 2020.

Further, the Commission’s objective concerning energy efficiency is to save 20 percent of total primary energy consumption by 2020 compared to 1990 levels. Potential methods include a more efficient use of fuels in vehicles for transport, tougher standards and better labeling for appliances, improved energy performance of the EU’s existing buildings, and improved efficiency of heat and electricity generation, transmission and distribution. For more information see “— Environmental Matters — Europe — The EU directive on energy end-use efficiency and energy services.”

On this basis the European Commission proposed the so called “Green Package” on January 23, 2008, a legislative package which contains i.e. directive proposals for the Emissions Trading Scheme post 2012 and the promotion of renewable energies. For more information, see “— Environmental Matters — Europe.”

Germany: Electricity Electricity Network Access The First Electricity Directive was implemented in Germany with a framework for negotiated third party access to high-, medium- and low-voltage networks agreed by the associations of all German utilities and of industrial customers (Verbändevereinbarung, amended as Verbändevereinbarung II and Verbändevereinbarung II+). Verbändevereinbarung II+ was valid until December 2003 and subsequently utilities still acted according to its rules until the Energy Law of 2005 came into force. As of July 13, 2005, electricity network access is regulated according to the Energy Law of 2005, as described in “— EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy Law” above.

Electricity Network Charges As described in “EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy Law” above, the regulation of electricity network charges started in July 2005, with network charges calculated according to a cost-based rate-of-return model.

First approval of the network charges by the BNetzA was originally due by May 1, 2006. Due to the complex check of companies’ cost calculations, approval was delayed by several months and received by E.ON Energie’s network operators between July and October, 2006. In 2006, approved network charges averaged a 13.7 percent reduction from E.ON Energie’s filed network charges. The approved network charges were applied by the network operators immediately after receipt of the relevant approval. The BNetzA has announced that it will require network operators to refund to network customers the difference between operators’ actual network charges and their approved charges for the period between November 1, 2005 (the day after applications for network charges approval were due) and the relevant approval date in 2006. Several German utilities have challenged the BNetzA’s decisions in legal proceedings; a ruling of the competent court in a third party suit brought by Vattenfall Europe Transmission has denied the BNetzA’s decision to require refunds — this is valid as well for electricity as gas. A revision of the case is, however, still pending and E.ON will wait until the legality of the refunds is decided before refunding any network charges. Network charges validity was originally limited until December 31, 2007, triggering a second round of network charges calculation, which was based upon network operations’ costs in 2006. Approved costs will be the basis for the forthcoming system of incentive-based regulation. The expected approvals have been delayed with the transmission system operator E.ON Netz being the first network operator to receive approval on February 29, 2008. Approved costs have increased by 4,3 percent compared to the first round of cost regulation. However, this increase only partly reflects the considerable rise of cost components that cannot be influenced by E.ON Netz (such as network losses). The approval process with respect to the other network operators is expected to be completed for the whole group in the next several months.

169 Electricity Rate Regulation Still in the first half of 2007, obligatory prices (general tariffs) at which local and regional distributors sold electricity to standard-rate and smaller commercial customers were regulated by the economics ministries of most of the German states (as provided in the BTOElt). The rates were set at a level to assure an adequate return on investment on the basis of the costs and earnings of the electricity company. However, we believe that these governmentally-set ceiling rates are not consistent with liberalization and competitive markets. The average price charged by utilities for an average standard-rate customer in Germany with an assumed annual consumption of 3,500 kWh was, according to the German Association of the Energy and Water Industry (BDEW), 20.64 €cent per kWh in 2007 (all taxes included), while E.ON Energie charged an average of 20.37 €cent per kWh (weighted average). The average price quoted by the German Association for Energy Consumption (“VEA”) for industrial customers was 10. 76 €cent per kWh, while the average price per kWh charged by E.ON Energie was 11.07 €cent per kWh, as quoted by VEA as of July 1, 2007 (net of tax). Pursuant to the Energy Law of 2005, obligatory electricity rate regulation and therefore BTOElt were abandoned on July 1, 2007.

Germany: Gas Gas Network Access Until the Energy Law of 2005 took effect, E.ON Ruhrgas used the framework for third party gas network access contained in an agreement between E.ON Ruhrgas and the Competition Directorate-General of the European Commission with respect to a matter that had been pending before the Competition Directorate. The agreement contained, among other commitments by E.ON Ruhrgas with respect to its transmission business such as greater transparency and improved congestion management, an agreement to use an entry/exit system for gas network access. The agreed entry/exit system was introduced by E.ON Gastransport on November 1, 2004. For more information, see “— Pan-European Gas — Transmission and Storage.” As of July 13, 2005, gas network access is regulated according to the Energy Law of 2005, as described in “— EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy Law” above. Under the Energy Law of 2005, gas network operators have to offer entry and exit capacities for the transmission of gas separately to system users (entry/exit system). Network access has to be granted without fixing transport routes, which are dependent on the specific transaction. All network operators are obliged to cooperate, in order to ensure that system users need only one contract for entry capacities and one contract for exit capacities, including when gas transportation is carried out via several conducted networks. In order to comply with this requirement, E.ON Gastransport adjusted its entry/exit system with the introduction of the “ENTRIX 2” system on February 1, 2006.

In order to comply with this statutory obligation, the gas industry started to implement a network access model at the end of 2005 in consultation with the BNetzA. The BGW and the Association of the Municipalities (Verband der Kommunalen Unternehmen, or “VKU”) drafted an agreement regarding cooperation between operators of gas supply networks located in Germany which contains principles for the cooperation of the network operators and standard terms and conditions for access to networks. The agreement uses one network access model with different market areas. Within each market area, which each include a number of network subsections, shippers are entitled to choose the following variants for gas transportation: 1) transmission over different networks from an entry point to an exit point at the end consumer or 2) transmission from an entry point to an exit point within a network subsection (e.g. to exit via a “city gate”). E.ON Gastransport adjusted its entry/exit system in view of the cooperation agreement in October 2006, the date that the new network access model took effect.

Following the development of the gas industry cooperation agreement, a single gas trader (Nuon Deutschland GmbH) and a German energy association (Bundesverband Neuer Energieanbieter, or “BNE”) filed claims against three network operators (including E.ON Hanse) which challenged the use of the second variant for gas transportation. In November 2006, the BNetzA decided that, according to their assessment, this variant does not comply with the Energy Law of 2005, thus necessitating changes to the existing gas network operators’

170 cooperation agreement. The E.ON Group decided to accept this decision after a detailed analysis of the regulator’s decision and to implement the necessary changes into the existing cooperation agreement. BGW and VKU have prepared a revised draft of the cooperation agreement with the necessary changes, to reflect the decision of the BNetzA. During 2007, the cooperation agreement was accepted by the BNetzA and signed by the respective parties. This cooperation agreement forces transmission system operators nationwide to offer customers only one entry and one exit point in their market area (the “two-contract-model”), requiring subsequently changes in all transportation and also sales contracts. E.ON Gastransport had, by October 2007, implemented all changes necessary in order to comply with the BNetzA’s decision and the revised cooperation agreement.

Gas Network Charges As described in “EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy Law” above, the regulation of gas network charges started in July 2005, with network charges calculated according to a cost-based rate-of-return model. After a detailed examination of their application documents by the BNetzA, approval was granted to E.ON Energie’s distribution network operators between September and November 2006. In 2006, approved network charges of E.ON Energie’s regional distribution network operators were reduced by approximately ten percent on average, based on a different interpretation of the new law by the BNetzA. In addition, the filed network charges of Ferngas Nordbayern GmbH and Thüga in the Pan-European Gas market unit were reduced by 19.0 and 17.2 percent, respectively. As described above in the case of electricity network charges, the BNetzA has announced that the lower charges should be economically effective from the day after applications were due, in this case February 1, 2006. Currently approved network charges will be valid until March 31, 2008. For new network charges from April 1, 2008 all network operators — except E.ON Gastransport, as stated below — issued new network charges applications by the end of September, 2007, reflecting cost developments between 2004 and 2006. As in the case of electricity network charges, approved costs will be the base for the following incentive-based regulation system, starting in 2009. Results of the BNetzA examination of E.ON’s network operators’ applications, at this point in time, are hard to predict.

The Energy Law of 2005 provides an exemption from cost calculations for gas transmission networks if actual or potential pipeline competition can be proven. In January 2006, E.ON Gastransport gave notice to the BNetzA that it would calculate its network costs on a market-oriented basis (rather than submitting the charges for BNetzA approval). As the BNetzA has not yet determined whether actual or potential pipeline competition exists, E.ON Gastransport is not yet required to submit calculated gas network transmission charges to the BNetzA as described above.

Gas Rates Gas and heat rates are not regulated in Germany, but the GWB does apply. On this law, see “EU/Germany: General Aspects (Electricity and Gas) — Further German legislation.”

For information about proceedings regarding gas price calculations, e.g. against E.ON Hanse, see “Risk Factors.”

U.K. Liberalization of the electricity and gas industries in the United Kingdom largely pre-dated the requirements of the First and Second Electricity and Gas Directives described under “— EU/Germany: General Aspects (Electricity and Gas)” above, but the U.K. regulatory regime is basically consistent with the terms of such directives. E.ON UK is also subject to U.K. and EU legislation on competition.

The gas and electricity markets in England, Wales and Scotland are regulated by a single energy regulator, the Gas and Electricity Markets Authority (the “Authority”), established in November 2000. The Authority is assisted by Ofgem, which is governed by the Authority. The principal objective of the Authority is to protect the

171 interests of consumers of gas and electricity, wherever appropriate, by the promotion of effective competition in the electricity and gas industries. The Authority may grant licenses authorizing the generation, transmission, distribution or supply of electricity and the transportation, shipping or supply of gas. The Energy Act 2004 also gives the Authority power to license the operation of gas and electricity interconnectors. Any such license will incorporate by reference as appropriate the standard conditions determined for that type of license, which may be modified by the Authority. The license may also include other conditions that the Authority considers appropriate. License conditions may be modified in accordance with their terms or under the provisions of the Electricity Act 1989 (as amended) or the Gas Act 1986 (as amended), as appropriate. The Authority has power to impose financial penalties on licensees and/or issue enforcement orders for breach of license conditions and other relevant requirements.

The Authority also has within its designated areas of responsibility many of the powers of the Office of Fair Trading to apply and enforce the prohibitions in the Competition Act 1998 in relation to anti-competitive agreements or abuse of market dominance, including imposing financial penalties for breach. Since May 1, 2004, following reform of the EC competition law regime, the Authority also has the power to apply Articles 81 and 82 of the EC Treaty, which deal with control of anti-competitive agreements and abuse of market dominance. Within its designated areas, the Authority also exercises concurrently with the Office of Fair Trading certain functions under the Enterprise Act 2002 relating to the power to make market investigation references to the Competition Commission.

The U.K. government has introduced three bills to parliament in the 2007/8 parliamentary session which are intended to support delivery of the government’s energy and environmental policy objectives. The Climate Change Bill sets a target for the year 2050 for the reduction of greenhouse gas emissions, provides for a system of carbon budgeting for the U.K. economy, and establishes a Committee on Climate Change to advise the government. The Planning Bill introduces a new system for approving major infrastructure of national importance, such as larger power stations and electricity transmission lines, with the objective of streamlining decision-making and avoiding long public inquiries. The Energy Bill contains legislative provisions needed to implement policies set out in the 2007 Energy White Paper and the 2008 White Paper on Nuclear Power. These include provisions for a regulatory framework to enable investment in carbon capture and storage projects, for changes to the Renewables Obligation to allow support for different technologies, and for operators of new nuclear power stations to accumulate funds to meet the costs of decommissioning and their share of waste management costs. It is too early to predict if any of these proposals will be implemented, either in their current form or at all.

Electricity Unless covered by a license exemption, all electricity generators operating a power station in England, Wales or Scotland are required to have a generation license. The principal generation license within the E.ON U.K. business is held by E.ON UK. Although generation licenses do not contain direct price controls, they contain conditions which regulate various aspects of generators’ economic behavior.

The distribution licenses held by Central Networks East and Central Networks West (the two companies operating under the brand Central Networks) authorize the licensee to distribute electricity for the purpose of giving a supply to any premises in Great Britain. They provide for a distribution services area, equating to the former authorized area of the former public electricity suppliers in the East Midlands and West Midlands areas, respectively, in which the licensee has certain specific distribution services obligations. Under the Electricity Act 1989 (as amended), an electricity distributor has a duty, except in certain circumstances, to make a connection between its distribution system and any premises for the purpose of enabling electricity to be conveyed to or from the premises and to make a connection between its distribution system and any distribution system of another authorized distributor, for the purpose of enabling electricity to be conveyed to or from that other system.

The license obligations extend to not distorting the competitive market for the provision of those connections either through the distribution business’ own connection activities, through an affiliate or through an

172 unrelated third party. Over the last few years a number of U.K. distributors, including both Central Networks companies, have been investigated by Ofgem over concerns that they may have breached this aspect of their licenses or competition law in this regard. On December 11, 2007 Central Networks received notification from Ofgem that it believed both Central Networks East and West had breached their respective licenses and distorted competition in providing new connections. However, Ofgem accepted that this breach was not commercially driven and did not have an impact on the market. As a consequence, Ofgem decided that it was not appropriate to impose a penalty in this instance.

The distribution licenses place price controls on distribution. The current distribution price controls are in effect for a five-year period ending March 2010, and are expected to provide for overall stable prices for the distribution of electricity over that period. The price controls are intended to provide companies with sufficient revenues to allow them to finance their operating costs and capital investment. In addition to caps on revenue, the price controls also include targets for network losses and overall quality of network performance based upon the average number and duration of supply outages experienced by consumers. Companies can be either rewarded or penalized for exceeding or failing these targets.

The supply license held by E.ON Energy Limited (formerly Powergen Retail) authorizes the licensee to supply electricity to any premises in Great Britain. It provides for a supply services area, equating to the former authorized area of Powergen Energy plc, as the former public electricity supplier in the East Midlands, in which the licensee has certain specific supply services obligations. Ofgem relies on monitoring competition and, where necessary, using its powers under the Competition Act 1998 to tackle abuse. In addition, Ofgem is pursuing a range of measures under its Social Action Plan to help vulnerable and low-income customers. It is also continuing to work with the industry to improve the process for customers when they switch suppliers.

The U.K. government indicated in the Energy White Paper published in May 2007 that it would consider introducing legislation requiring suppliers to offer social programmes if there continued to be a wide disparity in the voluntary initiatives offered by suppliers. Ofgem’s assessment of suppliers’ programmes showed that E.ON UK’s programme was substantive, costing around 0.9GBP/account per year. The Energy Bill currently before parliament does not contain any legislation on social programmes.

A separate supply license is held by E.ON UK, which does not extend to supply to domestic premises. E.ON UK also continues to hold a second-tier supply license for Northern Ireland (to which the Utilities Act 2000 generally does not extend).

Following the acquisition of the U.K. retail energy business of the TXU Group (“TXU”) in October 2002, E.ON UK also holds a number of additional electricity and gas supply licenses through certain of the companies that were acquired as part of that deal. Customers supplied under these licenses have been migrated to the supply licenses held by E.ON Energy Limited and E.ON UK.

In June 2005, E.ON UK acquired the electricity supply company of Economy Power Limited (“Economy Power”). Migration of former Economy Power customers, which were supplied under a separate electricity supply license, to the supply licenses held by E.ON Energy Limited and E.ON UK was completed in June 2006.

Under Section 33BC of the Gas Act 1986, Section 41A of the Electricity Act 1989 and Section 103 of the Utilities Act 2000, electricity and gas suppliers are subject to a statutory obligation (known as the Energy Efficiency Commitment (EEC)) which requires them to achieve targets for installing energy efficiency measures in the household sector. The current obligation (known as the Electricity and Gas (Energy Efficiency Obligations) Order 2004) covers the period from April 1, 2005 to March 31, 2008. A range of energy efficiency measures qualify for the obligation, with E.ON UK expecting that about 60 percent of its expenditures will be on home insulation. E.ON UK met its targets a few months ahead of schedule and at a slightly lower cost than government’s forecast and expects that the cost to suppliers of this requirement will be about GBP0.9 /account per year. The obligation for the period from April 1, 2008 to March 31, 2011 involves targets which are roughly double those for the period ending March 31, 2008.

173 Gas Licenses to ship gas and to supply gas are held by a number of companies in the U.K. market unit.

E.ON UK operates gas pipelines that are subject to the Pipelines Act 1962 (as amended), including pipelines at Killingholme, Cottam, Connah’s Quay, Enfield and Winnington. This legislation gives third parties rights to apply to the Secretary of State for a direction requiring the pipeline owner to make spare capacity available to the third party.

Nordic The description under “— EU/Germany: General Aspects (Electricity and Gas)” above is applicable to E.ON Sverige AB and its two Finnish subsidiaries, and these companies are also subject to EU and national legislation on competition.

Electricity. The primary legislation applicable to the electricity industry in Sweden is the Swedish Electricity Act (Ellag (1997:857), or the “Electricity Act”) that came into force on January 1, 1998, and the statutes and provisions issued pursuant to the Electricity Act.

The Electricity Act promotes competition by creating opportunity for each customer to enter into an agreement with the supplier of the customer’s choice. In order to further ensure competition in sales of electricity, the Electricity Act also requires functional unbundling of the generation/sales and the transmission and distribution businesses, as well as legal unbundling of these businesses so that transmission and distribution operations are carried out by a separate legal entity. As a consequence, electricity customers in Sweden have separate contracts with a retail supplier and an electricity distributor. In Sweden, retail prices are not regulated.

Transmission and distribution of electricity are considered to be natural monopolies and are subject to regulation. The Energy Markets Inspectorate (“EMI”), formerly part of the Swedish Energy Agency and since January 1, 2008 an independent authority, grants licenses to erect power lines and carry on distribution operations. As the regulator for the Swedish electricity and gas markets, EMI has the authority to supervise the monopoly transmission and distribution businesses in order to protect the interests of customers. EMI also oversees third party access to the networks. It monitors network charges and other terms for the transmission and distribution of electricity and is responsible for setting certain standards with respect to transmission and distribution.

In Sweden, the high-voltage transmission grid is owned and operated by Svenska Kraftnät, the state-owned national grid company. The mid- and low-voltage distribution networks are owned and operated by a large number of both privately and publicly owned companies. A tariff, consisting of an annual capacity charge and an hourly transmission energy charge, applies for access to the national transmission as well as the regional and local distribution networks. Market participants pay for the right to feed in or take out electricity at just one point, which gives the participant access to the entire grid system and enables it to trade with any of the other market participants in the Nordic grid system. EMI also monitors quality of supply data for statistical reasons.

Changes in the Electricity Act regarding distribution regulation came into force in July 2002. The amendments provide that network charges have to be reasonable compared to the distribution companies’ performance. The concept of performance has initially been defined by EMI, which annually constructs a fictitious network for each utility in order to calculate the resources needed in the local network business. The resulting value of the network is then compared to the utility’s actual revenues in order to assess the reasonableness of the network charges. For this purpose EMI has created a regulation model called the “Network Performance Assessment Model” (“NPAM”). At present, EMI is only assessing the performance of the local networks but intends to include the regional networks in the near future.

The NPAM was used for the first time to evaluate network charges for 2003. Swedish electricity distribution companies reported the required information to EMI, which examined the operation of the companies. EMI

174 decided in December 2004 to prolong its inspection of a number of Swedish electricity distribution companies. Within E.ON Sverige, 14 distribution areas were initially subject to the additional inspection, with inspection satisfactorily concluded for 13 of these areas. For the remaining area, EMI initially decided that E.ON Sverige be required to reduce its network charges for 2003 by SEK 19.7 million, by repaying customers a portion of the network charges. E.ON Sverige has appealed the decision to the relevant administrative court. So far, EMI has admitted an increase of the weighted average cost of capital (WACC) from 4.8 percent to 6.7 percent and shortened depreciation-time for meters, which has reduced the obligation of repayment to SEK15.1 million. A judgment in the court case is expected in the middle of 2008 at the earliest. With respect to 2004 network charges, EMI decided in October 2005 to prolong its inspection of four distribution areas within E.ON Sverige. EMI has not issued a final decision regarding 2004 network charges. With respect to 2005 and 2006 network charges, EMI decided in December 2006 and December 2007, respectively, not to prolong its inspection of any distribution areas within E.ON Sverige, which means that the 2005 and 2006 network charges cannot be subject to any further actions by EMI.

In July 2005, several sections of the Electricity Act were amended in order to comply with the Second Electricity Directive. Among other changes, the amendments require more detailed regulation concerning the calculation of network charges; more information on the invoice and in advertising about the composition of energy sources used in producing the delivered electricity; that distribution companies procure the electricity required to cover their net losses in an open, non-discriminatory and market-oriented manner; and that distribution companies establish a supervision plan which states what kind of actions will be taken in order to prevent discriminatory behavior towards other operators in the market.

As a result of a severe storm that hit Sweden in January 2005, the Swedish government passed new legislation concerning electricity distribution in December 2005. Under the new law (SFS 2005: 1110), which was incorporated into the Electricity Act and which mainly came into force on January 1, 2006, a customer shall be compensated for power outages that last more than 12 hours, with the compensation payment being equal to at least 12.5 percent and up to 300 percent of the customer’s annual network charges, with compensation being based on the length of the outage. With effect from January 1, 2011, the new legislation also stipulates that the maximum allowable period of time for a power outage is 24 hours. If this time period is exceeded the provisions concerning compensation payment will still be applied and if this occurs frequently, the network operator will risk losing its license to operate the grid area.

In December 2007, a governmental commission (the Energy Network Commission) proposed a new regulation pursuant to which the supervisory authority would approve the network companies’ transmission and connection charges before they were allowed to take effect. According to the proposal, EMI would, prior to a new supervisory period and for each network company, determine the overall revenues that the network company would be allowed to gain from the network tariffs during the coming supervisory period (revenue frame). The revenue frame would be calculated so that it covers reasonable costs for running the network operations and gave a reasonable return on the capital needed in order to run the operations (capital base). The basic starting point in the calculation of network companies’ capital bases would be the companies’ existing electricity networks, for example in the form of cables, transformer stations, etc, and other assets that are used in network operations. The Commission proposes that the first supervisory period should begin on January 1, 2012.

Gas. In order to comply with the requirements of the Second Gas Directive, a new Swedish Natural Gas Act (Naturgaslag (2005:403) or the “Natural Gas Act”) was implemented on July 1, 2005. From this date, all non-household customers were able to choose their gas supplier. Household customers have also been eligible since July 1, 2007. In addition, the Natural Gas Act stipulates legal and functional unbundling of the transmission, distribution, storage and regasification (LNG) businesses from the supply business and requires separate accounting for the transmission, distribution, storage and regasification (LNG) businesses. The law also requires non-discriminatory third party access to the gas networks based on published charges for eligible customers. Further, distribution and transmission companies must also establish a supervision plan, which states what kind of actions will be taken in order to prevent discriminatory behavior towards other operators in the

175 market. As in the former Natural Gas Act, the new Natural Gas Act contains rules regarding the granting of licenses to build and use natural gas pipelines and natural gas storage, as well as new rules regarding the granting of licenses for LNG facilities.

The Natural Gas Act also requires EMI to pre-approve the criteria used by network operators to establish network charges valid from 2006. EMI approved the model (the criteria for network charges) used by E.ON Sverige in November 2005. In addition, the Natural Gas Act requires that the revenues from network charges be reasonable compared to costs for capital and operations, and stipulates that the reasonableness of network charges remains subject to inspection by EMI ex-post. If EMI finds that revenues from network charges are not reasonable, it can obligate the operator to reduce network charges. A first test inspection was launched in the spring of 2007 regarding revenues for the second half of 2005. This inspection was finished in December 2007 without any judgment being issued. According to EMI, the inspection was closed because of the difficulties in getting correct basic data for the second half of 2005 since there was no obligation to have separate accounts for the first half of 2005. The first full-year inspection will take place in 2008 regarding revenues for 2006.

Security of Energy Supply (Gas). The Gas Supply Directive has been implemented in the Swedish Natural Gas Act. The amendments entered into force July 1, 2006 and impose a general obligation on the operators in the natural gas market to plan and take necessary measures to ensure the supply of natural gas. The Natural Gas Act does not contain any detailed regulation on how the operators shall perform their obligation. Instead, the Swedish government has authorized the Swedish Independent System Operator (Affärsverket svenska kraftnät) to determine in more detail which measures shall be taken in this respect. At this time it is unclear which obligations can be imposed on the operators in Sweden.

Renewable Energy and Electricity Certificates. The Swedish energy policy is based on the assumption that Sweden will obtain all its energy from renewable energy sources in the long term. The most important policy instrument in promoting renewable electricity production is the electricity certificate system. The Swedish electricity certificate system has been in operation since May 2003. The objective of the system, which is based on the Swedish Act on Electricity Certificates (SFS 2003:113), was initially to increase the volume of electricity produced from renewable energy sources by 10 TWh by 2010 as compared with the 2002 level.

During 2004 EMI gave the Ministry of Sustainable Development recommendations on the electricity certificate system based on an analysis of the system. EMI recommended that the electricity certificate system be made permanent and that long-term quota levels be set if necessary investments in renewable energy are to take place. Due in part to this analysis, the Swedish government delivered proposals on an amendment of the Act on Electricity Certificates to the Swedish Parliament. The proposed amendment contained suggestions that the Swedish electricity certificate system should be extended until 2030 and that the objective of the system be revised to increase the volume of electricity produced from renewable energy sources by 17 TWh by 2016 as compared with the 2002 level. The proposals were adopted by the Swedish parliament in June 2006 and the amendments entered into force on January 1, 2007. For more information about the current system, see “— Nordic — Market Environment.” In February 2008, a governmental commission (the Grid Connection Inquiry) proposed a new regulations to promote the development of renewable electricity production. In the current system, plants with a capacity of 1.5 MW or lower are granted a reduction in network tariffs. The proposed new regulation would replace this rule with a cap on the total network charges for renewable energy production at SEK 0.03 per kWh. The inquiry also proposed the establishment of a grid investment fund to partly finance necessary and costly network investments for connecting renewable energy production that fulfil the criteria for being allocated electricity certificates to the network. The fund will be financed by end-customers through the network companies in accordance with customers’ underlying electricity consumption (per kWh).

176 U.S. Midwest Retail Electric Rate Regulation The KPSC has regulatory jurisdiction over the rates and service of LG&E and KU and over the issuance of certain of their securities. The Virginia State Corporation Commission also has parallel regulatory jurisdiction with respect to certain of KU’s operations. The KPSC, in the case of LG&E and KU, and the Virginia State Corporation Commission, in the case of KU, regulate the retail rates and services of LG&E or KU and, via periodic public rate cases and other proceedings, establish tariffs governing the rates LG&E and KU may charge customers. Because KU owns and operates a small amount of electric utility property in Tennessee and serves five customers there, KU is also subject to the jurisdiction of the Tennessee Regulatory Authority.

LG&E and KU are each a “public utility” as defined in the Federal Power Act. Each is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in the Federal Power Act, including the wholesale sale of electric energy in interstate commerce. In addition, the FERC and certain states share jurisdiction over the issuance by public utilities of short-term securities.

In June 2004, the KPSC issued an order approving increases in the base electric and gas rates of LG&E and the base electric rates of KU. In the KPSC’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million or 7.7 percent and in annual base gas rates of approximately $11.9 million or 3.4 percent. KU was granted an increase in annual base electric rates of approximately $46.1 million or 6.8 percent. The rate increases took effect in July 2004. In March 2006, the KPSC issued a final order in the rate case proceedings which resolved a final calculational issue in LG&E’s and KU’s favor consistent with the original July 2004 rate increase order. For information about 2007 developments regarding re-regulation involving a hybrid model of rate regulation, see “— U.S. Midwest — Market Environment.”

The electric rates of LG&E and KU in Kentucky contain fuel adjustment clauses whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all retail electric customers. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer the then-current fuel adjustment charge or credit to the base charges. At present, the KPSC also requires that electric utilities, including LG&E and KU, publicly file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.

In 1992, the Kentucky General Assembly enacted a statute which provides an alternative procedure to increasing base rates by allowing utilities to recover the costs of environmental compliance by means of a surcharge rather than by opening a general rate case. Pursuant to this statute, LG&E’s and KU’s electric rates in Kentucky contain an environmental cost recovery surcharge which recovers costs incurred by LG&E or KU that are required to comply with the U.S. Clean Air Act Amendments of 1990 and other environmental regulations which apply to coal combustion wastes and by-products from facilities utilized for the production of energy from coal. The magnitude of the surcharge fluctuates with the level of approved environmental compliance costs incurred during each period. At six-month intervals, the KPSC reviews the operation of each utility’s environmental surcharge, and, after review, may disallow any surcharge amounts found not to be just and reasonable. In addition, every two years the KPSC reviews and evaluates the past operation of the surcharge, and, after review, may disallow improper expenses and, to the extent appropriate, incorporate surcharge amounts found to be just and reasonable into the utility’s existing base rates.

Retail Gas Rate Regulation LG&E’s gas rates in Kentucky contain a gas supply charge, whereby increases or decreases in the cost of gas supply are reflected in LG&E’s rates, subject to approval of the KPSC. The gas supply charge procedure prescribed by order of the KPSC provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the gas supply charge contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor.

177 Transmission Developments In September 2006, LG&E and KU withdrew from the MISO transmission organization. In LG&E’s and KU’s view, the costs of MISO membership outweighed the benefits, particularly in light of the financial impact of MISO’s implementation of new day-ahead and real-time energy markets in April 2005. In October 2006, LG&E and KU paid MISO $33 million in satisfaction of a contractual aggregate exit fee. Pursuant to agreement, LG&E, KU and MISO have filed an application with the FERC to approve adjustments to certain components of this calculated amount, including a potential aggregate refund to LG&E and KU of $6.4 million over eight years. LG&E and KU estimate that the exit fee will be more than offset by savings resulting from withdrawal from MISO. Orders of the KPSC approving the exit from MISO have authorized the establishment of a regulatory asset for the exit fee, subject to adjustment for possible future MISO credits, and a regulatory liability for certain revenues associated with former MISO charges. Historically, LG&E and KU have received approval to recover regulatory assets and liabilities in future rate proceedings, although this cannot be assured. Pursuant to FERC requirements, LG&E and KU have contracted with independent third parties to manage applicable operational aspects of their transmission systems following the MISO exit, including functions relating to reliability coordinator and independent transmission system operator roles. The SPP now functions as the transmission system operator and the TVA now functions as the transmission reliability coordinator, respectively, for LG&E and KU.

LG&E, KU and other E.ON U.S. subsidiaries sell excess power pursuant to FERC-granted cost-based and market-based rate authorities. In connection with recent FERC market-based rate and market power regulatory developments, the E.ON U.S. entities operate under approved tariffs whereby they may make applicable wholesale power sales within their own control areas (and one adjacent control area) subject to a price cap set at a cost-based price. The tariffs further allow for sales at market-based rates at the boundary of such control areas, subject to certain restrictions. Industry-wide FERC proceedings continue with respect to market-based rate matters, and E.ON U.S.’s market-based rate authority is subject to such future developments.

The charges relating to transmission and wholesale power market structures and prices following LG&E’s and KU’s exit from MISO are not completely estimable and may have variable effects on energy and transmission purchases and sales and on related costs and revenues. Additional changes may have an effect on LG&E’s and KU’s ability to access the transmission system for wholesale or native load power activities. LG&E and KU believe that, over time, the benefits and savings from their exit of MISO will outweigh the costs and expenses.

A number of regional or industry-wide general FERC proceedings regarding transmission market structure changes are in varying stages of development. In the ordinary course of business, LG&E and KU, either directly or via industry groups, participate in many of these proceedings.

Energy Policy Act of 2005 and Repeal of PUHCA The Energy Policy Act of 2005 (“EPAct 2005”) was enacted in August 2005. Among other matters, the comprehensive legislation contains provisions mandating improved electric reliability standards and performance; providing certain economic and other incentives relating to transmission, pollution control and renewable generation assets; increasing funding for clean coal generation incentives; repealing PUHCA; and establishing a new Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 reduces or eliminates many prior federal regulatory constraints applicable to public utility holding companies in such areas as mergers and acquisitions, non-energy-related investments, financial and capital structures, utility system integration, affiliate services, and reporting and record-keeping requirements. LG&E and KU currently believe they have the necessary FERC authorizations and approvals to conduct their operations under the EPAct 2005 and PUHCA 2005 as presently conducted, including financing approvals, and, to the extent required, will apply for additional authorizations as applicable.

178 Other Regulations Integrated resource planning regulations in Kentucky require LG&E, KU and other major utilities to make triennial filings with the KPSC of historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques. The two utilities filed such integrated resource plans in April 2005 and the Kentucky Attorney General and representatives of an industrial customer group were granted intervenor status. In February 2006, the KPSC issued a staff report noting no substantive issues and closed the integrated resource planning proceedings. The company will make its next filing in April 2008.

Pursuant to Kentucky law, the KPSC has established the service boundaries for LG&E, KU and other utility companies, other than municipal corporations, within which each such supplier has the exclusive right to render retail electric service.

179 DIRECTORS AND SENIOR MANAGEMENT

General In accordance with the German Stock Corporation Act, E.ON has a Supervisory Board and a Board of Management. The two Boards are separate and no individual may simultaneously be a member of both Boards.

The Board of Management is responsible for managing the day-to-day business of E.ON in accordance with the Stock Corporation Act and E.ON’s Articles of Association. The Board of Management is authorized to represent E.ON and to enter into binding agreements with third parties on behalf of it.

The principal function of the Supervisory Board is to supervise the Board of Management. It is also responsible for appointing and removing the members of the Board of Management. The Supervisory Board may not make management decisions, but may determine that certain types of transactions require its prior consent.

In carrying out their duties, the individual Board members must exercise the standard of care of a diligent and prudent businessperson. In complying with such standard of care, the Boards must take into account a broad range of considerations including the interests of E.ON and its shareholders, employees and creditors. In addition, the members of the Board of Management are personally liable for certain violations of the Stock Corporation Act by the Company.

Corporate Governance German stock corporations are governed by three separate bodies: the annual general meeting of shareholders, the supervisory board and the board of management. Their roles are defined by German law and by the corporation’s articles of association, and may be described generally as follows: • The annual general meeting of shareholders ratifies the actions of the corporation’s supervisory board and board of management. It decides, among other things, on the amount of the annual dividend, the appointment of an independent auditor and certain significant corporate transactions. In corporations with more than 2,000 employees, shareholders and employees elect or appoint an equal number of representatives to the supervisory board. The annual general meeting must be held within the first eight months of each fiscal year. • The supervisory board appoints and removes the members of the board of management and oversees the management of the corporation. Although prior approval of the supervisory board may be required in connection with certain significant matters, the law prohibits the supervisory board from making management decisions. • The board of management manages the corporation’s business and represents it in dealings with third parties. The board of management submits regular reports to the supervisory board about the corporation’s operations and business strategies, and prepares special reports upon request. A person may not serve on the board of management and the supervisory board of a corporation at the same time.

Cooperation between the Board of Management and the Supervisory Board. The E.ON Board of Management manages the business of the Company, with all its members bearing joint responsibility for its decisions, in accordance with German law. The Board of Management establishes the Company’s objectives, sets its fundamental strategic direction, and is responsible for corporate policy and group organization.

The Board of Management regularly reports to the Supervisory Board on a timely and comprehensive basis on all issues of corporate planning, business development, risk assessment and risk management.

Conflicts of Interest. In order to ensure that the Supervisory Board’s advice and oversight functions are conducted on an independent basis, no more than two former members of the Board of Management may be

180 members of the Supervisory Board. The Supervisory Board is required to report any conflicts of interest to the annual shareholders’ meeting and to describe how the conflicts have been handled. Any material conflict of interest of a non-temporary nature will result in the termination of the member’s appointment to the Supervisory Board.

Members of the Board of Management are also required to promptly report conflicts of interest to the Executive Committee of the Supervisory Board and to the full Board of Management.

The Supervisory Board Committees. The Supervisory Board has 20 members and, in accordance with the German Co-determination Act (Mitbestimmungsgesetz), is composed of an equal number of shareholder and employee representatives. It supervises the management of the Company and advises the Board of Management. The Supervisory Board has formed committees from among its members.

The Executive Committee consists of four members. It prepares meetings of the Supervisory Board and advises the Board of Management on matters of general policy relating to the strategic development of the Company. In urgent cases (i.e., if waiting for the prior approval of the Supervisory Board would materially prejudice the Company), the Executive Committee decides on business transactions requiring prior approval by the Supervisory Board. The Executive Committee also performs the functions of a remuneration committee.

The Audit Committee consists of four members who have special knowledge in the field of accounting or business administration. The Audit Committee deals in particular with issues relating to the Company’s accounting policies and risk management, issues regarding the independence of the Company’s external auditors, the establishment of auditing priorities and agreements on auditors’ fees, including E.ON’s policy for the approval of all audit and permissible non-audit services performed by the Company’s independent auditors. The Audit Committee also prepares the Supervisory Board’s decision on the approval of the annual financial statements of E.ON AG and the acceptance of the annual consolidated financial statements.

The Finance and Investment Committee consists of four members. It advises the Board of Management on all issues of Group financing and investment planning. It decides on behalf of the Supervisory Board on the approval of the acquisition and disposition of companies, company participations and parts of companies, as well as on finance activities whose value exceeds 1 percent of the Group’s equity, as listed in the latest consolidated balance sheet. If the value of any such transactions or activities exceeds 2.5 percent of this equity, the Finance and Investment Committee will prepare the Supervisory Board’s decision on such matters.

E.ON has instituted the following measures to improve the transparency of its corporate governance and financial reporting: • In addition to E.ON’s general Code of Conduct for all employees, the Company has developed a special Code of Ethics for members of the Board of Management and senior financial officers and published the text on its corporate website at www.eon.com. Material appearing on the website is not incorporated by reference in this document. This code obliges these managers to make full, appropriate, accurate, timely and understandable disclosure of information both in the documents E.ON submits to the regulatory authorities and in its other corporate publications.

Supervisory Board (Aufsichtsrat) The present Supervisory Board of E.ON consists of twenty members, ten of whom were elected by the shareholders by a simple majority of the votes cast at a shareholder meeting in accordance with the provisions of the Stock Corporation Act, and ten of whom were elected by the employees in accordance with the German Co-determination Act (Mitbestimmungsgesetz).

A member of the Supervisory Board elected by the shareholders may be removed by the shareholders by a majority of the votes cast at a meeting of shareholders. A member of the Supervisory Board elected by the

181 employees may be removed by three-quarters of the votes cast by the relevant class of employees. The Supervisory Board appoints a Chairman and a Deputy Chairman of the Supervisory Board from amongst its members. At least half the total required number of members of the Supervisory Board must be present or participate in the decision making to constitute a quorum. Unless otherwise provided for by law, resolutions are passed by a simple majority of the votes cast. In the event of a tie, another vote is held and the Chairman (who is, in practice, a representative of the shareholders because the representatives of the shareholders have the right to elect the Chairman if two-thirds of the total required number of members of the Supervisory Board fail to agree on a candidate) then casts the tie-breaking vote.

The members of the Supervisory Board are each elected for the same fixed term of approximately five years. The term expires at the end of the annual general shareholders’ meeting after the fourth fiscal year following the year in which the Supervisory Board was elected. Reelection is possible. The remuneration of the members of the Supervisory Board is determined by E.ON’s Articles of Association.

182 Because all members of the Supervisory Board are elected at the same time, their terms expire simultaneously. The term of a substitute member of the Supervisory Board elected or appointed by a court to fill a vacancy ends at the time when the term of the original member would have ended. The incumbent members of E.ON’s Supervisory Board, their respective ages and their principal occupation and experience, each as of December 31, 2007, as well as the year in which they were first elected or appointed to the Supervisory Board are as follows:

Year First Name and Position Held Age Principal Occupation Elected Ulrich Hartmann(1)(2)*(3)*(4) ...... 69 Retired Co-Chief Executive Officer of 2003 Chairman of the Supervisory Board E.ON AG; formerly Chairman of the Board of Management and Chief Executive Officer of VEBA AG Supervisory Board Memberships/ Directorships: Deutsche Bank AG, Deutsche Lufthansa AG, IKB Deutsche Industriebank AG (Chairman), Münchener Rückversicherungs-Gesellschaft AG, Henkel KGaA Hubertus Schmoldt(2)(3)(6) ...... 62 Chairman of the Board of Management of 1996 Deputy Chairman of the Supervisory Board Industriegewerkschaft Bergbau, Chemie, Energie Supervisory Board Memberships/ Directorships: Bayer AG, DOW Olefinverbund GmbH, Deutsche BP AG, RAG Aktiengesellschaft, Evonik Industries AG Dr. Karl-Hermann Baumann(1)* ...... 72 Formerly Chairman of the Supervisory Board 2000 Member of the Supervisory Board of Siemens AG; formerly member of the Board of Management of Siemens AG Supervisory Board Memberships/ Directorships: Linde AG, Bayer Schering Pharma AG Sven Bergelin(6)(7) ...... 44 Director, National Energy Working Group, 2007 Member of the Supervisory Board Unified Services Sector Union (ver.di) Supervisory Board Memberships/ Directorships: E.ON Avacon AG, E.ON Kernkraft GmbH Dr. Rolf-E. Breuer ...... 70 Formerly Chairman of the Supervisory Board 1997 Member of the Supervisory Board of Deutsche Bank AG; formerly Spokesman of the Board of Management of Deutsche Bank AG Supervisory Board Memberships/ Directorships: Landwirtschaftliche Rentenbank(5)

183 Year First Name and Position Held Age Principal Occupation Elected Gabriele Gratz(1)(6) ...... 59 Chairwoman of the Works Council of 2005 Member of the Supervisory Board E.ON Ruhrgas AG Supervisory Board Memberships/ Directorships: E.ON Ruhrgas AG Wolf-Rüdiger Hinrichsen(2)(3)(6) ...... 52 Vice-Chairman of the Group Workers’ 1998 Member of the Supervisory Board Council of E.ON AG Ulrich Hocker ...... 57 General Manager of the German Investor 1998 Member of the Supervisory Board Protection Association Supervisory Board Memberships/ Directorships: Feri Finance AG, Arcandor AG, ThyssenKrupp Stainless AG, Deutsche Telekom AG, Gartmore SICAV(5), Phoenix Mecano AG(5) (Chairman) Eva Kirchhof(6) ...... 50 Diploma-Physicist, E.ON Sales and Trading 2002 Member of the Supervisory Board GmbH Prof. Dr. Ulrich Lehner(3)(4) ...... 61 President and Chief Executive Officer, 2003 Member of the Supervisory Board Henkel KGaA Supervisory Board Memberships/ Directorships: Dr. Ing. h.c.F. Porsche AG, Porsche Automobil Holding SE, HSBC Trinkaus & Burkhardt AG, Novartis AG Dr. Klaus Liesen ...... 76 Honorary Chairman of the Supervisory 1991 Member of the Supervisory Board Board of E.ON Ruhrgas AG and of Volkswagen AG; formerly Chairman of the Supervisory Board of E.ON Ruhrgas AG Erhard Ott(6) ...... 54 Member of the Board of Management, 2005 Member of the Supervisory Board Unified Services Sector Union (ver.di) Supervisory Board Memberships/ Directorships: E.ON Energie AG Hans Prüfer(6) ...... 58 Chairman of the Group Works Council, 2006 Member of the Supervisory Board E.ON AG Klaus Dieter Raschke(1)(6) ...... 54 Chairman of the Combined Works Council, 2002 Member of the Supervisory Board E.ON Energie AG Supervisory Board Memberships/ Directorships: E.ON Energie AG, E.ON Kernkraft GmbH

184 Year First Name and Position Held Age Principal Occupation Elected Dr. Henning Schulte-Noelle(2)(4) ...... 65 Chairman of the Supervisory Board of 1993 Member of the Supervisory Board Allianz SE; formerly Chairman of the Board of Management of Allianz SE Supervisory Board Memberships/ Directorships: Siemens AG, ThyssenKrupp AG Dr. Theo Siegert(7) ...... 60 Managing Director de Haen-Carstanjen & 2007 Member of the Supervisory Board Söhne Supervisory Board Memberships/ Directorships: Deutsche Bank AG, ERGO AG, Merck KGaA, E. Merck OHG, DKSH Holding Ltd., Hülsken Holding GmbH & Co. KG Prof. Dr. Wilhelm Simson ...... 69 Retired Co-Chief Executive Officer of E.ON 2003 Member of the Supervisory Board AG; formerly Chairman of the Board of Management and Chief Executive Officer of VIAG AG Supervisory Board Memberships/ Directorships: Frankfurter Allgemeine Zeitung GmbH, Merck KGaA (Chairman), Freudenberg KG (5), Jungbunzlauer Holding AG(5), E. Merck OHG(5), Hochtief AG Gerhard Skupke(6) ...... 58 Chairman of the Central Works Council, 2003 Member of the Supervisory Board E.ON edis AG Supervisory Board Memberships/ Directorships: E.ON edis AG Dr. Georg Freiherr von Waldenfels ...... 63 Former Minister of Finance of the State of 2003 Member of the Supervisory Board Bavaria; Attorney Supervisory Board Memberships/ Directorships: CAPEO Consulting AG, Georgsmarienhütte Holding GmbH, Rothenbaum Sport GmbH Hans Wollitzer(6)(7) ...... 59 Chairman of the Central Works Council, 2007 Member of the Supervisory Board E.ON Energie AG Supervisory Board Memberships/ Directorships: E.ON Energie AG, E.ON Bayern AG * Chairman of the respective Supervisory Board committee. (1) Member of E.ON AG’s Audit Committee. (2) Member of E.ON AG’s Executive Committee, which covers the functions of a remuneration committee. (3) Member of E.ON AG’s Finance and Investment Committee. (4) Member of E.ON AG’s Nomination Committee.

185 (5) Membership in comparable domestic or foreign supervisory body of a commercial enterprise. (6) Elected by the employees. (7) Seppel Kraus was a member of E.ON AG’s Supervisory Board until July 31, 2007. He was elected by the employees. On August 1, 2007, Sven Bergelin, Chairman of the Central Works Council of E.ON Energie AG, was publicly appointed as his successor. Dr. Gerhard Cromme was a member of E.ON AG’s Supervisory Board until June 30, 2007. He was elected by the shareholders. On July 4, 2007, Dr. Theo Siegert was publicly appointed as his successor. Ulrich Otte was a member of E.ON AG’s Supervisory Board until December 31, 2006. He was elected by the employees and a member of E.ON AG’s Audit Committee. On January 4, 2007, Hans Wollitzer, Chairman of the Central Works Council of E.ON Energie AG, was publicly appointed as his successor. On March 6, 2007, Gabriele Gratz was elected as a new member of E.ON AG’s Audit Committee, replacing Ulrich Otte. On July 1, 2007, Prof. Dr. Ulrich Lehner was elected as a new member of E.ON AG’s Finance and Investment Committee, replacing Dr. Gerhard Cromme, and also joined E.ON AG’s Nomination Committee.

The current members of the Supervisory Board are subject to reelection in 2008.

Board Of Management (Vorstand) As of December 31, 2007, the Board of Management of E.ON consisted of six members (the total number is determined by the Supervisory Board) who are appointed by the Supervisory Board in accordance with the Stock Corporation Act.

Pursuant to E.ON’s Articles of Association, any two members of the Board of Management, or one member of the Board of Management and the holder of a special power of attorney (Prokura), may bind E.ON. According to E.ON’s Articles of Association, Prokura is granted by the Board of Management.

The Board of Management must report regularly to the Supervisory Board, in particular on proposed business policy and strategy, on profitability, on the current business of E.ON and on business transactions that may affect the profitability or liquidity of E.ON, as well as on any exceptional matters which may arise from time to time. The Supervisory Board is also entitled to request special reports at any time.

The members of the Board of Management are appointed by the Supervisory Board for a maximum term of five years. They may be re-appointed or have their term extended for additional five-year terms, subject to certain limitations depending upon the age of the member. Under certain circumstances, such as a serious breach of duty or a bona fide vote of no confidence by the shareholders at a shareholders’ meeting, a member of the Board of Management may be removed by the Supervisory Board prior to the expiration of such term.

In 2006, E.ON introduced a new Board structure to prepare for an even stronger market focus and for the Group’s future growth. In October 2006, the Supervisory Board of E.ON AG decided that the future Board of Management will include not only the Chief Executive Officer (CEO), the Chief Financial Officer (CFO) and the Chief Human Resources Officer but also a Chief Operating Officer (COO) and a Board member in charge of Corporate Development/New Markets. The new Board of Management structure was effective as of April 1, 2007.

186 The members of the Board of Management, their respective ages and their positions and experience, each as of December 31, 2007, as well as the year in which they were first appointed to the Board and the years in which their terms expire, respectively, are as follows:

Year First Year Current Name and Title Age Business Activities and Experience Appointed Term Expires Dr. Wulf H. Bernotat ...... 59 Chief Executive Officer; Corporate 2003 2010 Chairman of the Board of Management Communications, Corporate and Public Affairs, Investor Relations, Supervisory Board Relations, Strategy, Executive Development, Audit; formerly Chairman of the Board of Management of Stinnes AG Supervisory Board Memberships/ Directorships: E.ON Energie AG(1) (Chairman), E.ON Ruhrgas AG(1) (Chairman), Allianz SE, Metro AG, Bertelsmann AG, E.ON Nordic AB(2)(3) (Chairman), E.ON UK plc(2)(3) (Chairman), E.ON US Investments Corp.(2)(3) (Chairman), E.ON Sverige AB(2)(3) (Chairman) Dr. Burckhard Bergmann(4) ...... 64 Upstream Business, Market 2003 2008 Member of the Board of Management Management, Group Regulatory Management; Chairman of the Board of Management and Chief Executive Officer of E.ON Ruhrgas AG Supervisory Board Memberships/ Directorships: Thüga AG(1) (Chairman), Allianz Lebensversicherungs-AG, MAN Ferrostaal AG, Jaeger Beteiligungsgesellschaft mbH & Co. KG (2) (Chairman), Accumulatorenwerke Hoppecke Carl Zoellner & Sohn GmbH(2), OAO Gazprom(2), E.ON Ruhrgas E & P GmbH(2)(3) (Chairman), North Stream AG(2), E.ON Gastransport AG & Co. KG(2)(3) (Chairman), E.ON UK plc(2)(3), ZAO Gerosgaz(2)(3) (Chairman; in alternation with a representative of the foreign partner)

187 Year First Year Current Name and Title Age Business Activities and Experience Appointed Term Expires Christoph Dänzer-Vanotti ...... 52 Chief Human Resources Officer; 2006 2009 Member of the Board of Management Labor Relations, Personnel, Infrastructure and Services, Procurement, Organization; formerly Member of the Board of Management of E.ON Ruhrgas AG Supervisory Board Memberships/ Directorships: E.ON Nordic AB(2)(3), E.ON Sverige AB(2)(3) Lutz Feldmann ...... 50 Corporate Development/New 2006 2009 Member of the Board of Management Markets, M&A, Legal Affairs; formerly Group Vice President Marketing of BP p.l.c. Supervisory Board Memberships/ Directorships: E.ON Energie AG(1) Dr. Marcus Schenck ...... 41 Chief Financial Officer; Finance, 2006 2009 Member of the Board of Management Accounting, Taxes, IT; formerly Managing Director and Partner of Goldman, Sachs & Co. oHG Supervisory Board Memberships/ Directorships: E.ON Ruhrgas AG(1), E.ON IS GmbH(3), NFK Finanzcontor GmbH(3), E.ON Risk Consulting GmbH(3), E.ON Audit Services GmbH(3) Dr. Johannes Teyssen(5) ...... 47 Chief Operating Officer, Downstream 2004 2008 Member of the Board of Management Business, Market Management, Generation, Marketing, Group Regulatory Management Supervisory Board Memberships/ Directorships: E.ON Energie AG(1), E.ON Ruhrgas AG(1), Salzgitter AG, E.ON Nordic AB(2)(3), E.ON Sverige AB(2)(3), E.ON UK plc.(2)(3) (1) Group mandate. (2) Membership in comparable domestic or foreign supervisory body of a commercial enterprise. (3) Other Group mandate (membership in comparable domestic or foreign supervisory body of a commercial enterprise). (4) On February 29, 2008, Dr. Burckhard Bergmann retired from the Board. (5) Dr. Johannes Teyssen became Chief Operating Officer as of April 1, 2007. On April 1, 2007, Dr. Hans Michael Gaul retired from the Board of Management. The members of the Supervisory Board and Board of Management hold, in aggregate, less than 1 percent of E.ON’s outstanding Ordinary Shares.

188 DESCRIPTION OF THE NOTES

The $2,000,000,000 5.80% senior notes due 2018 (the “2018 Notes”) and the $1,000,000,000 6.65% senior notes due 2038 (the “2038 Notes” and, together with the 2018 Notes, the “Notes”) will be issued under a fiscal and paying agency agreement (“the Fiscal and Paying Agency Agreement”) to be dated as of April 22, 2008 between E.ON International Finance B.V. (the “Issuer”), E.ON AG (the “Guarantor”) and HSBC Bank USA, N.A. as fiscal agent, principal paying agent, transfer agent and registrar (the “Fiscal Agent”). The following summaries of certain provisions of the Notes and the Fiscal and Paying Agency Agreement do not purport to be complete and are subject to, and are qualified in their entirety by reference to, all the provisions of the Notes and the Fiscal and Paying Agency Agreement, including the definitions of certain terms contained therein.

General The 2018 Notes will be initially limited to $2,000,000,000 aggregate principal amount and will mature on April 30, 2018. The 2038 Notes will be initially limited to $1,000,000,000 aggregate principal amount and will mature on April 30, 2038. The Notes will be the direct, unconditional, unsecured and unsubordinated general obligations of the Issuer. The Notes will rank pari passu among themselves, without any preference of one over the other by reason of priority of date of issue or otherwise, and at least equally with all other unsecured and unsubordinated general obligations of the Issuer from time to time outstanding. The Notes will bear interest at the rate per annum shown on the front cover of this offering memorandum from April 22, 2008, payable semiannually in arrears on October 30 and April 30 of each year, commencing on October 30, 2008, to the Holders of record on the October 15 and April 15, as the case may be, immediately preceding such interest payment date, whether or not such day is a Business Day. Interest will be calculated on the basis of a 360-day year consisting of twelve 30-day months. The Notes will be repaid at maturity at a price of 100% of the principal amount thereof. The Notes may be redeemed at any time prior to maturity in the circumstances described under “— Optional Redemption” and “— Optional Tax Redemption.” The Notes will be issued in denominations of $1,000 and integral multiples of $1,000 in excess thereof. The Notes do not provide for any sinking fund.

The term “Business Day” means any day other than a day on which commercial banks or foreign exchange markets are permitted or required to be closed in New York City, London, Frankfurt am Main or Amsterdam. If the date of maturity of interest on or principal of the Notes or the date fixed for redemption of any Note is not a Business Day, then payment of interest or principal need not be made on such date, but may be made on the next succeeding Business Day with the same force and effect as if made on the date of maturity or the date fixed for redemption, and no interest shall accrue for the period after such date.

Guarantees Each Note will benefit from an unconditional and irrevocable guarantee (each a “Guarantee” and, collectively, the “Guarantees”) by the Guarantor. Under the Guarantees, the Guarantor will guarantee to each Holder the due and punctual payment of any principal, accrued and unpaid interest (and all Additional Amounts, if any) due under the Notes in accordance with the Fiscal and Paying Agency Agreement, and any Additional Amounts in respect of such Guarantees. The Guarantees will be the direct, unconditional, unsecured and unsubordinated general obligations of the Guarantor. The Guarantees will rank pari passu among themselves, without any preference of one over the other by reason of priority of date of issue or otherwise, and at least equally with all other unsecured and unsubordinated general obligations of the Guarantor from time to time outstanding.

Additional Notes The Notes will be issued in the initial aggregate principal amount set forth above. The Issuer may, from time to time, without notice to or the consent of the Holders, create and issue, pursuant to the Fiscal and Paying Agency Agreement and in accordance with applicable laws and regulations, additional notes (the “Additional Notes”) maturing on the same maturity date as the other Notes of that series (the 2018 Notes or the 2038

189 Notes) and having the same terms and conditions under the Fiscal and Paying Agency Agreement (including with respect to the Guarantor and the Guarantees) as the previously outstanding Notes of that series in all respects (or in all respects except for the issue date and the amount and the date of the first payment of interest thereon) so that such Additional Notes shall be consolidated and form a single series with the previously outstanding Notes of that series. Additional Notes, if any, will be issued under a separate offering memorandum or a supplement to this offering memorandum.

Optional Redemption The Issuer may, at its option, redeem the Notes as a whole or in part at any time upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to the greater of: • 100% of the aggregate principal amount of the Notes to be redeemed; and • as determined by the Independent Investment Banker, the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 35 basis points;

plus, in each case described above, accrued and unpaid interest on the principal amount being redeemed to (but excluding) such redemption date.

“Treasury Rate” means, with respect to any redemption date: • the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. treasury securities adjusted to constant maturity under the caption “Treasury constant maturities — Nominal”, for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the remaining term of the Notes, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue will be determined and the Treasury Rate will be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month); or • if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

The Treasury Rate will be calculated on the third Business Day preceding such redemption date.

“Comparable Treasury Issue” means the U.S. Treasury security (not inflation-indexed) selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Notes.

“Comparable Treasury Price” means (i) the average of five Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (ii) if the Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. or J.P. Morgan Securities Inc., as specified by the Issuer, or, if these firms are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing in the United States appointed by the Issuer.

190 “Reference Treasury Dealer means (i) Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. and J.P. Morgan Securities Inc. and their respective successors, provided, however, that if any of the foregoing shall cease to be a primary U.S. government securities dealer in The City of New York (a “Primary Treasury Dealer”), the Issuer will substitute therefor another Primary Treasury Dealer and (ii) any three other Primary Treasury Dealers selected by the Issuer after consultation with the Independent Investment Banker. “Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third Business Day preceding such redemption date. Unless the Issuer (and/or the Guarantor) defaults on payment of the redemption price, from and after the redemption date interest will cease to accrue on the Notes or portions thereof called for redemption. On the redemption date, the Issuer will deposit with the Fiscal Agent, or with one or more paying agents (or, if the Issuer is acting as its own paying agent, set aside, segregate and hold in trust as provided in the Fiscal and Paying Agency Agreement) money sufficient to pay the redemption price of and accrued interest on the Notes to be redeemed on such date. If fewer than all of the Notes are to be redeemed, the Fiscal Agent will select, not more than 60 days prior to the redemption date, the particular Notes or portions thereof for redemption from the outstanding Notes not previously called for redemption, on a pro rata basis or by such method as the Fiscal Agent deems fair and appropriate.

Optional Tax Redemption The Notes may be redeemed at any time, at the Issuer’s (or, if applicable, the Guarantor’s) option, as a whole, but not in part, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the principal amount of the Notes then outstanding plus accrued and unpaid interest on the principal amount being redeemed (and all Additional Amounts, if any) to (but excluding) the redemption date, if (i) as a result of any change in, or amendment to, the laws, treaties, regulations or rulings of a Relevant Taxing Jurisdiction or in the interpretation, application or administration of any such laws, treaties, regulations or rulings (including a holding, judgment or order by a court of competent jurisdiction) which becomes effective on or after the issue date (any such change or amendment, a “Change in Tax Law”), the Issuer or (if a payment were then due under the Guarantee, the Guarantor) would be required to pay Additional Amounts and (ii) such obligation cannot be avoided by the Issuer (or the Guarantor) taking reasonable measures available to it. Additional amounts are payable by the Issuer under the circumstances described below under “—Additional amounts”. Prior to the publication or, where relevant, mailing of any notice of redemption pursuant to the foregoing, the Issuer or the Guarantor will deliver to the Fiscal Agent an opinion of independent tax counsel of recognized standing to the effect that the Issuer or the Guarantor is or would be obligated to pay such Additional Amounts as a result of a Change in Tax Law. No notice of redemption may be given earlier than 90 days prior to the earliest date on which the Issuer or the Guarantor would be obligated to pay Additional Amounts if a payment in respect of the Notes were then due. The foregoing provisions shall apply mutatis mutandis to any successor person, after such successor person becomes a party to the Fiscal and Paying Agency Agreement.

Holders’ Option to Repayment upon a Change in Control In the event that (i) a Change of Control (as defined below) occurs, and, within the Change of Control Period (as defined below), a Ratings Downgrade (as defined below) in respect of that Change of Control occurs or is announced (an “Early Redemption Event”): (a) any Holder may, by submitting a redemption notice (the “Early Redemption Notice”), demand from the Issuer repayment as of the Effective Date (as defined under subparagraph (b)(2) below) of any or all of its Notes which have not otherwise been declared due for early redemption, at their principal amount plus

191 interest accrued until (but excluding) the Effective Date (and all Additional Amounts, if any). Each Early Redemption Notice must be received by the Fiscal Agent no less than 30 days prior to the Effective Date; and (b) the Issuer will (1) immediately after becoming aware of the Early Redemption Event, provide written notice thereof to the Holders, and (2) determine and provide written notice of the effective date for the purposes of early repayment (the “Effective Date”). The Effective Date must be a Business Day not less than 60 and not more than 90 days after the giving of the notice regarding the Early Redemption Event pursuant to subparagraph (b)(1).

Any Early Redemption Notice shall be made in writing in English and shall be delivered by hand or by registered mail to the Fiscal Agent not less than ten (10) days prior to the Effective Date at its specified office. The Early Redemption Notice must be accompanied by evidence showing that the relevant Holder is the Holder of the relevant Note(s) at the time the Early Redemption Notice is delivered. Such evidence may be provided in the form of a certificate issued by any custodian or in any other suitable manner. Early Redemption Notices shall be irrevocable.

A “Change of Control“ shall occur if any person or group, acting in concert, gains control over the Guarantor. “Control” for these purposes means any direct or indirect legal or beneficial ownership or any direct or indirect legal or beneficial entitlement (as described in Section 22 of the German Securities Trading Act (Wertpapierhandelsgesetz)) of, in the aggregate, more than 50% of the voting shares of the Guarantor.

The “Change of Control Period“ shall commence on the date of the Change of Control announcement, but not later than on the date of the Change of Control, and shall end 180 days after the Change of Control. “Change of Control Announcement” for these purposes means any public announcement or statement by the Guarantor or any actual or potential bidder relating to a Change of Control.

A “Ratings Downgrade” shall occur if a solicited credit rating for the Guarantor’s long-term unsecured debt falls below investment grade or all Rating Agencies (as defined below) cease to assign (other than temporarily) a credit rating to the Guarantor. A credit rating below investment grade shall mean, in relation to Standard & Poor’s Rating Services, a rating of BB+ or below and, in relation to Moody’s Investor Services Inc., a rating of Ba1 or below and, where another rating agency has been designated by the Guarantor, a comparable rating.

“Rating Agencies“ shall mean each of Standard & Poor’s Ratings Services, a Division of The McGraw Hill Companies, Inc., or Moody’s Investors Services Inc., or any other rating agency designated by the Guarantor.

Modifications and Amendment The Issuer, the Guarantor and the Fiscal Agent may, with the consent of the Holders of not less than a majority in aggregate principal amount of the Notes then outstanding, evidenced as provided in the Fiscal and Paying Agency Agreement, execute agreements adding any provisions to or changing in any manner or eliminating any of the provisions of the Fiscal and Paying Agency Agreement or of any supplemental agreement or modifying in any manner the rights of the Holders under the Notes or the Guarantees; provided that no such agreement shall (a) change the maturity of the principal of any Note, or reduce the principal amount thereof, or reduce the rate or extend the time of payment of any installment of interest thereon, or change the place or currency of payment of principal of, or interest on, any Note, or change the Issuer’s or the Guarantor’s obligation to pay Additional Amounts, impair or affect the right of any Holder to institute suit for the enforcement of any such payment on or after the due date thereof (or in the case of redemption, on or after the redemption date) or change in any manner adverse to the interests of the Holders the terms and provisions of the Guarantees in respect of the due and punctual payment of principal amount of the Notes then outstanding plus accrued and unpaid interest (and all Additional Amounts, if any) without the consent of the Holder of each Note so affected; or (b) reduce the aforesaid percentage of Notes, the consent of the Holders of which is required for any such agreement, without the consent of the Holders of the Notes then outstanding.

192 The Issuer, the Guarantor and the Fiscal Agent may, without the consent of the Holders, from time to time and at any time, enter into a fiscal and paying agency agreement or fiscal and paying agency agreements supplemental thereto for one or more of the following purposes: • to convey, transfer, assign, mortgage or pledge to the Fiscal Agent or another person as security for the Notes any property or assets; • to evidence the succession of another person to the Issuer or the Guarantor, or successive successions, and the assumption by the successor person of the covenants, agreements and obligations of the Issuer or the Guarantor, pursuant to the Fiscal and Paying Agency Agreement; • to evidence and provide for the acceptance of appointment of a successor or successors to the Fiscal Agent in any of its capacities; • to add to the covenants of the Issuer or the Guarantor, such further covenants, restrictions, conditions or provisions as the Issuer or the Guarantor, as the case may be, shall reasonably consider to be for the protection of the Holders, and to make the occurrence, or the occurrence and continuance, of a default in any such additional covenants, restrictions, conditions or provisions an Event of Default under the Notes permitting the enforcement of all or any of the several remedies provided in the applicable fiscal and paying agency agreement; provided that, in respect of any such additional covenant, restriction, condition or provision, such supplemental fiscal and paying agency agreement may provide for a particular period of grace after default (which may be shorter or longer than that allowed in the case of other defaults) or may provide for an immediate enforcement upon such an Event of Default or may limit the right of Holders of a majority in aggregate principal amount of the Notes to waive such an Event of Default; • to modify the restrictions on, and procedures for, resale and other transfers of the Notes pursuant to law, regulation or practice relating to the resale or transfer of restricted securities generally; • to cure any ambiguity or to correct or supplement any provision contained in the Fiscal and Paying Agency Agreement, the Notes or the Guarantees, or in any supplemental agreement, which may be defective or inconsistent with any other provision contained therein or in any supplemental agreement or to make such other provision in regard to matters or questions arising under the Fiscal and Paying Agency Agreement or under any supplemental agreement as the Issuer may deem necessary or desirable and which will not adversely affect the interests of the Holders to which such provision relates in any material respect; and • to “reopen” the Notes of any series and create and issue additional Notes having identical terms and conditions as the Notes of such series (or in all respects except for the issue date, issue price and first interest payment date) so that the additional Notes are consolidated and form a single series with the outstanding Notes.

Negative Pledge So long as any of the Notes remains outstanding neither the Issuer nor the Guarantor will create or permit to subsist any mortgage, charge, pledge, lien or other encumbrance upon any or all of its present or future assets to secure for the benefit of the holders of any present or future Bond Issue the repayment of such present or future Bond Issue without at the same time, or prior thereto, securing such Notes or the Guarantees, as the case may be, equally and rateably therewith. “Bond Issue” means any indebtedness of the Issuer or the Guarantor which is, in the form of, or is represented by, any bond, security, certificate or other instrument which is or is capable of being listed, quoted or traded on any stock exchange or in any securities market (including any over-the-counter market) and any guarantee or other indemnity in respect of such indebtedness.

Events of Default The occurrence and continuance of one or more of the following events will constitute an “Event of Default” under the Fiscal and Paying Agency Agreement and the Notes: (a) payment default — the Issuer fails to pay principal or interest or Additional Amounts within 30 days from the relevant due date; or

193 (b) breach of other obligations — the Issuer defaults in the performance or observance of any of its other obligations under or in respect of the Notes or the Fiscal and Paying Agency Agreement and such default remains unremedied for 90 days after there has been given a written notice to the Issuer by the Fiscal Agent or to the Issuer and the Fiscal Agent by the Holders of at least 25% in principal amount of the outstanding Notes affected thereby, specifying such default or breach and requiring it to be remedied and stating that such notice is a “Notice of Default” under the Notes; or (c) cross-default — any obligation for the payment or repayment of money borrowed having an aggregate outstanding principal amount of at least €50,000,000 (or its equivalent in any other currency) of the Issuer or the Guarantor is not paid within 30 days after the due date or (as the case may be) within any originally applicable longer grace period relating to such obligation or becomes due and payable prior to its stated maturity by reason of default and is not paid within 30 days, or any guarantee or indemnity of any obligation for the payment or repayment of money borrowed having an aggregate outstanding principal amount of at least €50,000,000 (or its equivalent in any other currency) given by the Issuer or the Guarantor is not honored within 30 days after the due date unless, in either such case, proceedings are brought by the Issuer or the Guarantor, in a court of competent jurisdiction, to bona fide challenge its obligation to make payment or repayment of any such amount; or (d) financial distress — the Issuer or the Guarantor announces its inability to meet its financial obligations or ceases its payments; or (e) bankruptcy or insolvency — a court opens bankruptcy or other insolvency proceedings against the Issuer or the Guarantor, or the Issuer or the Guarantor applies for or institutes such proceedings or offers or makes an arrangement (allgemeine Schuldenbereinigung) for the benefit of its creditors generally, or the Issuer applies for a “surseance van betaling” (within the meaning of the Statute of Bankruptcy of The Netherlands), or a third party applies for insolvency proceedings against the Guarantor and such proceedings are not discharged or stayed within 60 days, or (f) liquidation — the Issuer or the Guarantor goes into liquidation unless this is done in connection with a merger or other form of combination with another person and such person assumes all obligations contracted by the Issuer or the Guarantor, as the case may be, under the Notes or the Guarantees; or (g) impossibility due to government action — any governmental order, decree or enactment shall be made in or by The Netherlands or in or by Germany whereby the Issuer or the Guarantor is prevented from observing and performing in full its obligations as set forth in the terms and conditions of the Notes and the Guarantees, respectively, and this situation is not cured within 90 days, or (h) invalidity of the Guarantees — the Guarantees cease to be valid and legally binding for any reason whatsoever.

If an Event of Default occurs and is continuing, then in each and every case, unless the principal of all of the Notes shall already have become due and payable (in which case no action is required for the acceleration of the Notes), the Holders of not less than 25% in aggregate principal amount of Notes then outstanding, by written notice to the Issuer and the Fiscal Agent as provided in the Fiscal and Paying Agency Agreement, may declare the entire principal of all the Notes, and the interest accrued thereon, to be due and payable immediately. Under certain circumstances, the Holders of a majority in aggregate principal amount of the Notes then outstanding may, by written notice to the Issuer and the Fiscal Agent as provided in the Fiscal and Paying Agency Agreement, waive all defaults and rescind and annul such declaration and its consequences, but no such waiver or rescission and annulment shall extend to or shall affect any subsequent default or shall impair any right consequent thereon.

Substitution of Issuer; Consolidation, Merger and Sale of Assets In all cases subject to the provisions described above under “— Holders’ Option to Repayment upon a Change in Control,” (i) the Issuer or the Guarantor, without the consent of the Holders of any of the Notes, may consolidate with, or merge into, or sell, transfer, lease or convey all or substantially all of their respective assets

194 to, any corporation and (ii) the Issuer may at any time substitute for the Issuer either the Guarantor or any Affiliate (as defined below) of the Guarantor as principal debtor under the Notes; provided that: (a) any successor company (other than an Affiliate of the Guarantor) shall expressly assume the Issuer’s or the Guarantor’s respective obligations under the Notes or the Guarantees, as the case may be, and the Fiscal and Paying Agency Agreement; (b) the Issuer is not in default of any payments due under the Notes; and (c) written notice of such transaction shall be promptly provided to the Holders. For purposes of the foregoing, “Affiliate” shall mean any affiliated company (verbundenes Unternehmen) within the meaning of Section 15 German Stock Corporation Act (Aktiengesetz). Upon the effectiveness of any substitution, all of the foregoing provisions will apply mutatis mutandis, and references elsewhere herein to the Issuer or the Guarantor will, where the context so requires, be deemed to be or include references, to any successor company. For as long as any Notes are outstanding, if E.ON International Finance B.V. ceases to have the benefit of exemptive relief from Dutch banking licence requirements available to it under the Dutch Financial Markets Supervision Act (Wet op het financieel toezicht, including its subordinate regulations and decrees, the “FMSA”), E.ON International Finance B.V. will immediately be substituted in accordance with the foregoing conditions with a successor company, which is not subject to Dutch banking regulations or which has the benefit of the appropriate exemptive relief. Discharge and Defeasance Discharge of Fiscal and Paying Agency Agreement The Fiscal and Paying Agency Agreement provides that the Issuer and the Guarantor will be discharged from any and all obligations in respect of the Fiscal and Paying Agency Agreement (except for certain obligations to register the transfer of or exchange Notes, replace stolen, lost or mutilated Notes, make payments of principal and interest and maintain paying agencies) if: • the Issuer has paid or caused to be paid in full the principal of and interest on all Notes outstanding thereunder; • the Issuer shall have delivered to the Fiscal Agent for cancellation all Notes outstanding theretofore authenticated; or • all Notes not theretofore delivered to the Fiscal Agent for cancellation (i) have become due and payable; (ii) will become due and payable in accordance with their terms within one year or (iii) are to be, or have been, called for redemption as described under “— Optional Redemption” or “— Optional Tax Redemption” within one year under arrangements satisfactory to the Fiscal Agent for the giving of notice of redemption, and, in any such case, the Issuer shall have irrevocably deposited with the Fiscal Agent as trust funds in irrevocable trust, specifically pledged as security for, and dedicated solely to, the benefit of the Holders of such Notes, (a) cash in U.S. dollars in an amount, or (b) U.S. Government Obligations (as defined below) which through the payment of interest thereon and principal thereof in accordance with their terms will provide not later than the due date of any payment, cash in U.S. dollars in an amount, or (c) any combination of (a) and (b), sufficient to pay all the principal of, and interest (and Additional Amounts, if any) on, all such Notes not theretofore delivered to the Fiscal Agent for cancellation on the dates such payments are due in accordance with the terms of the Notes and all other amounts payable under the Fiscal and Paying Agency Agreement by the Issuer. “U.S. Government Obligations” means securities which are (i) direct obligations of the U.S. government or (ii) obligations of a person controlled or supervised by and acting as an agency or instrumentality of the U.S. government, the payment of which is unconditionally guaranteed by the U.S. government, which, in either case, are full faith and credit obligations of the U.S. government payable in U.S. dollars and are not callable or redeemable at the option of the issuer thereof and shall also include a depositary receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligation or a specific payment of interest on or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a

195 depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depositary receipt.

Covenant Defeasance The Fiscal and Paying Agency Agreement also provides that the Issuer and the Guarantor need not comply with certain covenants of the Fiscal and Paying Agency Agreement (including those described under “— Negative Pledge”), and the Guarantor shall be released from its obligations under the Guarantees, if: • the Issuer (or the Guarantor) irrevocably deposits with the Fiscal Agent as trust funds in irrevocable trust, specifically pledged as security for, and dedicated solely to, the benefit of the Holders of such Notes, (i) cash in U.S. dollars in an amount, or (ii) U.S. Government Obligations which through the payment of interest thereon and principal thereof in accordance with their terms will provide not later than the due date of any payment cash in U.S. dollars in an amount, or (iii) any combination of (i) and (ii), sufficient to pay all the principal of, and interest on, the Notes then outstanding on the dates such payments are due in accordance with the terms of the Notes; • certain Events of Default, or events which with notice or lapse of time or both would become such an Event of Default, shall not have occurred and be continuing on the date of such deposit; • the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an opinion of tax counsel of recognized standing with respect to U.S. federal income tax matters to the effect that the beneficial owners of the Notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the exercise of such Covenant Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would be the case if such Covenant Defeasance had not occurred; • the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an opinion of tax counsel of recognized standing in its jurisdiction of incorporation to the effect that such deposit and related Covenant Defeasance will not cause the Holders of Notes, other than Holders who are or who are deemed to be residents of such jurisdiction of incorporation or use or hold or are deemed to use or hold their Notes in carrying on a business in such jurisdiction of incorporation, to recognize income, gain or loss for income tax purposes in such jurisdiction of incorporation, and to the effect that payments out of the trust fund will be free and exempt from any and all withholding and other income taxes of whatever nature of such jurisdiction of incorporation or political subdivision thereof or therein having power to tax, except in the case of Notes beneficially owned (i) by a person who is or is deemed to be a resident of such jurisdiction of incorporation or (ii) by a person who uses or holds or is deemed to use or hold such Notes in carrying on a business in such jurisdiction of incorporation; and • the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an officers’ certificate and an opinion of legal counsel of recognized standing, each stating that all conditions precedent provided for relating to such Covenant Defeasance have been complied with.

The effecting of these arrangements is also known as “Covenant Defeasance”.

Additional Amounts The Issuer (and/or the Guarantor) will make all payments in respect of the Notes without withholding or deduction for or on account of any present or future taxes or duties of whatever nature imposed or levied by way of withholding or deduction at source by or on behalf of any jurisdiction in which the Issuer or Guarantor is incorporated, organized, or otherwise tax resident or any political subdivision or any authority thereof or therein having power to tax (the “Relevant Taxing Jurisdiction”) unless such withholding or deduction is required by

196 law. In such event, the Issuer or, as the case may be, the Guarantor will pay to the Holders such additional amounts (the “Additional Amounts”) as shall be necessary in order that the net amounts received by the Holders, after such withholding or deduction, shall equal the respective amounts of principal and interest which would otherwise have been receivable in the absence of such withholding or deduction; except that no such Additional Amounts shall be payable on account of any taxes or duties which: (a) are payable by any person acting as custodian bank or collecting agent on behalf of a Holder, or otherwise in any manner which does not constitute a deduction or withholding by the Issuer from payment of principal or interest made by it, or (b) are payable by reason of the Holder or beneficial owner having, or having had, some personal or business connection with such Relevant Taxing Jurisdiction and not merely by reason of the fact that payments in respect of the Notes or the Guarantees are, or for purposes of taxation are deemed to be, derived from sources in, or are secured in the Relevant Taxing Jurisdiction, or (c) are imposed or withheld by reason of the failure of the Holder or beneficial owner to provide certification, information, documents or other evidence concerning the nationality, residence, or identity of the Holder and beneficial owner or to make any valid or timely declaration or similar claim or satisfy any other reporting requirements relating to such matters, whether required or imposed by statute, treaty, regulation or administrative practice, as a precondition to exemption from, or a reduction in the rate of withholding or deduction of such taxes, or (d) consist of any estate, inheritance, gift, sales, excise, transfer, personal property or similar taxes, or (e) are imposed on or with respect to any payment by the Issuer or Guarantor to the registered Holder if such Holder is a fiduciary or partnership or any person other than the sole beneficial owner of such payment to the extent that taxes would not have been imposed on such payment had such registered Holder been the sole beneficial owner of such Note, or (f) are deducted or withheld pursuant to (i) any European Union directive or regulation concerning the taxation of interest income, or (ii) any international treaty or understanding relating to such taxation and to which the Relevant Taxing Jurisdiction or the European Union is a party, or (iii) any provision of law implementing, or complying with, or introduced to conform with, such directive, regulation, treaty or understanding, or (g) are payable by reason of a change in law or practice that becomes effective more than 30 days after the relevant payment of principal or interest becomes due, or is duly provided for and written notice thereof is provided to the Holders, whichever occurs later, or (h) are payable because any Note was presented to a particular paying agent for payment if the Note could have been presented to another paying agent without any such withholding or deduction, or (i) are payable for any combination of (a) through (h) above.

References to principal or interest in respect of the Notes shall be deemed to include any Additional Amounts, which may be payable as set forth in the Fiscal and Paying Agency Agreement.

Indemnification of Judgment Currency To the fullest extent permitted by applicable law, the Issuer and the Guarantor will indemnify each Holder against any loss incurred by such Holder as a result of any judgment or order being given or made for any amount due under any Note or Guarantee and such judgment or order being expressed and paid in a currency (the “Judgment Currency”), which is other than U.S. dollars and as a result of any variation as between (i) the rate of exchange at which the U.S. dollar is converted into the Judgment Currency for the purposes of such judgment or order and (ii) the spot rate of exchange in The City of New York at which the Holder on the date of payment of such judgment is able to purchase U.S. dollars with the amount of the Judgment Currency actually received by such Holder. This indemnification will constitute a separate and independent obligation of the Issuer or the

197 Guarantor, as the case may be, and will continue in full force and effect notwithstanding any such judgment or order as aforesaid. The term “spot rate of exchange” includes any premiums and costs of exchange payable in connection with the purchase of, or conversion into, U.S. dollars.

Governing Law; Submission to Jurisdiction The Fiscal and Paying Agency Agreement, the Notes and the Guarantees will be governed by and construed in accordance with the laws of the State of New York.

The Issuer and the Guarantor have irrevocably submitted to the non-exclusive jurisdiction of the courts of any U.S. state or federal court in the Borough of Manhattan in The City of New York, New York with respect to any legal suit, action or proceeding arising out of or based upon the Fiscal and Paying Agency Agreement, the Notes or the Guarantees.

Regarding the Fiscal Agent, Paying Agent, Transfer Agent and Registrar In acting under the Fiscal and Paying Agency Agreement, and in connection with the Notes and the Guarantees, the Fiscal Agent, paying agent, any transfer agent and registrar, and any additional or successor fiscal agent, transfer agents, paying agents or registrars, are acting solely as agents of the Issuer and the Guarantor and do not assume any obligation towards or relationship of agency or trust for or with the owners or Holders, except that any funds held by any paying agent for payment of principal of or interest on the Notes shall be held in trust by it for the persons entitled thereto and applied as set forth in the Fiscal and Paying Agency Agreement and in the Notes, but need not be segregated from other funds held by it except as required by law. For a description of the duties and the immunities and rights of any Fiscal Agent, paying agent, transfer agent or registrar under the Fiscal and Paying Agency Agreement, reference is made to the Fiscal and Paying Agency Agreement, and the obligations of any Fiscal Agent, paying agent, transfer agent and registrar to the Holder are subject to such immunities and rights.

198 BOOK-ENTRY; DELIVERY AND FORM Summary of Provisions Relating to Notes in Global Form The certificates representing the Notes (and the Guarantees) will be issued in fully registered form without interest coupons. The Notes will be represented by Book-Entry Interests (as defined below) and are being offered and sold only (i) to Qualified Institutional Buyers, or QIBs, in reliance on Rule 144A under the Securities Act (the “Rule 144A Notes”) or (ii) to persons other than U.S. persons (within the meaning of Regulation S under the Securities Act) in offshore transactions in reliance on Regulation S (the “Regulation S Notes”). The Regulation S Notes will initially be represented by one or more permanent Regulation S global notes in definitive, fully registered form without interest coupons (the “Regulation S Global Notes”), and will be deposited with the Fiscal Agent as custodian for, and registered in the name of a nominee of, DTC for the accounts of its participants, including Euroclear and Clearstream. Prior to the 40th day after the later of the commencement of the offering of the Notes and the date of the original issue of the Notes, any resale or other transfer of beneficial interests in a Regulation S Global Note (“Regulation S Book-Entry Interests”) or a Rule 144A Global Note as defined below (“Rule 144A Book-Entry Interests” and, together with the Regulation S Book-Entry Interests, the “Book-Entry Interests”) to U.S. persons shall not be permitted unless such resale or transfer is made pursuant to Rule 144A or Regulation S and in accordance with the certification requirements described below. The Rule 144A Notes will be represented by one or more permanent Rule 144A global notes in definitive, fully registered form without interest coupons (the Rule 144A Global Notes and, together with the Regulation S Global Notes, the “Global Notes”), with such appropriate insertions, omissions, substitutions and other variations as are required or permitted by the Fiscal and Paying Agency Agreement and such legends as may be applicable thereto, and will be deposited with the Fiscal Agent as custodian for, and registered in the name of DTC or a nominee of DTC duly executed by the Issuer and authenticated by the Fiscal Agent as provided in the Fiscal and Paying Agency Agreement. Rule 144A Book-Entry Interests may be transferred to a person who takes delivery in the form of Regulation S Book-Entry Interests only upon receipt by the Fiscal Agent of written certifications from the transferor (in the form or forms provided in the Fiscal and Paying Agency Agreement) to the effect that such transfer is being made to a person other than a U.S. person in an offshore transaction in reliance on Regulation S under the Securities Act and pursuant to the transfer restrictions related to a Rule 144A Global Note as described in this offering memorandum. Regulation S Book-Entry Interests may be transferred to a person who takes delivery in the form of Rule 144A Book-Entry Interests only if such transfer occurs at least 40 days after the later of the commencement of the offering of the Notes and the closing date and is made pursuant to Rule 144A and, in addition, only upon receipt by the Fiscal Agent of written certifications from the transferor (in the form or forms provided in the Fiscal and Paying Agency Agreement) to the effect that such transfer is being made to a person who the transferor reasonably believes is a QIB within the meaning of Rule 144A in a transaction meeting the requirements of Rule 144A and in accordance with all applicable securities laws of the states of the United States and other jurisdictions. Each Global Note (and any Notes issued in exchange therefor) will be subject to certain restrictions on transfer set forth therein described under “Transfer Restrictions.” Except in the limited circumstances described below under “— Summary of Provisions Relating to Certificated Notes”, owners of Book-Entry Interests will not be entitled to receive physical delivery of certificated Notes. Ownership of Book-Entry Interests will be limited to persons who have accounts with DTC, or participants, or persons who hold interests through participants. Ownership of Book-Entry Interests will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interests of persons other than participants). Qualified institutional buyers may hold their Rule 144A Book-Entry Interests directly through DTC if they are participants in such system, or indirectly through organizations which are participants in such system. Investors may hold their Regulation S Book-Entry Interests directly through Euroclear or Clearstream, if they are participants in such systems, or indirectly through organizations that are participants in such systems. Euroclear and Clearstream will hold Regulations S Book-Entry Interests on behalf of their participants through DTC.

199 So long as DTC, or its nominee, is the registered owner or holder of a Global Note, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the Notes represented by such Global Note for all purposes under the Fiscal and Paying Agency Agreement and the Notes. No beneficial owner of a Book-Entry Interest will be able to transfer that interest except in accordance with DTC’s applicable procedures, in addition to those provided for under the fiscal and paying agency agreement and, if applicable, those of Euroclear and Clearstream.

Conveyance of notices and other communications by DTC to its participants, by those participants to its indirect participants, and by participants and indirect participants to beneficial owners of Book-Entry Interests will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

The Fiscal Agent will send any notices in respect of the Notes held in book-entry form to DTC or its nominee.

Neither DTC nor its nominee will consent or vote with respect to the Notes unless authorized by a participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to the Issuer as soon as possible after the record date. The omnibus proxy assigns DTC’s or its nominee’s consenting or voting rights to those participants to whose account the Notes are credited on the record date.

Payments of the principal of, and interest on, a Global Note will be made to DTC or its nominee, as the case may be, as the registered owner thereof. Neither the Issuer, the Guarantor nor the Fiscal Agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of Book-Entry Interests or for maintaining, supervising or reviewing any records relating to such Book-Entry Interests.

The Issuer expects that DTC or its nominee, upon receipt of any payment of principal or interest in respect of a Global Note, will credit participants’ accounts with payments in amounts proportionate to their respective Book-Entry Interests in the principal amount of such Global Note as shown on the records of DTC or its nominee. The Issuer also expects that payments by participants to owners of Book-Entry Interests in such Global Note held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payments will be the responsibility of such participants.

Transfers between participants in DTC will be effected in the ordinary way in accordance with DTC rules and will be settled in same-day funds. Transfers between participants in Euroclear and Clearstream will be effected in the ordinary way in accordance with their respective rules and operating procedures.

Cross-market transfers between persons holding directly or indirectly through DTC, on the one hand, and directly or indirectly through Euroclear or Clearstream participants, on the other, will be effected in DTC in accordance with DTC rules on behalf of the relevant European international clearing system by the relevant European depositary; however, those cross-market transactions will require delivery of instructions to the relevant European international clearing system by the counterparty in that system in accordance with its rules and procedures and within its established deadlines (European time). The relevant European international clearing system will, if the transaction meets its settlement requirements, deliver instructions to the relevant European depositary to take action to effect final settlement on its behalf by delivering or receiving securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the European depositaries.

Because of time zone differences, credits of securities received in Euroclear or Clearstream as a result of a transaction with a person that does not hold the Notes through Euroclear or Clearstream will be made during subsequent securities settlement processing and dated the first day Euroclear or Clearstream, as the case may be,

200 is open for business following the DTC settlement date. Those credits or any transactions in those securities settled during that processing will be reported to the relevant Euroclear or Clearstream participants on that business day. Cash received in Euroclear or Clearstream as a result of sales of securities by or through a Euroclear participant or a Clearstream participant to a DTC participant will be received with value on the DTC settlement date, but will be available in the relevant Euroclear or Clearstream cash account only as of the first day Euroclear or Clearstream, as the case may be, is open for business following settlement in DTC.

The Issuer expects that DTC will take any action permitted to be taken by a holder of Notes (including the presentation of Notes for exchange as described below) only at the direction of one or more participants to whose account the DTC interests in a Global Note are credited and only in respect of such portion of the aggregate principal amount of Notes as to which such participant or participants has or have given such direction. However, if there is an event of default under the Notes, DTC will exchange the applicable Global Note for certificated Notes, which it will distribute to its participants and which may be legended as set forth under the heading “Transfer Restrictions.”

DTC DTC advises that it is a limited purpose trust company organized under The New York Banking Law, a “banking organization” within the meaning of The New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of The New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds securities for its participants and facilitates the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of securities certificates. Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Indirect access to the DTC system is available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly, or indirect participants.

Euroclear Euroclear holds securities and book-entry interests in securities for participating organizations and facilitates the clearance and settlement of securities transactions between Euroclear participants, and between Euroclear participants and participants of certain other securities intermediaries through electronic book-entry changes in accounts of such participants or other securities intermediaries. Euroclear provides Euroclear participants, among other things, with safekeeping, administration, clearance and settlement, securities lending and borrowing, and related services. Euroclear participants are investment banks, securities brokers and dealers, banks, central banks, supranationals, custodians, investment managers, corporations, trust companies and certain other organizations. Certain of the Initial Purchasers, or other financial entities involved in this offering, may be Euroclear participants. Non-participants in the Euroclear system may hold and transfer book-entry interests in the Notes through accounts with a participant in the Euroclear system or any other securities intermediary that holds a book-entry interest in the securities through one or more securities intermediaries standing between such other securities intermediary and Euroclear.

Investors electing to acquire Notes in the offering through an account with Euroclear or some other securities intermediary must follow the settlement procedures of such intermediary with respect to the settlement of new issues of securities. Notes to be acquired against payment through an account with Euroclear will be credited to the securities clearance accounts of the respective Euroclear participants in the securities processing cycle for the first day Euroclear is open for business following the settlement date for value as of the settlement date.

Investors electing to acquire, hold or transfer Notes through an account with Euroclear or some other securities intermediary must follow the settlement procedures of such intermediary with respect to the settlement

201 of secondary market transactions in securities. Euroclear will not monitor or enforce any transfer restrictions with respect to the Notes. Investors that acquire, hold and transfer interests in the Notes by book-entry through accounts with Euroclear or any other securities intermediary are subject to the laws and contractual provisions governing their relationship with their intermediary, as well as the laws and contractual provisions governing the relationship between such intermediary and each other intermediary, if any, standing between themselves and the individual Notes.

Euroclear has advised that, under Belgian law, investors that are credited with securities on the records of Euroclear have a co-property right in the fungible pool of interests in securities on deposit with Euroclear in an amount equal to the amount of interests in securities credited to their accounts. In the event of the insolvency of Euroclear, Euroclear participants would have a right under Belgian law to the return of the amount and type of interests in securities credited to their accounts with Euroclear. If Euroclear did not have a sufficient amount of interests in securities on deposit of a particular type to cover the claims of all participants credited with such interests in securities on Euroclear’s records, all participants having an amount of interests in securities of such type credited to their accounts with Euroclear would have the right under Belgian law to the return of their pro rata share of the amount of interests in securities actually on deposit. Under Belgian law, Euroclear is required to pass on the benefits of ownership in any interests in Notes on deposit with it (such as dividends, voting rights and other entitlements) to any person credited with such interests in securities on its records. Distributions with respect to the Notes held beneficially through Euroclear will be credited to the cash accounts of Euroclear participants in accordance with the Euroclear terms and conditions.

Clearstream Clearstream advises that it is incorporated under the laws of Luxembourg and licensed as a bank and professional depositary. Clearstream holds securities for its participating organizations and facilitates the clearance and settlement of securities transactions among its participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of certificates. Clearstream provides to its participants, among other things, services for safekeeping, administration, clearance and settlement of internationally traded securities and securities lending and borrowing. Clearstream interfaces with domestic markets in several countries. Clearstream has established an electronic bridge with the Euroclear operator to facilitate the settlement of trades between Clearstream and Euroclear. As a registered bank in Luxembourg, Clearstream is subject to regulation by the Luxembourg Commission for the Supervision of the Financial Sector. As a professional depository, Clearstream is subject to regulation by the Luxembourg Monetary Institute. Clearstream participants are recognized financial institutions around the world, including underwriters, securities brokers and dealers, banks, trust companies and clearing corporations. In the United States, Clearstream participants are limited to securities brokers and dealers and banks, and may include the Initial Purchasers, or other financial entities involved in, this offering. Other institutions that maintain a custodial relationship with a Clearstream participant may obtain indirect access to Clearstream. Clearstream is an indirect participant in DTC. Distributions with respect to Notes held beneficially through Clearstream will be credited to cash accounts of Clearstream participants in accordance with its rules and procedures.

Although DTC, Euroclear and Clearstream are expected to follow the foregoing procedures in order to facilitate transfers of interests in a global note among participants of DTC, Euroclear and Clearstream, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither the Issuer nor the fiscal agent will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their respective operations.

The information in this section concerning DTC, Euroclear and Clearstream and DTC’s book-entry system has been obtained from sources that the Issuer believes to be reliable, but the Issuer takes no responsibility for the accuracy thereof.

202 Summary of Provisions Relating to Certificated Notes If DTC is at any time unwilling or unable to continue as a depositary for the Global Notes and a successor depositary is not appointed by the Issuer within 90 days, or if there shall have occurred and be continuing an event of default with respect to the Notes, the Issuer will issue certificated Notes, with Guarantees endorsed thereon by the Guarantor, in exchange for the Global Notes. Certificated notes delivered in exchange for Book- Entry Interests will be registered in the names, and issued in denominations of $1,000 and integral multiples of $1,000 in excess thereof, requested by or on behalf of DTC or the successor depositary (in accordance with its customary procedures). Holders of Book-Entry Interests may receive certificated Notes, which may bear the legend referred to under “Transfer Restrictions”, in accordance with DTC’s rules and procedures in addition to those provided for under the Fiscal and Paying Agency Agreement.

Except in the limited circumstances described above, owners of Book-Entry Interests will not be entitled to receive physical delivery of individual definitive certificates. The Notes are not issuable in bearer form.

Subject to any applicable transfer restrictions, the holder of a certificated note bearing the legend referred to under “Transfer Restrictions” may transfer or exchange such Notes in whole or in part by surrendering them to the Fiscal Agent. Prior to any proposed transfer of Notes in certificated form, the holder may be required to provide certifications and other documentation to the Fiscal Agent as described above. In the case of a transfer of only part of a note, the original principal amount of both the part transferred and the balance not transferred must be in authorized denominations, and new Notes will be issued to the transferor and transferee, respectively, by the Fiscal Agent. Upon the transfer, exchange or replacement of certificated Notes not bearing the legend described above, the Fiscal Agent will deliver certificated Notes that do not bear such legend.

Upon the transfer, exchange or replacement of certificated Notes bearing the legend described above, or upon a specific request for removal of the legend from such certificated note, the Fiscal Agent will deliver only certificated Notes bearing such legend or will refuse to remove such legend, as the case may be, unless there is delivered to the Issuer such satisfactory evidence, which may include an opinion of legal counsel of recognized standing, as may be reasonably required by the Issuer that neither the legend nor the restrictions on transfer set forth therein are required to ensure compliance with the provisions of the Securities Act.

Payment of principal and interest in respect of the certificated Notes shall be payable at the office or agency of the Issuer in the City of New York which shall initially be at the corporate trust office of the Fiscal Agent, which is located at 452 Fifth Avenue, New York, NY 10018, provided that at the option of the Issuer with prior notice to the paying agent, payment may be made by wire transfer, direct deposit or check mailed to the address of the holder entitled thereto as such address appears in the note register.

If the Issuer decides to maintain a paying agent with respect to the Notes in a member state of the European Union, it will ensure such paying agent is in a member state of the European Union that is not obligated to withhold or deduct tax pursuant to European Council Directive 2003/48/EC or any other directive implementing the conclusions of ECOFIN Council meeting of November 26-27, 2000 on the taxation of savings income, or any law implementing or complying with, or introduced in order to conform to, such Directive or such other directive.

The certificated Notes, at the option of the Holder and subject to the restrictions contained in the Notes and in the Fiscal and Paying Agency Agreement, may be exchanged or transferred, upon surrender for exchange or presentation for registration of transfer at the office of the Fiscal Agent. Any certificated note surrendered for exchange or presented for registration of transfer shall be duly endorsed, or be accompanied by a written instrument of transfer in form satisfactory to the Fiscal Agent, duly endorsed by the Holder thereof or his attorney duly authorized in writing. Notes issued upon such transfer will be executed by the Issuer and authenticated by the Fiscal Agent, registered in the name of the designated transferee or transferees and delivered at the office of the Fiscal Agent or mailed, at the request, risk and expense of, and to the address requested by, the designated transferee or transferees.

203 TAXATION Taxation in Germany The following is a general discussion of certain German tax consequences of the acquisition, ownership and disposition of the Notes. This discussion does not purport to be a comprehensive description of all tax consequences that may be relevant to an investor’s decision to invest in the Notes. In particular, this discussion does not consider any specific tax consequences that may apply due to facts or circumstances of a particular investor. The discussion is based on the laws of Germany as currently in force and applied on the date of this Offering Memorandum. Such laws are subject to changes, possibly with retroactive effect. The discussion is not intended to be, nor should it be construed to be, legal or tax advice.

Prospective investors in the Notes are urged to consult their own tax advisors as to the tax consequences of the acquisition, ownership or disposition of the Notes, including the effect of any state or local taxes, under the tax laws of Germany and any other relevant jurisdiction.

The German tax laws concerning the taxation of capital investment income in the hands of individual investors holding the Notes as private assets will change significantly generally with effect as of 2009. These changes are described below under the caption “— Company Tax Reform Act 2008”. For individual investors holding the Notes as private assets, the tax consequences described below under the captions “— German Holders” and “— Non German Holders” will only be applicable in 2008, and, under certain circumstances, to the disposition or redemption of Notes that have been acquired in 2008.

German Holders Taxation of Interest Income Under German tax law, as currently in effect, payments of interest on the Notes including payments for interest that accrued up to a disposition of a Note and is credited separately (“Accrued Interest”; Stückzinsen), to persons who are residents of Germany (e.g., persons whose residence, habitual abode, statutory seat or place of management is located in Germany, a “German Holder”) are subject to German individual income tax at progressive individual tax rates or corporate income tax (in each case plus solidarity surcharge thereon which is currently levied at a rate of 5.5%). Interest income derived from the Notes may also be subject to trade tax on income if the Notes are held as part of a German business establishment for trade tax purposes.

Individual investors are entitled to an annual lump-sum deduction for expenses related to investment income (Werbungskosten-Pauschbetrag)of€51 (€102 for married couples filing jointly) in computing their income from capital investment (including income earned from the Notes) as well as an annual saver’s exemption (Sparer- Freibetrag)of€750 (€1,500 for married couples filing jointly) with respect to such investment income.

Withholding Tax on Interest Income If the Notes are kept or administered in a custodial account maintained by a German Holder with a German resident bank or a German resident financial services institution, also including a German branch of a foreign bank or a foreign financial services institution but excluding a foreign branch of a German bank or a German financial services institution (“German Disbursing Agent”), a 30% withholding tax on interest payments (Zinsabschlag), plus a 5.5% solidarity surcharge thereon, will be withheld by such German Disbursing Agent on payments of interest, resulting in a total withholding tax charge of 31.65% on the gross amount of interest paid. If a German Holder sells Notes during a current interest period, Accrued Interest received in connection therewith will also be subject to withholding tax at a rate of 30% and 5.5% solidarity surcharge thereon. Accrued Interest paid by a German Holder upon the purchase of the Notes may be offset against the amount of interest income received by such German Holder and, under certain circumstances, may reduce the amount subject to withholding tax. If the Notes are presented for payment at the offices of a German Disbursing Agent (over-the- counter-transaction; Tafelgeschäft), withholding tax will be imposed at a rate of 35%, plus a 5.5% solidarity surcharge thereon, resulting in a total withholding tax charge of 36.925%.

204 Withholding tax and solidarity surcharge thereon might be credited as prepayments against the German Holder’s final tax liability for German individual income or corporate income tax purposes and the respective solidarity surcharge, or, if in excess of such liability, refunded upon application.

No tax is withheld by the Disbursing Agent if the holder is an individual who has filed a withholding exemption certificate (Freistellungsauftrag) with the Disbursing Agent and the respective Notes are not part of a German trade or business property or generate income from the letting and leasing of property. However, this exemption applies only to the extent that the aggregate interest income derived from the Notes together with an individual’s other investment income administered by the Disbursing Agent does not exceed the respective applicable maximum annual exemption amount (up to €801 for individuals and €1,602 for married couples filing jointly). Further, no withholding obligation exists, if the holder of the Notes submits a certificate of non- assessment (Nichtveranlagungsbescheinigung) issued by the local tax office to the Disbursing Agent.

Disposition or Redemption of the Notes Capital gains resulting from the disposition or redemption of Notes (or, as the case may be, from the payment at maturity of the Notes) realized by individual German Holders holding the Notes as private assets (“German Private Investors”) are generally taxable if the capital gain is realized within one year after the acquisition of the Notes. Capital losses realized by German Private Investors from the disposition or redemption of the Notes may only be offset against taxable capital gains resulting from the disposition or redemption of Notes or from other private transactions (private Veräußerungsgeschäfte) within the same fiscal year and, subject to certain limitations, in the preceding year or in subsequent years.

If the German Private Investor’s aggregate capital gain from taxable private transactions amounts to less than €512 in one calendar year the capital gains are not subject to German income tax.

Capital gains derived by German Private Investors from the disposition or redemption of Notes are not subject to German income tax if the Notes are sold or redeemed more than one year after their acquisition, provided that the Notes do not qualify as Financial Innovations, as described under the following caption “Special Rules for Financial Innovations.” Currency gains derived by German Private Investors are only taxable if the disposition or redemption of the Notes is realized within one year after their acquisition.

Irrespective of a holding period, any capital gain resulting from the disposition or redemption of Notes (or, as the case may be, from the payment at maturity of the Notes) are subject to individual income or corporate income tax, including trade tax, if such Notes are held as business assets of a German Holder.

Special Rules for Financial Innovations To the extent Notes are classified as financial innovations (“Financial Innovations”; Finanzinnovationen), special provisions apply to the disposition or redemption, or upon maturity, of the Notes by German Private Investors. In particular, debt instruments may be classified as Financial Innovations if they provide for a floating, variable or contingent interest rate, an issue discount or certain optional redemption rights.

In case Notes are classified as Financial Innovations, capital gains arising upon the disposition or redemption, or upon maturity, of Notes realized by a German Private Investor (including capital gains so derived by a secondary or subsequent purchaser who is a German Private Investor) are fully or partially subject to income tax, regardless of the one-year holding period described above under the caption “Disposition or Redemption of the Notes”. If a yield to maturity (Emissionsrendite) cannot be established, the difference between the proceeds from the disposition or redemption and the purchase price of the Notes (market yield; Marktrendite), is deemed interest income. In case a yield to maturity can be established, only the part of the capital gain attributable to such yield to maturity during the period the respective German Private Investor held the new note is subject to income tax.

205 Upon the disposition or redemption, or upon maturity, of Notes that are classified as Financial Innovations, the difference between the purchase price and the proceeds from the disposition is subject to 30% withholding tax (plus a solidarity surcharge of 5.5% thereon) if the Notes are kept or administered in a custodial account by the same German Disbursing Agent since the acquisition of the Notes. If the Notes have not been so kept in a custodial account by the same German Disbursing Agent, withholding tax at the same rate will be imposed on 30% of the proceeds received upon the disposition or redemption, or upon the maturity, of the Notes.

As described above such withholding tax might be credited or refunded upon application.

Non-German Holders Income derived from the Notes by persons who are not tax residents of Germany (“Non-German Holder”) is in general exempt from German individual income or corporate income taxation, and no withholding tax must be withheld (even if the Notes are kept with a German Disbursing Agent), provided (i) the Notes are not held as business assets (Betriebsvermögen) of a German permanent establishment of the Non-German Holder or a fixed base or as a business asset for which a permanent representative has been appointed in Germany, (ii) the Notes are not presented for payment at the offices of a German Disbursing Agent in an over-the-counter-transaction, (iii) the income derived from the Notes does not otherwise constitute German source income (such as income from the letting and leasing of certain German situs property) and (iv) in the event that the Notes are kept or administered in a custodial account maintained with a German Disbursing Agent, the Holder of the Notes complies with the applicable procedural rules under German law and provides evidence of the fact that the Holder of the Notes is not subject to taxation in Germany.

If the income is subject to German taxation (e.g., if the Notes are held as business assets of a German permanent establishment of a Non-German Holder), such Holder is subject to a tax treatment similar to that described above under the caption “— German Holders.”

If the Notes are involved in an over-the-counter-transaction, as described above, income derived therefrom will be subject to withholding tax of 35% plus a 5.5% solidarity surcharge thereon.

Company Tax Reform Act 2008 The “Company Tax Reform Act 2008” (Federal Law Gazette I 2007, 1912) provides for various substantial changes in the taxation of individual investors in respect of capital investment income. In the following certain important changes are described which could become relevant for German Holders and Non-German Holders.

The new provisions under the Company Tax Reform Act 2008 regarding the taxation of interest income and capital gains (see the description under the caption — “Taxation of Interest Income and Capital Gains” below) and the withholding tax (see the description under the caption — “Withholding Tax on Interest Income and Capital Gains” below) will apply to interest on the Notes, including Accrued Interest, received by a German Private Investor after December 31, 2008. Capital gains derived by a German Private Investor from a disposition or redemption of the Notes will be subject to the new provisions after December 31, 2008 if (i) the Notes have been acquired after December 31, 2008 or (ii) qualify as Financial Innovations.

German Holders Taxation of Interest Income and Capital Gains Payments of interest on the Notes, including Accrued Interest, to German Private Investors will be subject to German income tax generally at a flat rate of 25% (plus solidarity surcharge thereon, which is currently levied at a rate of 5.5%, resulting in a total rate of 26.375%). Irrespective of the holding period or the qualification of the Notes as Financial Innovations, capital gains derived by German Private Investors from the disposition or redemption of the Notes (or, as the case may be, from the payment at maturity of the Notes) generally will be subject to German income tax at the same flat rate (plus solidarity surcharge thereon). The taxable capital gain

206 will be the difference between the proceeds received upon the disposition or redemption, or upon the maturity, of the Notes (after the deduction of the actual expenses directly related to the sale) and the acquisition costs. Losses from the redemption or disposition of Notes realized after December 31, 2008 may generally be offset only against profits from other capital gains or other capital income in the same or, subject to various limitations, subsequent fiscal years. The deduction for actual expenses related to the income is replaced by a saver’s lump-sum deduction (Sparer-Pauschbetrag) of €801 (€1,602 for married couples filing jointly). Where the Notes are issued in a currency other than Euro, both the proceeds derived from disposition or redemption and the acquisition costs, will be converted into Euro taking into account the relevant conversion rates as of the date of acquisition and disposition or redemption, respectively.

Withholding Tax on Interest Income and Capital Gains The rate at which withholding tax will be levied on interest payments on the Notes, including Accrued Interest, if the Notes are kept or administered in a custodial account maintained by a German Holder with a German Disbursing Agent (which term also includes, as of 2009, a German securities trading firm (Wertpapierhandelsunternehmen) or a German securities trading bank (Wertpapierhandelsbank)), will be reduced to 25% plus a 5.5% solidarity surcharge thereon, resulting in a total withholding tax charge of 26.375%. Withholding tax at such rate will generally also be levied on capital gains irrespective of whether or not the Notes are classified as Financial Innovations. The same withholding tax rate applies to an over-the-counter- transaction. In addition, under the new provisions, church tax may be levied by way of withholding upon application by a German Private Investor. In the event that (i) the Notes have not been so kept in a custodial account by the same German Disbursing Agent since their acquisition and (ii) the relevant acquisition costs could not be established by the relevant German Holder by way of certification from the previous German Disbursing Agent or from a foreign bank or foreign financial services institution within the European Economic Area or a foreign branch of a German bank or financial services institution within the European Economic Area, withholding tax at the same rate will be imposed on 30% of the proceeds received upon the disposition or redemption, or upon the maturity, of the Notes. The withholding tax will generally be a final tax for German Private Investors, i.e., the income tax liability is generally satisfied through the withholding and interest payments or capital gains which have been subject to the withholding tax are not to be included in the annual income tax return (Abgeltungssteuer). However, upon election and filing of an annual income tax return, the German Private Investors’ income derived from interest payments, including Accrued Interest, and capital gains from the disposition or redemption of the Notes can be taxed at regular individual tax rates if this results in a lower income tax burden. The tax withheld at source will then be credited against the individual income tax liability assessed or, if in excess of such liability, refunded.

Non-German Holders Non-German Holders of the Notes will in general not be subject to German taxation with their interest or capital gains from the Notes and no tax will in general be withheld by German Disbursing Agents under the conditions described under the previous caption “— Non-German Holders”. If interest or capital gains from the Notes will be subject to taxation in Germany and the Notes are kept or administered by a German Disbursing Agent (or involved in an over-the-counter-transaction), withholding tax at the reduced rate of 25% (plus solidarity surcharge thereon, which is currently levied at a rate of 5.5%, resulting in a total withholding tax charge of 26.375%) will be levied on interest and capital gains from the Notes. Such withholding tax can be credited against the German individual or corporate income tax liability of a Non-German Holder or, if in excess of such liability, refunded.

Substitution of the Issuer The Guarantor or certain of its subsidiaries may, subject to certain restrictions, assume the obligations of the Issuer under the Notes without the consent of the holders. Such an assumption may be treated as a taxable

207 disposition for German income tax purposes and could lead to a gain equal to the difference between the fair market value as of the date of the assumption and the relevant acquisition cost of the Notes, which would be subject to the same rules applicable to a disposition of the Notes (discussed above). Holders should consult their own tax advisors regarding the German tax consequences of such an assumption.

Inheritance and Gift Tax, Other Taxes No inheritance or gift tax with respect to any Notes will arise under the laws of Germany, if, in the case of inheritance tax, both the decedent and the beneficiary, and, in the case of gift tax, both the donor and the donee, are tax non-residents and are not deemed to be tax residents of Germany at the time of the transfer and such Notes are not attributable to a permanent establishment or to a business property for which a permanent representative has been appointed in Germany. In the case of a decedent, donor or heir who is a German national, this only applies if such person has been a non-resident of Germany for more than five consecutive years. No stamp, issue, registration or similar taxes or duties will be payable in Germany in connection with the issuance, delivery or execution of the Notes. Under certain circumstances, an entrepreneur may opt to have value-added tax levied on a transaction involving the disposition of the Notes, when such transaction is executed for the enterprise of another entrepreneur. Currently, net asset tax (Vermögensteuer) is not levied in Germany.

EU Savings Directive The Council of the European Union (the “Council”) on June 3, 2003 adopted a directive regarding the taxation of savings income (2003/48/EC, the “Directive”). Under the Directive, Member States will be required to provide to the tax authorities of another Member State information about payments of interest (or other similar income) paid by a person within its jurisdiction to an individual resident in that other Member State except that, from the date of implementation of the Directive, Belgium, Luxembourg and Austria have instead offered to operate a withholding system for a transitional period in relation to such payments (the ending of such transitional period in particular being dependent upon the conclusion of agreements relating to information exchange with certain other countries). The Directive has come into effect on July 1, 2005. A number of non-EU countries, and certain dependent or associated territories of certain Member States, have agreed to adopt similar measures (either provisions of information or transitional withholding) in relation to payments made by a person within its jurisdiction to an individual resident in a Member State. In addition, the Member States have entered into reciprocal provision of information or transitional withholding arrangements with certain of those dependent or associated territories in relation to payments made by a person in a Member State to an individual resident in one of those territories.

United States Federal Income Tax Considerations TO ENSURE COMPLIANCE WITH TREASURY DEPARTMENT CIRCULAR 230, INVESTORS ARE HEREBY NOTIFIED THAT: (A) ANY DISCUSSION OF UNITED STATES FEDERAL TAX ISSUES IN THIS OFFERING MEMORANDUM (INCLUDING ANY ATTACHMENTS) IS NOT INTENDED OR WRITTEN TO BE USED, AND CANNOT BE USED, BY INVESTORS FOR THE PURPOSE OF AVOIDING PENALTIES THAT MAY BE IMPOSED ON INVESTORS UNDER THE INTERNAL REVENUE CODE; (B) SUCH DISCUSSION HAS BEEN WRITTEN IN CONNECTION WITH THE PROMOTION OR MARKETING OF THE TRANSACTIONS OR MATTERS ADDRESSED HEREIN; AND (C) INVESTORS SHOULD SEEK ADVICE BASED ON THEIR PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR. The following discussion is a general summary of certain U.S. federal income tax consequences of the purchase, ownership and disposition of Notes to a U.S. holder (as defined below) that holds its Notes as a capital asset (generally, property held for investment) and that purchases the Notes in the initial offering and at the “issue price” (as defined below). This summary is based on the Internal Revenue Code of 1986, as amended, Treasury regulations promulgated thereunder, rulings, judicial decisions and administrative pronouncements, all as in effect on the date hereof, and all of which are subject to change or changes in interpretation, possibly with retroactive effect.

208 This summary does not address all aspects of U.S. federal income taxation that may apply to holders that are subject to special tax rules, including U.S. expatriates, insurance companies, tax-exempt entities, banks, financial institutions, persons subject to the alternative minimum tax, dealers in securities or currencies, regulated investment companies, traders in securities that mark to market, persons holding their Notes as part of a straddle, hedging transaction or conversion transaction, or persons whose functional currency is not the U.S. dollar. These holders may be subject to U.S. federal income tax consequences different from those set forth below. If a partnership (including for this purpose any entity treated as a partnership for U.S. federal income tax purposes) holds Notes, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. A partner in a partnership that holds Notes is urged to consult its tax advisor regarding the specific tax consequences of the purchase, ownership and disposition of the Notes.

For purposes of this discussion, the term “U.S. holder” means a beneficial owner of Notes who is (a) a citizen or individual resident of the United States for U.S. federal income tax purposes, (b) a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States or any state thereof (including the District of Columbia), (c) an estate the income of which is subject to U.S. federal income taxation regardless of its source, or (d) a trust if a court within the United States can exercise primary supervision over the administration of the trust and one or more U.S. persons are authorized to control all substantial decisions of the trust.

The “issue price” of a Note is equal to the first price at which a substantial amount of the Notes is sold for money other than to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers.

U.S. holders should consult their tax advisors regarding the specific Dutch, German and U.S. federal, state and local tax consequences of purchasing, owning and disposing of Notes in light of their particular circumstances as well as any consequences arising under the laws of any other relevant taxing jurisdiction.

Payments of Interest It is anticipated that the Notes will not be issued with original issue discount for U.S. federal income tax purposes. In this case, payments of interest on a Note generally will be taxable to a U.S. holder as ordinary interest income at the time such payments are received or are accrued in accordance with the U.S. holder’s method of accounting for U.S. tax purposes.

Interest paid on a Note generally will constitute foreign-source income. For purposes of computing allowable foreign tax credits for U.S. tax purposes, interest generally will be treated as “passive category” income, or, in the case of certain U.S. holders, “general category” income. The rules relating to foreign tax credits are complex and U.S. holders should consult their own tax advisors regarding the application of the foreign tax credit limitations to their particular situation.

Sale or Other Disposition Upon the sale or other disposition of a Note, a U.S. holder generally will recognize capital gain or loss in an amount equal to the difference between the amount realized (other than amounts attributable to accrued and unpaid interest, which will be taxable as ordinary interest income in accordance with the U.S. holder’s method of tax accounting) and the U.S. holder’s adjusted tax basis in the Note (generally its cost less any principal payments previously received). Any gain or loss recognized upon the sale or other disposition of a Note by a U.S. holder generally will be U.S.-source capital gain or loss, and will be treated as long-term capital gain or loss if the Note has been held for more than one year at the time of the sale or other disposition. Capital gains recognized by an individual U.S. holder generally are subject to U.S. federal income taxation at preferential rates if certain minimum holding periods are met. The deductibility of capital losses for all taxpayers is subject to significant limitations.

209 Substitution of the Issuer The Guarantor or certain of its subsidiaries may, subject to certain restrictions, assume the obligations of the Issuer under the Notes without the consent of the holders. Such an assumption may in some circumstances be treated as a taxable exchange for U.S. federal income tax purposes. Holders should consult their own tax advisors regarding the U.S. federal, state, and local tax consequences of such an assumption.

U.S. Information Reporting and Backup Withholding Payments of interest on and proceeds from the sale or other disposition of the Notes may be subject to information reporting to the Internal Revenue Service and backup withholding at a current rate of 28%. Certain exempt recipients (such as corporations) are not subject to these information reporting requirements. Backup withholding will not apply to a holder who furnishes a correct taxpayer identification number or certificate of foreign status and makes any other required certification, or who is otherwise exempt from backup withholding. U.S. persons who are required to establish their exempt status generally must provide IRS Form W 9 (Request for Taxpayer Identification Number and Certification). Non-U.S. holders generally will not be subject to U.S. information reporting or backup withholding. However, these holders may be required to provide certification of non-U.S. person status (generally on IRS Form W-8BEN) in connection with payments received in the United States or through certain U.S.-related financial intermediaries. Backup withholding is not an additional tax. Amounts withheld as backup withholding may be credited against a holder’s U.S. federal income tax liability. A holder may obtain a refund of any excess amounts withheld under the backup withholding rules by timely filing the appropriate claim for refund with the Internal Revenue Service and furnishing any required information.

Netherlands Tax Considerations The following summary of certain Dutch taxation matters is based on the laws and practice in force as of the date of this offering memorandum and is subject to any changes in law and the interpretation and application thereof, which changes could be made with retroactive effect. The following summary does not purport to be a comprehensive description of all the tax considerations that may be relevant to a decision to acquire, hold or dispose of the Notes, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which (such as dealers in Notes) may be subject to special rules. This summary does not address the Dutch tax consequences for a holder of a Note who holds a substantial interest (“aanmerkelijk belang”) in the issuer. Generally speaking, a person holds a substantial interest in an entity, if he or she, alone or together with his or her partner (statutory defined term) or certain other related persons, directly or indirectly, holds (i) an interest of five per cent. or more of the total issued capital of the entity, or of five per cent. or more of the issued capital of a certain class of shares of the entity, (ii) rights to acquire, directly or indirectly, such interest or (iii) certain profit sharing rights in the entity. Save as otherwise indicated, this summary only addresses the position of investors who do not have any connection with the Netherlands other than the holding of the Notes. Investors are advised to consult their professional advisers as to the tax consequences of purchase, ownership and disposition of the Notes. For the purpose of this summary, it is assumed that E.ON International Finance B.V. is resident or deemed to be resident of The Netherlands for taxation purposes.

Withholding tax All payments by E.ON International Finance B.V. of interest and principal under the Notes can be made free of withholding or deduction for any taxes of whatsoever nature imposed, levied, withheld or assessed by The Netherlands or any political subdivision or taxing authority thereof or therein, unless the Notes qualify as debt as referred to in article 10, paragraph 1, sub d of the Dutch Corporate Tax Act 1969 (Wet op de vennootschapsbelasting 1969).

210 Taxes on Income and Capital Gains A holder of a Note who derives income from a Note or who realises a gain on the disposal or redemption of a Note will not be subject to Dutch taxation on such income or capital gain unless: (a) the holder is, or is deemed to be, resident in The Netherlands, or, where the holder is an individual, such holder has elected to be treated as a resident of The Netherlands; or (b) such income or gain is attributable to an enterprise or part thereof which is either effectively managed in The Netherlands or carried on through a permanent establishment (vaste inrichting) or a permanent representative (vaste vertegenwoordiger) in The Netherlands; or (c) the holder has, directly or indirectly, a substantial interest (aanmerkelijk belang) in E.ON International Finance B.V. as defined in the Dutch Income Tax Act 2001 (Wet inkomstenbelasting 2001) and, if the holder is not an individual, such interest does not form part of the arrests of an enterprise; or (d) the holder is an individual and such income or gain qualifies as income from activities that exceed normal active portfolio management in The Netherlands.

Gift, Estate or Inheritance Taxes Dutch gift, estate or inheritance taxes will not be levied on the occasion of the transfer of a Note by way of gift by, or on the death of, a holder, unless: (a) the holder is, or is deemed to be, resident in The Netherlands for the purpose of the relevant provisions; or (b) the transfer is construed as an inheritance or as a gift made by, or on behalf of, a person who, at the time of the gift or death, is, or is deemed to be, resident in The Netherlands for the purpose of the relevant provisions; or (c) such Note is attributable to an enterprise or part thereof, which is either effectively managed in The Netherlands or carried on through a permanent establishment or a permanent representative in The Netherlands.

Value Added Tax There is no Dutch value added tax payable in respect of payments in consideration for the issue of the Notes or in respect of the payment of interest or principal under the Notes or the transfer of the Notes.

Other Taxes and Duties There is no Dutch registration tax, stamp duty or any other similar tax or duty payable in The Netherlands in respect of or in connection with the execution, delivery and/or enforcement by legal proceedings (including any foreign judgment in the courts of The Netherlands) of the Notes or the performance of the obligations of the E.ON International Finance B.V. under the Notes.

Residence A holder of a Note will not be treated as a resident of The Netherlands by reason only of the holding of a Note or the execution, performance, delivery and/or enforcement of the Notes.

211 PLAN OF DISTRIBUTION The Issuer intends to offer the Notes through the Initial Purchasers. Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. and J.P. Morgan Securities Inc. are acting as representatives for the Initial Purchasers named below. Subject to the terms and conditions contained in a purchase agreement dated April 15, 2008 between the Issuer, the Guarantor and the Initial Purchasers (the “Purchase Agreement”), the Issuer has agreed to sell to the Initial Purchasers, and the Initial Purchasers have severally agreed to purchase from the Issuer, the principal amount of each series of Notes listed opposite their names below: Initial Purchasers Principal Amount 2018 Notes 2038 Notes Banc of America Securities LLC ...... $ 450,000,000 $ 225,000,000 Deutsche Bank Securities Inc...... $ 450,000,000 $ 225,000,000 Goldman, Sachs & Co...... $ 450,000,000 $ 225,000,000 J.P. Morgan Securities Inc...... $ 450,000,000 $ 225,000,000 Greenwich Capital Markets, Inc...... $ 66,666,000 $ 50,000,000 Lehman Brothers Inc...... $ 66,667,000 $ 50,000,000 Merrill Lynch, Pierce, Fenner & Smith Incorporated ...... $ 66,666,000 — Total ...... $2,000,000,000 $1,000,000,000

The Initial Purchasers have agreed, severally and not jointly, to purchase all of the Notes of a series being sold pursuant to the Purchase Agreement if any of such Notes are purchased. If an Initial Purchaser defaults, the Purchase Agreement provides that the purchase commitments of the non-defaulting Initial Purchasers may be increased or the Purchase Agreement may be terminated. The Initial Purchasers have advised the Issuer that they (or certain of their affiliates acting as selling agents) propose initially to offer the Notes for resale at the prices listed on the cover page of this offering memorandum within the United States to Qualified Institutional Buyers as defined in, and in reliance upon Rule 144A and outside the United States to non-U.S. persons in transactions exempt from registration under Regulation S. See “Transfer Restrictions.” After the initial offering of the Notes, the offering price and other selling terms may from time to time be varied by the Initial Purchasers. The Issuer and the Guarantor have agreed to indemnify the Initial Purchasers against certain liabilities, including certain liabilities under the Securities Act. The Initial Purchasers are offering the Notes, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the Notes, and other conditions contained in the Purchase Agreement, such as the receipt by the Initial Purchasers of officer’s certificates and legal opinions. The Initial Purchasers reserve the right to withdraw, cancel or modify offers to investors and to reject orders in whole or in part. After the Notes are released for sale, the Initial Purchasers may change the offering prices and other selling terms without notice. Each series of the Notes will be a new issue of securities with no established trading market and will not be listed on any exchange. We cannot assure you that the prices at which the Notes will be sold in the market after this offering will not be lower than the initial offering prices listed on the cover page of this offering memorandum. The Initial Purchasers are not obligated to make a market in any series of the Notes and accordingly, no assurance can be given as to the liquidity of, or trading markets for, the Notes. In connection with the offering, Banc of America Securities LLC (or any person acting for it), acting for the benefit of the Initial Purchasers, may purchase and sell Notes in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves sales of Notes of any series in excess of the principal amount of such Notes to be purchased in the offering, which creates a short position. Syndicate covering transactions involve purchases of the Notes in the open market after the distribution has been completed in order to cover short positions created. Stabilizing transactions consist of certain bids or purchases of Notes made for the purpose of pegging, fixing or maintaining the prices of the Notes.

212 Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. or J.P. Morgan Securities Inc. (or any person acting for either of them), acting for the benefit of the Initial Purchasers, may impose penalty bids. Penalty bids permit Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. or J.P. Morgan Securities Inc. (or any person acting for either of them) to reclaim selling concessions from a syndicate member when it, in covering short positions or making stabilizing purchases, repurchases Notes originally sold by that syndicate member. Any of these activities may cause the prices of the Notes to be higher than the price that otherwise would exist in the open market in the absence of such transactions. These transactions may be effected in any over-the-counter market, and, if commenced, may be discontinued at any time. We expect that delivery of the Notes will be made against payment therefor on or about the closing date specified on the cover page of this offering memorandum (the “Settlement Date”), which will be the fifth New York business day following the date of pricing of the Notes of this offering (this settlement cycle being referred to as “T+5”). Under Rule 15c6-1 of the Securities Exchange Act of 1934, trades in the secondary market generally are required to settle in three New York business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade Notes prior to the third business day preceding the Settlement Date will be required, by virtue of the fact that the Notes initially will settle in T+5, to specify an alternative settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of Notes who wish to trade Notes prior to the third business day preceding the Settlement Date should consult their own advisor.

Selling Restrictions General No action has been or will be taken in any jurisdiction that would permit a public offering of the Notes, or the possession, circulation or distribution of this offering memorandum, or any amendment or supplement to this offering memorandum, or any other offering or publicity material relating to the Notes, in any country or jurisdiction where, or in any circumstances in which, action for that purpose is required. Accordingly, the Notes may not be offered or sold, directly or indirectly, and neither this offering memorandum nor any other offering material or advertisements in connection with the Notes may be distributed or published, in or from any country or jurisdiction except under circumstances that will result in compliance with applicable laws and regulations. Each Initial Purchaser has agreed that it will, to the best of its knowledge, comply with all relevant laws, regulations and directives in each jurisdiction in which it purchases, offers, sells or delivers Notes or has in its possession or distributes this offering memorandum and none of the Issuer, the Guarantor or any other initial purchaser shall have any responsibility therefor.

United States The Initial Purchasers propose to offer the Notes for resale in transactions not requiring registration under the Securities Act or applicable state securities laws, including sales pursuant to Rule 144A. The Initial Purchasers will not offer or sell the Notes except: • to persons they reasonably believe to be Qualified Institutional Buyers; or • pursuant to offers and sales to non-U.S. persons that occur in offshore transactions outside the United States within the meaning of Regulation S. In addition, until 40 days after the later of the commencement of this offering and the closing date of this offering, an offer or sale of the Notes within the United States by a dealer (whether or not participating in this offering) may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than in accordance with Rule 144A or another available exemption from the registration requirements thereof. Notes sold pursuant to Regulation S may not be offered or resold in the United States or to U.S. persons (as defined in Regulation S), except under an exemption from the registration requirements of the Securities Act or under a registration statement declared effective under the Securities Act.

213 European Economic Area In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each Initial Purchaser has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), it has not made and will not make an offer of Notes to the public in that Relevant Member State, except that it may, with effect from and including the Relevant Implementation Date, make an offer of Notes to the public in that Relevant Member State: • to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities; • to any legal entity which has two or more of: (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43,000,000; and (iii) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; • to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the Initial Purchasers for any such offer; or • in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of Notes shall require the Issuer or any of the Initial Purchasers to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of Notes to the public” in relation to any Notes in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe to the Notes, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

United Kingdom Each Initial Purchaser has represented and agreed that: • it has only communicated or caused to be communicated and will only communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of section 21 of the Financial Services and Markets Act 2000, or the FSMA) received by it in connection with the issue or sale of any Notes in circumstances in which section 21(1) of the FSMA does not apply to the Issuer or the Guarantor; and • it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the Notes in, from or otherwise involving the United Kingdom.

Hong Kong Each Initial Purchaser has represented and agreed that: • it has not offered or sold and will not offer or sell in Hong Kong, by means of any document, any Notes other than (i) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made under that ordinance; or (ii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within the meaning of that ordinance; and • it has not issued or had in its possession for the purposes of issue, and will not issue or have in its possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to the Notes, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to Notes which are or are intended to be disposed of only to persons

214 outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that ordinance.

Japan The Notes have not been and will not be registered under the Securities and Exchange Law of Japan (the “Securities and Exchange Law”) and each Initial Purchaser has agreed that it will not offer or sell any Notes, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any personresident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

Singapore This offering memorandum has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this offering memorandum and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the Notes may not be circulated or distributed, nor may the notes be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the Notes are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the notes under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

Other Relationships Some of the Initial Purchasers and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with the Guarantor and its subsidiaries and affiliates, including the Issuer.

215 TRANSFER RESTRICTIONS

Offers and Sales The Notes have not been and will not be registered under the Securities Act and may not be offered or sold in the United States except pursuant to an effective registration statement or in a transaction not subject to the registration requirements under the Securities Act or in accordance with an applicable exemption from the registration requirements thereof. Accordingly, the Notes are being offered and sold hereunder only: • inside the United States or to U.S. persons (as defined under Regulation S), to Qualified Institutional Buyers (“QIBs” and each, a “QIB”) pursuant to Rule 144A; and • outside the United States to non-U.S. persons, or for the account or benefit of non-U.S. persons, in offshore transactions in reliance upon Regulation S.

Any offer or sale of the Notes in the United States in reliance on Rule 144A or another exemption from the registration requirements of the Securities Act will be made by broker-dealers who are registered as such under the Exchange Act.

Until the expiration of 40 days after the later of the commencement of the offering of the Notes and the original issue or sale date of the Notes, an offer or sale of the Notes within the United States by a dealer may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than pursuant to an exemption from registration under the Securities Act.

Rule 144A Global Notes Each purchaser of Notes within the United States will be deemed by its acceptance of the Notes to have represented and agreed on its behalf and on behalf of any investor accounts for which it is purchasing the Notes, that neither the Issuer nor the Guarantor or the Initial Purchasers, nor any person acting on their behalf, has made any representation to it with respect to the offering or sale of any Notes, other than the information contained in this offering memorandum, which offering memorandum has been delivered to it and upon which it is solely relying in making its investment decision with respect to the Notes, has had access to such financial and other information concerning E.ON and the Notes as it has deemed necessary in connection with its decision to purchase any of the Notes, and that: (i) the purchaser is not an affiliate of E.ON or a person acting on behalf of E.ON or on behalf of such affiliate; and it is not in the business of buying and selling securities or, if it is in such business, it did not acquire the Notes from E.ON or an affiliate thereof in the initial distribution of the Notes; (ii) the purchaser acknowledges that the Notes have not been and will not be registered under the Securities Act or with any securities regulatory authority of any state of the United States and are subject to significant restrictions on transfer; (iii) the purchaser (i) is a QIB, (ii) is aware that the sale to it is being made in reliance on Rule 144A or another exemption from, or in a transaction not subject to, the registration requirements of the Securities Act, and (iii) is acquiring such Notes for its own account or for the account of a QIB, in each case for investment and not with a view to, or for offer or sale in connection with, any resale or distribution of the Notes in violation of the Securities Act or any state securities laws; (iv) the subscriber or purchaser is aware that the Notes are being offered in the United States in a transaction not involving any public offering in the United States within the meaning of the Securities Act; (v) if, prior to the date that is one year after the later of the date (the “Resale Restriction Termination Date”) of the commencement of sales of the Notes and the last date on which the Notes were acquired from the Issuer or any of the Issuer’s affiliates in the offering the purchaser decides to offer, resell, pledge or otherwise transfer such Notes, such Notes may be offered, sold, pledged or otherwise transferred only (i) to

216 a person whom the beneficial owner and/or any person acting on its behalf reasonably believes is a QIB in a transaction meeting the requirements of Rule 144A, (ii) in accordance with Regulation S, (iii) in accordance with Rule 144 (if available), (iv) in accordance with an effective registration statement under the Securities Act, or (v) pursuant to any other available exemption from the registration requirements of the Securities Act in each case in accordance with any applicable securities laws of any state of the United States or any other jurisdiction and agrees to give any subsequent purchaser of such Notes notice of any restrictions on the transfer thereof; (vi) the Notes have not been offered to it by means of any general solicitation or general advertising; (vii) the Notes are “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act and no representation is made as to the availability of the exemption provided by Rule 144 under the Securities Act for resales of any such Notes; (viii) The Notes, unless otherwise determined by the Issuer in accordance with applicable law, will bear a legend to the following effect: THE NOTES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY STATE SECURITIES LAWS. OWNERSHIP INTERESTS IN THE NOTES MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED (I) WITHIN THE UNITED STATES TO, OR FOR THE ACCOUNT OR BENEFIT OF, PERSONS OTHER THAN “QUALIFIED INSTITUTIONAL BUYERS” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN TRANSACTIONS EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND (II) OUTSIDE THE UNITED STATES OTHER THAN TO PERSONS WHO ARE NOT U.S. PERSONS IN OFFSHORE TRANSACTIONS EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT PURSUANT TO RULE 903 OR RULE 904 OF REGULATION S THEREOF. EACH PERSON ACQUIRING AN OWNERSHIP INTEREST IN THE NOTES EVIDENCED HEREBY (1) SHALL BE DEEMED TO REPRESENT AND WARRANT THAT IT IS EITHER (A) A “QUALIFIED INSTITUTIONAL BUYER” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) OR (B) IS NOT A U.S. PERSON (AS DEFINED IN REGULATION S) AND IS OUTSIDE THE UNITED STATES; (2) AGREES THAT IT WILL NOT RESELL OR OTHERWISE TRANSFER THE NOTE EVIDENCED HEREBY EXCEPT IN ACCORDANCE WITH THE FOREGOING RESTRICTIONS, AND IN ANY CASE IN COMPLIANCE WITH ALL APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES AND ANY OTHER APPLICABLE JURISDICTION; (3) PRIOR TO SUCH TRANSFER, AGREES THAT IT WILL FURNISH TO HSBC BANK USA, N.A., AS REGISTRAR (OR A SUCCESSOR REGISTRAR, AS APPLICABLE), SUCH CERTIFICATIONS, LEGAL OPINIONS OR OTHER INFORMATION AS THE REGISTRAR MAY REASONABLY REQUIRE TO CONFIRM THAT SUCH TRANSFER IS BEING MADE PURSUANT TO AN EXEMPTION FROM, OR IN A TRANSACTION NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND (4) AGREES THAT IT WILL DELIVER TO EACH PERSON TO WHOM THE NOTE EVIDENCED HEREBY IS TRANSFERRED A NOTICE SUBSTANTIALLY TO THE EFFECT OF THIS LEGEND. AS USED HEREIN, THE TERMS “UNITED STATES”, “U.S. PERSON” AND “OFFSHORE TRANSACTION” HAVE THE MEANINGS GIVEN TO THEM BY REGULATION S UNDER THE SECURITIES ACT; and (ix) the Company shall not recognize any offer, sale, pledge or other transfer of the Notes made other than in compliance with the above-stated restrictions. Terms defined in Rule 144A shall have the same meaning when used in the foregoing sections (i)-(ix). Each purchaser acknowledges that the Issuer, the Guarantor and the Initial Purchasers will rely upon the truth and accuracy of the foregoing acknowledgements, representations and agreements, and agrees that if any of the acknowledgements, representations or warranties deemed to have been made by such purchaser by its purchase of Notes are no longer accurate, it shall promptly notify the Issuer, the Guarantor and the Initial Purchasers; if they are acquiring any Notes offered hereby as a fiduciary or agent for one or more investor

217 accounts, each purchaser represents that they have sole investment discretion with respect to each such account and full power to make the foregoing acknowledgements, representations and agreements on behalf of each such account.

Each purchaser of the Notes will be deemed by its acceptance of the Notes to have represented and agreed that it is purchasing the Notes for its own account, or for one or more investor accounts for which it is acting as a fiduciary or agent, in each case for investment, and not with a view to, or for offer or sale in connection with, any distribution thereof in violation of the Securities Act or any state securities laws, subject to any requirement of law that the disposition of its property or the property of such investor account or accounts be at all times within its or their control and subject to its or their ability to resell such Notes pursuant to Rule 144A, Regulation S or any other exemption from registration available under the Securities Act.

The Issuer and the Guarantor recognize that none of DTC, Euroclear nor Clearstream in any way undertakes to, and none of DTC, Euroclear nor Clearstream have any responsibility to, monitor or ascertain the compliance of any transactions in the Notes with any exemptions from registration under the Securities Act or any other state or federal securities law.

Regulation S Global Notes

Each purchaser of Notes outside the United States pursuant to Regulation S will be deemed by its acceptance of the Notes to have represented and agreed, on its behalf and on behalf of any investor accounts for which it is purchasing the Notes, that neither the Issuer nor the Guarantor or the Initial Purchasers, nor any person acting on their behalf, has made any representation to it with respect to the offering or sale of any Notes, other than the information contained in this offering memorandum, which offering memorandum has been delivered to it and upon which it is solely relying in making its investment decision with respect to the Notes, has had access to such financial and other information concerning the E.ON and the Notes as it has deemed necessary in connection with its decision to purchase any of the Notes, and that:

(i) the purchaser understands and acknowledges that the Notes have not been and will not be registered under the Securities Act, or with any securities regulatory authority of any state of the United States, and may not be offered, sold or otherwise transferred except in compliance with the registration requirements of the Securities Act or any other applicable securities law, pursuant to an exemption therefrom or in any transaction not subject thereto;

(ii) the purchaser, and the person, if any, for whose account or benefit the purchaser is acquiring the Notes, is not a U.S. person and is acquiring the Notes in an “offshore transaction” meeting the requirements of Regulation S and was located outside the United States at the time the buy order for the Shares was originated and continues to be outside of the United States and has not purchased the Notes for the account or benefit of any U.S. person or entered into any arrangement for the transfer of the Notes to any U.S. erson;

(iii) the purchaser is aware of the restrictions on the offer and sale of the Notes pursuant to Regulation S described in this offering memorandum and agrees to give any subsequent purchaser of such Notes notice of any restrictions on the transfer thereof;

(iv) the Notes have not been offered to it by means of any “directed selling efforts” as defined in Regulation S; and

(v) E.ON shall not recognize any offer, sale, pledge or other transfer of the Notes made other than in compliance with the above-stated restrictions.

Terms defined in Regulation S shall have the same meaning when used in the foregoing sections (i)-(v).

218 Unless we determine otherwise in compliance with applicable law, the Regulation S notes will bear the following restrictive legend and may not be transferred otherwise than in accordance with the transfer restrictions set forth in such legend: THE NOTES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY STATE SECURITIES LAWS. OWNERSHIP INTERESTS IN THE NOTES MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED (I) WITHIN THE UNITED STATES TO, OR FOR THE ACCOUNT OR BENEFIT OF, PERSONS OTHER THAN “QUALIFIED INSTITUTIONAL BUYERS” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN TRANSACTIONS EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT, PROVIDED THAT SUCH TRANSFER DOES NOT OCCUR PRIOR TO 40 DAYS AFTER THE LATER OF THE ANNOUNCEMENT OF THE OFFERING OF THE NOTES AND THE ISSUE DATE FOR THE NOTES OR (II) OUTSIDE THE UNITED STATES OTHER THAN TO PERSONS WHO ARE NOT U.S. PERSONS IN OFFSHORE TRANSACTIONS EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT PURSUANT TO RULE 903 OR RULE 904 OF REGULATION S THEREOF. EACH PERSON ACQUIRING AN OWNERSHIP INTEREST IN THE NOTES EVIDENCED HEREBY AS PART OF THE INITIAL DISTRIBUTION SHALL BE DEEMED TO REPRESENT AND WARRANT THAT IT IS (A) NOT A U.S. PERSON AND (B) ACQUIRING THE NOTES IN AN “OFFSHORE TRANSACTION” AS DEFINED IN RULE 902(H) UNDER THE SECURITIES ACT OUTSIDE THE UNITED STATES. EACH PERSON ACQUIRING AN OWNERSHIP INTEREST IN THE NOTES EVIDENCED HEREBY (1) AGREES THAT IT WILL NOT RESELL OR OTHERWISE TRANSFER THE NOTES EVIDENCED HEREBY EXCEPT IN ACCORDANCE WITH THE FOREGOING RESTRICTIONS IN I AND II ABOVE, AND IN ANY CASE IN COMPLIANCE WITH ALL APPLICABLE JURISDICTION AND (2) AGREES, PRIOR TO SUCH TRANSFER, TO FURNISH TO HSBC BANK USA, N.A., AS REGISTRAR (OR A SUCCESSOR REGISTRAR, AS APPLICABLE), SUCH CERTIFICATIONS, LEGAL OPINIONS OR OTHER INFORMATION AS THE REGISTRAR MAY REASONABLY REQUIRE TO CONFIRM THAT SUCH TRANSFER IS BEING MADE PURSUANT TO AN EXEMPTION FROM, OR IN A TRANSACTION NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT. AS USED HEREIN, THE TERMS “UNITED STATES”, “U.S. PERSON” AND “OFFSHORE TRANSACTION” HAVE THE MEANINGS GIVEN TO THEM BY REGULATION S UNDER THE SECURITIES ACT.

219 LEGAL MATTERS

Certain legal matters in connection with the offering of the Notes will be passed upon for us by Shearman & Sterling LLP, German and U.S. counsel to us and the Issuer, and by Clifford Chance LLP, Dutch counsel to us and the Issuer. Certain legal matters will be passed upon for the Initial Purchasers by Cleary Gottlieb Steen & Hamilton LLP, U.S. and German counsel to the Initial Purchasers.

220 INDEPENDENT ACCOUNTANTS

The consolidated financial statements of E.ON AG and its subsidiaries as of December 31, 2007 prepared in accordance with IFRS as adopted by the European Union, which are included herein, have been audited by PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprüfungsgesellschaft (“PwC”), independent accountants, as stated in their report appearing herein.

The consolidated financial statements of E.ON AG and the subsidiaries as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006, prepared in accordance with U.S. GAAP incorporated by reference in this offering memorandum have been audited by PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprufungsgesellschaft, independent registered public accounting firm, as stated in their report.

The audit report of PwC for E.ON AG as of December 31, 2007 refers to a group management report that has not been included in the offering memorandum. The examination of and the audit report upon such group management report are required under German generally accepted auditing standards. This examination was not made in accordance with generally accepted auditing or attestation standards in the United States. Accordingly, PwC does not express any opinion on this information or on the consolidated financial statements prepared in accordance with IFRS as adopted by the European Union included in this offering memorandum, in each case in accordance with U.S. generally accepted auditing standards or U.S. attestation standards.

221 LIMITATIONS ON ENFORCEMENT OF U.S. LAWS AGAINST THE GUARANTOR, THE ISSUER, THEIR MANAGEMENT, AND OTHERS

The Guarantor is a stock corporation (Aktiengesellschaft) organized under the laws of Germany, and the Issuer is a wholly-owned subsidiary of the Guarantor organized under the laws of The Netherlands. None of the members of the managing board (Vorstand) and the supervisory board (Aufsichtsrat) of the Guarantor and its independent auditors named in this offering memorandum and none of the members of the board of managing directors (bestuur) of the Issuer are residents of the U.S. All or a substantial portion of the assets of these individuals and of the Guarantor and the Issuer are located outside the U.S. As a result, it may not be possible for you to effect service of process within the U.S. upon these individuals or upon the Guarantor or the Issuer or to enforce judgments obtained in U.S. courts based on the civil liability provisions of the U.S. securities laws against these individuals, the Guarantor or the Issuer outside the U.S. Awards of punitive damages in actions brought in the U.S. or elsewhere may be unenforceable in Germany and also in The Netherlands. In addition, actions brought in a German court against the Guarantor or the members of its managing board to enforce liabilities based on U.S. federal securities laws may be subject to certain restrictions; in particular, a German court may not award punitive damages.

The U.S. and Germany currently do not have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Therefore, a final judgment for the payment of money rendered by any federal or state court in the U.S. based on civil liability, whether or not predicated solely upon U.S. federal or state securities laws, would not be automatically enforceable in Germany also. A final judgment by a U.S. federal or state court, however, may be recognized and enforced in Germany in an action before a court of competent jurisdiction in accordance with the proceedings set forth by the German Code of Civil Procedure (Zivilprozessordnung). In such an action, a German court will generally not reinvestigate the merits of the original matter decided by a U.S. court, except as noted below. The recognition and enforcement of the U.S. judgment by a German court is conditional upon a number of factors, including the following: • the judgment being final under U.S. law; • the U.S. courts having had jurisdiction over the original proceeding in accordance with German law; • the defendant having had the chance to defend herself or himself against an unduly or untimely served complaint; • the judgment of the U.S. court being compatible with the judgment rendered by a German court or a prior judgment of a foreign court to be recognized; • the procedure underlying the judgment of the U.S. court being compatible with a procedure in Germany that has been pending prior thereto; • the results of a recognition of the judgment of the U.S. court being compatible with the substantial principles of German law, in particular with the civil liberties (Grundrechte) guaranteed by virtue of the German Constitution (Grundgesetz); and • the guarantee of reciprocity.

Subject to the foregoing, purchasers of securities may be able to enforce judgments in civil and commercial matters obtained from U.S. federal or state courts in Germany. We cannot, however, assure you that attempts to enforce judgments in Germany will be successful.

The U.S. and The Netherlands currently do not have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Therefore, a final judgment for the payment of money rendered by any federal or state court in the U.S. based on civil liability, whether or not predicated solely upon U.S. federal or state securities laws, would not be automatically enforceable in The

222 Netherlands and new proceedings on the merits must be initiated before a competent Dutch court. However, if the party in whose favor such final judgment is rendered brings a new suit in a competent court in The Netherlands such party may submit to a Dutch court the final judgment that has been rendered in the U.S. and such court will have discretion to attach such weight to its judgment as it deems appropriate. According to current practice, however, based upon case law, Dutch courts will generally render a judgment in accordance with the U.S. judgment, if and to the extent that the following conditions are met: • the U.S. court rendering the judgment had jurisdiction over the subject matter of the litigation on internationally acceptable grounds (e.g., if the parties have agreed, for example in a written contract, to submit their disputes to the foreign court) and has conducted the proceedings in accordance with generally accepted principles of fair trials (e.g., after proper service of process, giving the defendant sufficient time to prepare for the litigation); • the U.S. judgment is final and definite; and • such recognition is not in conflict with an existing Dutch judgment or with Dutch public policy (i.e. a fundamental principle of Dutch law).

223 GENERAL INFORMATION ABOUT THE ISSUER The Issuer was incorporated in Amsterdam on November 14, 1983 under the name, VEBA International Finance B.V., under the laws of The Netherlands as a private limited liability company (besloten vennootschap met beperkte aansprakelijkheid) with an unlimited corporate duration. VEBA International Finance B.V. was renamed E.ON International Finance B.V. on September 26, 2000. It has its statutory seat in Amsterdam. Its registered office is at Capelseweg 400, 3068 AX Rotterdam, The Netherlands (telephone: +31 10 289 50 89), where it is registered in the commercial register of the Chamber of Commerce and Industry under number 33174429.

Business Overview The principal activity of the Issuer is the financing of E.ON Group entities.

Ownership The Issuer is a direct wholly-owned subsidiary of E.ON AG.

Trend Information There has been no material adverse change in the prospects of the Issuer since the date of its last published audited financial statements (December 31, 2007). No developments are currently foreseen that are reasonably likely to have a material effect on the Issuer’s prospects.

Administrative, Management and Supervisory Bodies Managing Board At present, the managing board consists of the following members: • Marcus Andreas Stefan Bokelmann, Rotterdam, Managing Director of E.ON Benelux Holding B.V. • Johannes Casparus Petrus Schoenmakers, Schiedam, General Council of E.ON Benelux Holding B. V. • Jan Trapman, Sliedrecht, Manager Treasury Controlling of E.ON Benelux N. V.

Supervisory Board At present, the supervisory board consists of the following members: • Dr. Verena Volpert, Germany, Senior Vice President Finance of E.ON AG • Graham Wood, London, UK • David Beynon, London, UK, Tax advisor of E.ON AG The members of the managing and the supervisory boards can be contacted at the Issuer’s business address: Capelseweg 400, 3068 AX Rotterdam, The Netherlands. None of the above members of the managing board and the supervisory board have declared any potential conflict of interest between any duties to the Issuer and their private interests or other duties.

Board Practices The Issuer has not instituted a separate audit committee. The Issuer, as a privately held company, is not subject to public corporate governance standards.

Legal and arbitration proceedings As of the date of this offering memorandum, the Issuer is, not nor has it been during the past two fiscal years, engaged in any governmental, legal or arbitration proceedings which may have or have had during such period a significant effect on its or the E.ON Group’s financial position or profitability, nor as far as the Issuer is aware, are any such governmental, legal or arbitration proceedings pending or threatened.

224 INDEX TO FINANCIAL STATEMENTS

Page Independent Auditors Report ...... F-2 Consolidated Statements of Income ...... F-3 Consolidated Balance Sheets—Assets ...... F-4 Consolidated Balance Sheets—Equity and Liabilities ...... F-5 Consolidated statements of Recognized Income and Expenses ...... F-6 Consolidated Statements of Cash Flows ...... F-7 Statements of Changes in Equity ...... F-8 Notes to the Consolidated Financial Statements ...... F-10

F-1 The auditor’s report issued in accordance with Section 322 German Commercial Code and in German language relates to the IFRS Consolidated Financial Statements of E.ON AG for the 2007 fiscal year which follow, as well as to the group management report of E.ON AG prepared in the German language for the 2007 fiscal year. The group management report is not reprinted in this offering memorandum.

INDEPENDENT AUDITOR’S REPORT

We have audited the Consolidated Financial Statements prepared by E.ON AG, Düsseldorf, Germany, comprising the balance sheet, the income statement, the statement of recognized income and expenses, the cash flow statement and the notes to the financial statements, together with the Group Management Report, which has been combined with the management report for E.ON AG, for the fiscal year from January 1 through December 31, 2007. The preparation of the Consolidated Financial Statements and of the Combined Management Report in accordance with the IFRS applicable to financial reporting as adopted by the EU and in accordance with the additional requirements pursuant to Article 315a (1) of the German Commercial Code (HGB) is the responsibility of the Company’s Board of Management. Our responsibility is to express an opinion on the Consolidated Financial Statements and on the Combined Management Report based on our audit.

We conducted our audit of the Consolidated Financial Statements in accordance with Article 317 HGB and the German generally accepted standards for the audit of financial statements promulgated by the Institut der Wirtschaftsprüfer (Institute of Public Auditors in Germany) (IDW), with additional consideration given to the International Standards on Auditing (ISA). Those standards require that we plan and perform the audit in such a way as to ensure that misstatements materially affecting the presentation of the net assets, financial position and results of operations in the Consolidated Financial Statements in accordance with the applicable financial reporting framework and in the Group Management Report are detected with reasonable assurance. Knowledge of the business activities and the economic and legal environment of the Group and expectations as to possible misstatements are taken into account in the determination of audit procedures. The effectiveness of the accounting-related internal control system and the evidence supporting the disclosures in the Consolidated Financial Statements and the Group Management Report are examined primarily on a test basis within the framework of the audit. The audit includes assessing the annual financial statements of those entities included in consolidation, the determination of entities to be included in consolidation, the accounting and consolidation principles used and significant estimates made by the Board of Management, as well as evaluating the overall presentation of the Consolidated Financial Statements and Group Management Report. We believe that our audit provides a reasonable basis for our opinion.

Our audit has not led to any reservations.

In our opinion, based on the findings of our audit, the Consolidated Financial Statements are in compliance with the IFRS applicable to financial reporting as adopted by the EU and with the additional requirements pursuant to Article 315a (1) HGB, and give a true and fair view of the net assets, financial position and results of operations of the Group in accordance with these requirements. The Combined Group Management Report is consistent with the Consolidated Financial Statements and, as a whole, provides an appropriate view of the Group’s position and appropriately presents the opportunities and risks of future development.

Düsseldorf, February 20, 2008

PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprüfungsgesellschaft

Dr. Norbert Vogelpoth Dr. Norbert Schwieters Wirtschaftsprüfer Wirtschaftsprüfer (German Public Auditor) (German Public Auditor)

F-2 E.ON AG AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME

€ in millions Notes 2007 2006 Sales including electricity and energy taxes ...... 70,761 67,653 Electricity and energy taxes ...... (2,030) (3,562) Sales ...... (5) 68,731 64,091 Changes in inventories (finished goods and work in progress) ...... 22 8 Own work capitalized ...... (6) 517 395 Other operating income ...... (7) 7,776 7,914 Cost of materials ...... (8) (50,223) (46,708) Personnel costs ...... (11) (4,597) (4,529) Depreciation, amortization and impairment charges ...... (3,194) (3,670) Other operating expenses ...... (7) (9,724) (11,907) Income/Loss (–) from companies accounted for under the equity method ...... 1,147 748 Income/Loss (–) from continuing operations before financial results and income taxes ...... (33) 10,455 6,342 Financial results ...... (9) (772) (995) Income from equity investments ...... 179 50 Income from other securities, interest and similar income ...... 1,035 1,169 Interest and similar expenses ...... (1,986) (2,214) Income taxes ...... (10) (2,289) (40) Income/Loss (–) from continuing operations ...... 7,394 5,307 Income/Loss (–) from discontinued operations, net ...... (4) 330 775 Net income ...... 7,724 6,082 Attributable to shareholders of E.ON AG ...... 7,204 5,586 Attributable to minority interests ...... 520 496 in € Earnings per share (attributable to shareholders of E.ON AG)—basic and diluted ...... (13) from continuing operations ...... 10.55 7.31 from discontinued operations ...... 0.51 1.16 from net income ...... 11.06 8.47

F-3 E.ON AG AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS—ASSETS

December 31 January 1 € in millions Notes 2007 2006 2006 Goodwill ...... (14a) 16,761 15,320 15,494 Intangible assets ...... (14a) 4,284 3,894 4,207 Property, plant and equipment ...... (14b) 48,552 42,484 41,067 Companies accounted for under the equity method ...... (15) 8,411 7,770 9,507 Other financial assets ...... (15) 21,478 20,679 16,544 Equity investments ...... 14,583 13,533 10,073 Non-current securities ...... 6,895 7,146 6,471 Financial receivables and other financial assets ...... (17) 2,449 2,631 3,268 Operating receivables and other operating assets ...... (17) 680 373 1,736 Income tax assets ...... 2,034 2,090 1 Deferred tax assets ...... (10) 1,155 1,247 2,108 Non-current assets ...... 105,804 96,488 93,932 Inventories ...... (16) 3,811 4,199 2,587 Financial receivables and other financial assets ...... (17) 1,515 1,477 1,090 Trade receivables and other operating assets ...... (17) 17,973 18,057 17,088 Income tax assets ...... 539 554 874 Liquid funds ...... (18) 7,075 6,189 9,901 Securities and fixed-term deposits ...... 3,888 4,448 5,455 Restricted cash ...... 300 587 98 Cash and cash equivalents ...... 2,887 1,154 4,348 Assets held for sale ...... (4) 577 611 682 Current assets ...... 31,490 31,087 32,222 Total assets ...... 137,294 127,575 126,154

F-4 E.ON AG AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS—EQUITY AND LIABILITIES

December 31 January 1 € in millions Notes 2007 2006 2006 Capital stock ...... (19) 1,734 1,799 1,799 Additional paid-in capital ...... (20) 11,825 11,760 11,749 Retained earnings ...... (21) 26,828 24,350 22,910 Accumulated other comprehensive income ...... (22) 10,656 11,033 8,150 Treasury shares ...... (19) (616) (230) (256) Reclassification related to put options on treasury shares ...... (19) (1,053) — — Equity attributable to shareholders of E.ON AG ...... 49,374 48,712 44,352 Minority interests (before reclassification) ...... 6,281 4,994 4,747 Reclassification related to put options ...... (26) (525) (2,461) (3,130) Minority interests ...... (23) 5,756 2,533 1,617 Equity ...... 55,130 51,245 45,969 Financial liabilities ...... (26) 15,915 10,029 10,985 Operating liabilities ...... (26) 5,432 5,422 5,666 Income taxes ...... 2,537 2,333 1,134 Provisions for pensions and similar obligations ...... (24) 2,890 3,962 9,768 Miscellaneous provisions ...... (25) 18,073 18,138 18,009 Deferred tax liabilities ...... (10) 7,555 7,063 7,625 Non-current liabilities ...... 52,402 46,947 53,187 Financial liabilities ...... (26) 5,549 3,443 3,455 Trade payables and other operating liabilities ...... (26) 18,254 19,578 18,296 Income taxes ...... 1,354 1,753 1,859 Miscellaneous provisions ...... (25) 3,992 3,994 2,552 Liabilities associated with assets held for sale ...... (4) 613 615 836 Current liabilities ...... 29,762 29,383 26,998 Total equity and liabilities ...... 137,294 127,575 126,154

F-5 E.ON AG AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RECOGNIZED INCOME AND EXPENSES

€ in millions 2007 2006 Net income ...... 7,724 6,082 Cash flow hedges ...... (81) (276) Unrealized changes ...... (82) (302) Reclassification adjustments recognized in income ...... 126 Available-for-sale securities ...... 261 3,776 Unrealized changes ...... 1,183 4,202 Reclassification adjustments recognized in income ...... (922) (426) Currency translation adjustments ...... (966) 145 Unrealized changes ...... (966) 9 Reclassification adjustments recognized in income ...... 0 136 Changes in actuarial gains/losses of defined benefit pension plans and similar obligations ...... 852 781 Deferred taxes ...... (23) (862) Total income and expenses recognized directly in equity ...... 43 3,564 Total recognized income and expenses (total comprehensive income) ...... 7,767 9,646 Attributable to shareholders of E.ON AG ...... 7,370 8,937 Attributable to minority interests ...... 397 709

F-6 E.ON AG AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

€ in millions 2007 2006 Net income ...... 7,724 6,082 Income from discontinued operations, net ...... (330) (775) Depreciation, amortization and impairment of intangible assets and of property, plant and equipment .... 3,194 3,670 Changes in provisions ...... (146) 1,284 Changes in deferred taxes ...... (35) (465) Other non-cash income and expenses ...... (111) 62 Gain/Loss on disposal of ...... (1,502) (950) Intangible assets and property, plant and equipment ...... (52) (95) Equity investments ...... (444) (362) Securities (> 3 months) ...... (1,006) (493) Changes in operating assets and liabilities and in income taxes ...... (68) (1,747) Inventories ...... 321 (1,673) Trade receivables ...... 455 (1,516) Other operating receivables and income tax assets ...... (724) 462 Trade payables ...... (958) 73 Other operating liabilities and income taxes ...... 838 907 Cash provided by operating activities of continuing operations (operating cash flow) ...... 8,726 7,161 Proceeds from disposal of ...... 1,431 3,877 Intangible assets and property, plant and equipment ...... 293 303 Equity investments ...... 1,138 3,574 Purchase of investments in ...... (11,306) (5,037) Intangible assets and property, plant and equipment ...... (6,916) (4,096) Equity investments ...... (4,390) (941) Proceeds from disposal of securities (> 3 months) and of financial receivables and fixed-term deposits . . 9,914 6,899 Purchase of securities (> 3 months) and of financial receivables and fixed-term deposits ...... (9,114) (10,042) Changes in restricted cash ...... 286 (154) Cash used for investing activities of continuing operations ...... (8,789) (4,457) Payments received/made from changes in capital ...... 55 (1) Payments for treasury shares, net ...... (3,500) 28 Premiums received for put options on treasury shares ...... 64 0 Cash dividends paid to shareholders of E.ON AG ...... (2,210) (4,614) Cash dividends paid to minority shareholders ...... (237) (244) Proceeds from financial liabilities ...... 12,533 10,845 Repayments of financial liabilities ...... (4,897) (11,874) Cash provided by (used for) financing activities of continuing operations ...... 1,808 (5,860) Net increase (decrease) in cash and cash equivalents from continuing operations ...... 1,745 (3,156) Cash provided by operating activities of discontinued operations ...... 12 69 Cash used for investing activities of discontinued operations ...... (12) (109) Cash provided by financing activities of discontinued operations ...... 0 2 Net increase (decrease) in cash and cash equivalents from discontinued operations ...... 0 (38) Effect of foreign exchange rates on cash and cash equivalents ...... (12) 0 Cash and cash equivalents at the beginning of the year ...... 1,154 4,348 Cash and cash equivalents at the end of the year ...... 2,887 1,154 Supplementary Information on Cash Flows from Operating Activities Income taxes paid (less refunds) ...... (1,822) (840) Interest paid ...... (1,134) (1,029) Interest received ...... 814 584 Dividends received ...... 1,325 1,079

F-7 E.ON AG AND SUBSIDIARIES STATEMENT OF CHANGES IN EQUITY

Accumulated other comprehensive income Additional Currency Available- Capital paid-in Retained translation for-sale Cash flow € in millions stock capital earnings adjustment securities hedges Balance as of January 1, 2006 ...... 1,799 11,749 22,910 675 7,343 132 Treasury shares repurchased/sold ...... 11 Dividends paid ...... (4,614) Other changes ...... Net additions/disposals from the reclassification related to put options . . . Total comprehensive income ...... 6,054 (43) 3,148 (222) Net income ...... 5,586 Changes in actuarial gains/ losses of defined benefit pension plans and similar obligations ...... 468 Other comprehensive income ...... (43) 3,148 (222) Balance as of December 31, 2006 ...... 1,799 11,760 24,350 632 10,491 (90) Balance as of January 1, 2007 ...... 1,799 11,760 24,350 632 10,491 (90) Changes in scope of consolidation ...... Treasury shares repurchased/sold ...... Capital increase ...... Capital decrease ...... (65) 65 (3,115) Dividends paid ...... (2,210) Other changes ...... Net additions/disposals from the reclassification related to put options . . . 56 Total comprehensive income ...... 7,747 (950) 590 (17) Net income ...... 7,204 Changes in actuarial gains/ losses of defined benefit pension plans and similar obligations ...... 543 Other comprehensive income ...... (950) 590 (17) Balance as of December 31, 2007 ...... 1,734 11,825 26,828 (318) 11,081 (107)

F-8 Equity Minority Put options attributable interests Reclassification Treasury on treasury to shareholders (before related to Minority shares shares of E.ON AG reclassification) put options interests Total (256) 0 44,352 4,747 (3,130) 1,617 45,969 26 37 37 (4,614) (244) (244) (4,858) (218) (218) (218)

669 669 669 8,937 709 709 9,646 5,586 496 496 6,082

468 35 35 503 2,883 178 178 3,061 (230) 0 48,712 4,994 (2,461) 2,533 51,245 (230) 0 48,712 4,994 (2,461) 2,533 51,245 1,067 1,067 1,067 (386) (386) (386) 180 180 180 (3,115) (64) (64) (3,179) (2,210) (237) (237) (2,447) (56) (56) (56)

(1,053) (997) 1,936 1,936 939 7,370 397 397 7,767 7,204 520 520 7,724

543 66 66 609 (377) (189) (189) (566) (616) (1,053) 49,374 6,281 (525) 5,756 55,130

F-9 E.ON AG AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION Based in Germany, the E.ON Group (“E.ON” or the “Group”) is an international group of companies with integrated electricity and gas operations. The E.ON Group’s reporting segments are presented in line with the Group’s internal organizational and reporting structure: • The Central Europe market unit, led by E.ON Energie AG (“E.ON Energie”), Munich, Germany, operates E.ON’s integrated electricity business and the downstream gas business in Central Europe. • Pan-European Gas is responsible for the upstream and midstream gas business. Moreover, this market unit holds predominantly minority shareholdings in the downstream gas business. This market unit is led by E.ON Ruhrgas AG (“E.ON Ruhrgas”), Essen, Germany. • The U.K. market unit encompasses the integrated energy business in the United Kingdom. This market unit is led by E.ON UK plc (“E.ON UK”), Coventry, U.K. • The Nordic market unit, which is led by E.ON Nordic AB (“E.ON Nordic”), Malmö, Sweden, focuses on the integrated energy business in Northern Europe. It operates through the integrated energy company E.ON Sverige AB (“E.ON Sverige”), Malmö, Sweden. • The U.S. Midwest market unit, led by E.ON U.S. LLC (“E.ON U.S.”), Louisville, Kentucky, U.S., is primarily active in the regulated energy market in the U.S. state of Kentucky. • Corporate Center/New Markets contains those interests held directly by E.ON AG (“E.ON” or the “Company”), including the operations acquired in Russia and those in the area of renewable energy (see Note 4), as well as E.ON AG itself and the consolidation effects that take place at the Group level.

The market units and Corporate Center/New Markets are the reportable segments as defined by International Financial Reporting Standard (“IFRS”) 8, “Operating Segments” (“IFRS 8”).

Note 33 provides additional information about the market units.

With European Union (“EU”) Regulation 1606/2002 dated July 19, 2002, the European Parliament and the European Council mandated the adoption of IFRS into EU law governing the consolidated financial statements of publicly traded companies for fiscal years beginning on or after January 1, 2005. However, member states were permitted to defer mandatory application of IFRS until 2007 for companies that, like E.ON, had been preparing their consolidated financial statements in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and whose stock was officially listed for public trading in a non-EU member state. In Germany, the Bilanzrechtsreformgesetz (“BilReG”) implemented the option to defer mandatory IFRS application in October 2004.

E.ON made use of this option and, accordingly, the Consolidated Financial Statements for the year ended December 31, 2007, contained in this Annual Report have been prepared in accordance with IFRS 1, “First-time Adoption of International Financial Reporting Standards” (“IFRS 1”). These Consolidated Financial Statements have been prepared in accordance with Article 315a (1) of the German Commercial Code (“HGB”) and with those IFRS and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations that had been adopted by the European Commission for use in the EU as of the end of the fiscal year, and whose application was mandatory as of December 31, 2007. In addition, E.ON has opted for the voluntary early adoption of IFRS 8.

The preparation of the Consolidated Financial Statements in accordance with IFRS has led to changes in the Group’s accounting policies as compared with the accounting principles used in the most recent annual Consolidated Financial Statements, i.e., U.S. GAAP. The following accounting policies have been applied for all

F-10 periods presented in these Consolidated Financial Statements. They have also been used, in accordance with IFRS 1, for the preparation of the opening balance sheet under IFRS as of January 1, 2006. The effects of the transition from U.S. GAAP to IFRS are discussed in Note 35.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Principles The Consolidated Financial Statements are prepared based on historical cost, with the exception of available-for-sale financial assets that are recognized at fair value and of financial assets and liabilities (including derivative financial instruments) that must be recognized in income at fair value.

Scope of Consolidation The Consolidated Financial Statements incorporate the financial statements of E.ON AG and entities controlled by E.ON (“subsidiaries”). Control is achieved when the parent company has the power to govern the financial and operating policies of an entity so as to obtain economic benefits from its activities. In addition, special purpose entities are consolidated when the substance of the relationship indicates that the entity is controlled by E.ON.

The results of the subsidiaries acquired or disposed of during the year are included in the Consolidated Statement of Income from the date of acquisition or until the date of the disposal, respectively.

Where necessary, adjustments are made to the subsidiaries’ financial statements to bring their accounting policies into line with those of the Group. Intercompany receivables, liabilities and results between Group companies are eliminated in the consolidation process.

Associated Companies An associate is an entity over which E.ON has significant influence but which is neither a subsidiary nor an interest in a joint venture. Significant influence is achieved when E.ON has the power to participate in the financial and operating policy decisions of the investee but does not control or jointly control these decisions. Significant influence is generally presumed if E.ON directly or indirectly holds at least 20 percent, but less than 50 percent, of an entity’s voting rights.

Interests in associated companies are accounted for under the equity method. In addition, majority-owned companies in which E.ON does not exercise control due to restrictions concerning the control of assets or management are also generally accounted for under the equity method.

Interests in associated companies accounted for under the equity method are reported on the balance sheet at cost, adjusted for changes in the Group’s share of the net assets after the date of acquisition, as well as any impairment charges. Losses that exceed the Group’s interest in an associated company are not recognized. Any goodwill resulting from the acquisition of an associated company is included in the carrying amount of the investment.

Unrealized gains and losses arising from transactions with associated companies accounted for under the equity method are eliminated within the consolidation process on a pro-rata basis if and insofar as these are material.

Companies accounted for under the equity method are tested for impairment by comparing the carrying amount with its recoverable amount. If the carrying amount exceeds the recoverable amount, the carrying amount is adjusted in the amount of this difference. If the reasons for previously recognized impairment losses no longer exist, such impairment losses are reversed.

F-11 The financial statements of equity interests accounted for under the equity method are generally prepared using accounting that is uniform within the Group.

Joint Ventures Joint ventures are also accounted for under the equity method. Unrealized gains and losses arising from transactions with joint-venture companies are eliminated within the consolidation process on a pro-rata basis if and to the extent these are material.

Business Combinations In accordance with the exemption allowed under IFRS 1, the provisions of IFRS 3, “Business Combinations” (“IFRS 3”), were not applied with respect to the accounting for business combinations that occurred before January 1, 2006. The goodwill maintained from this period did not include any intangible assets that had to be reported separately under IFRS. Conversely, there were no intangible assets that until now had been reported separately that had to be included in goodwill. As no adjustment for intangible assets was required relating to such business combinations, the goodwill reported under U.S. GAAP was maintained in E.ON’s opening balance sheet under IFRS.

Business combinations are accounted for by applying the purchase method, whereby the purchase price is offset against the proportional share in the acquired company’s net assets. In doing so, the values at the acquisition date that corresponds to the date at which control of the acquired company was attained are used as a basis. The acquiree’s identifiable assets, liabilities and contingent liabilities are recognized at their fair values, regardless of the extent attributable to minority interests. The fair values of individual assets are determined using published exchange or market prices at the time of acquisition in the case of marketable securities, for example, and in the case of land, buildings and more significant technical equipment, generally using independent expert reports that have been prepared by third parties. If exchange or market prices are unavailable for consideration, fair values are determined using the most reliable information available that is based on market prices for comparable assets or on suitable valuation techniques. In such cases, E.ON determines fair value using the discounted cash flow method by discounting estimated future cash flows by a weighted average cost of capital. Estimated cash flows are consistent with the internal mid-term planning data for the next three years, followed by two additional years of cash flow projections, which are extrapolated until the end of an asset’s useful life using a growth rate based on industry and internal projections. The discount rate reflects specific risks inherent to the asset.

Transactions with minority shareholders are treated in the same way as transactions with equity holders. Should the acquisition of additional shares in a subsidiary result in a difference between the cost of purchasing the shares and the carrying amount of the minority interest acquired, that difference must be fully recognized in equity.

Gains and losses from disposals of shares to minority shareholders are also recognized in equity, provided that such disposals do not result in a loss of control.

Intangible assets must be recognized separately from goodwill if they are clearly separable or if their recognition arises from a contractual or other legal right. Provisions for restructuring measures may not be recorded in a purchase price allocation. If the purchase price paid exceeds the proportional share in the net assets at the time of acquisition, the positive difference is recognized as goodwill. A negative difference is immediately recognized in income.

F-12 Foreign Currency Translation The Company’s transactions denominated in foreign currencies are translated at the current exchange rate at the date of the transaction. Monetary foreign currency items are adjusted to the current exchange rate at each balance sheet date; any gains and losses resulting from fluctuations in the relevant currencies are included in other operating income and other operating expenses, respectively. Gains and losses from the translation of financial instruments used in hedges of net investments in its foreign operations are recognized in equity. The ineffective portion of the hedging instrument is immediately recognized in income.

The functional currency as well as the reporting currency of E.ON AG is the euro. The Consolidated Financial Statements are presented in euro as well. The assets and liabilities of the Company’s foreign subsidiaries with a functional currency other than the euro are translated using period-end exchange rates, while items of the statements of income are translated using average exchange rates for the period. Significant transactions of foreign subsidiaries occurring during the fiscal year are translated in the financial statements using the exchange rate at the date of the transaction. Differences arising from the translation of assets and liabilities, as well as gains or losses in comparison with the translation of prior years, are included as a separate component of equity and accordingly have no effect on net income. In accordance with the option under IFRS 1, all unrealized cumulative translation differences that had resulted from the translation of financial statements into the reporting currency of E.ON in prior periods and had been recognized in equity were offset against retained earnings at the date of transition.

The foreign currency translation effects that are attributable to monetary financial instruments classified as available for sale are recognized in net income. For non-monetary financial instruments classified as available for sale, the foreign currency translation effects are recognized in equity with no effect on net income.

The following table depicts the movements in exchange rates for the periods indicated for major currencies of countries outside the European Monetary Union:

Currencies

€ 1, annual average € ISO 1, rate at year-end rate Code 2007 2006 2007 2006 British pound ...... GBP 0.73 0.67 0.68 0.68 Norwegian krone ...... NOK 7.97 8.24 8.02 8.05 Russian ruble ...... RUB 35.99 34.68 34.99 34.11 Swedish krona ...... SEK 9.45 9.04 9.25 9.25 Hungarian forint ...... HUF 253.81 251.77 251.34 264.26 U.S. Dollar ...... USD 1.47 1.32 1.37 1.26

Recognition of Income a) Revenues The Company generally recognizes revenue upon delivery of products to customers or upon fulfillment of services. Delivery has occurred when the risks and rewards associated with ownership have been transferred to the buyer, compensation has been contractually established and collection of the resulting receivable is probable. Revenues from the sale of goods and services are measured at the fair value of the consideration received or receivable.

Revenues are presented net of sales taxes, returns, rebates and discounts, and after elimination of intercompany sales.

F-13 Revenues are generated primarily from the sale of electricity and gas to industrial and commercial customers and to retail customers. Additional revenue is earned from the distribution of electricity and gas, as well as from deliveries of steam and heat.

Revenues from the sale of electricity and gas to industrial and commercial customers and to retail customers are recognized when earned on the basis of a contractual arrangement with the customer; they reflect the value of the volume supplied, including an estimated value of the volume supplied to customers between the date of their last meter reading and period-end.

b) Interest Income Interest income is recognized pro rata using the effective interest method.

c) Dividend Income Dividend income is recognized when the right to receive the distribution payment arises.

Electricity and Energy Taxes The electricity tax is levied on electricity delivered to retail customers by domestic utilities in Germany and Sweden and is calculated on the basis of a fixed tax rate per kilowatt-hour (“kWh”). This rate varies between different classes of customers. Electricity and energy taxes paid are deducted from sales revenues on the face of the income statement.

Germany’s Energy Tax Act (“Energiesteuergesetz,” “EnergieStG”) regulates the taxation of energy generated from petroleum, natural gas and coal. It replaced the Petroleum Tax Act (“Mineralölsteuergesetz”) effective August 1, 2006. Under the Energy Tax Act, natural gas tax is not levied until delivery to the end consumer. Under the previously applicable Petroleum Tax Act, natural gas tax became due at the time of the procurement or removal of the natural gas from storage facilities.

Accounting for Sales of Shares of Subsidiaries or Associated Companies If a subsidiary or associated company sells shares to a third party, leading to a reduction in E.ON’s ownership interest in the relevant company (“dilution”), and consequently to a loss of control or significant influence, gains and losses from these dilutive transactions are included in the income statement under other operating income or expenses.

Research and Development Costs Under IFRS, research and development costs must be allocated to a research phase and a development phase. While expenditure on research is expensed as incurred, recognized development costs must be capitalized as an intangible asset if all of the general criteria for recognition specified in IAS 38, “Intangible Assets” (“IAS 38”), as well as certain other specific prerequisites, have been fulfilled. In the 2007 and 2006 fiscal years, these criteria have not been fulfilled.

Research and development costs totaled €37 million in 2007 (2006: €27 million).

Earnings per Share Basic (undiluted) earnings per share is computed by dividing the consolidated net income attributable to the shareholders of the parent company by the weighted average number of ordinary shares outstanding during the relevant period. At E.ON the computation of diluted earnings per share is identical to basic earnings per share, because E.ON AG has no dilutive potential ordinary shares.

F-14 Goodwill and Intangible Assets Goodwill According to IFRS 3, goodwill is not amortized, but rather tested for impairment at the cash-generating unit level on at least an annual basis. Impairment tests must also be performed between these annual tests if events or changes in circumstances indicate that the carrying amount of the respective cash-generating unit might not be recoverable.

Newly created goodwill is allocated to those cash-generating units expected to benefit from the respective business combination. E.ON has identified the operating units one level below its primary segments as its cash- generating units.

In a first step, E.ON determines the recoverable amount of a cash-generating unit on the basis of the fair value (less costs to sell) using valuation procedures that make use of the Company’s internal mid-term planning data. Valuation is based on the discounted cash flow method, and accuracy is verified through the use of multiples. In addition, market transactions or valuations prepared by third parties for comparable assets are used to the extent available.

In an impairment test, the recoverable amount of a cash-generating unit is compared with its carrying amount, including goodwill. The recoverable amount is the higher of the cash-generating unit’s fair value less costs to sell and its value in use. If the carrying amount exceeds the recoverable amount, the goodwill allocated to that cash-generating unit is adjusted in the amount of this difference.

If the impairment thus identified exceeds the goodwill allocated to the affected cash-generating unit, the remaining assets of the unit must be written down in the proportion of their carrying amounts. Individual assets may not be written down if their respective carrying amounts were to fall below the highest of the following as a result: • Fair value less costs to sell • Value in use • Zero

The impairment loss that would otherwise have been allocated to the asset concerned must instead be allocated pro rata to the remaining assets of the unit.

E.ON has elected to perform the annual testing of goodwill for impairment at the cash-generating unit level in the fourth quarter of each fiscal year.

Impairment losses recognized for goodwill in a cash-generating unit may not be reversed in subsequent reporting periods.

Intangible Assets IAS 38 requires that intangible assets be amortized over their useful lives unless their lives are considered to be indefinite.

Acquired intangible assets subject to amortization are classified as marketing-related, customer-related, contract-based, and technology-based. Internally generated intangible assets subject to amortization are related to software. Intangible assets subject to amortization are measured at cost and amortized using the straight-line method over their expected useful lives, generally for a period between 5 and 25 years or between 3 and 5 years for software, respectively. Useful lives and amortization methods are subject to annual verification. Intangible assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate that such assets may be impaired.

F-15 Intangible assets not subject to amortization are measured at cost and tested for impairment annually or more frequently if events or changes in circumstances indicate that such assets may be impaired. Moreover, such assets are reviewed annually to determine whether an assessment of indefinite useful life remains applicable.

In accordance with IAS 36, “Impairment of Assets” (“IAS 36”), the carrying amount of an intangible asset, whether subject to amortization or not, is tested for impairment by comparing the carrying value with its recoverable amount, which is the higher of an asset’s value in use and its fair value less costs to sell. Should the carrying amount exceed the recoverable amount, an impairment charge equal to the difference between the carrying amount and the recoverable amount is recognized. If the reasons for previously recognized impairment losses no longer exist, such impairment losses are reversed. A reversal shall not cause the carrying amount of an intangible asset subject to amortization to exceed the amount that would have been determined, net of amortization, had no impairment loss been recognized during the period.

If a recoverable amount cannot be determined for an individual intangible asset, the recoverable amount for the smallest identifiable group of assets (cash-generating unit) that the intangible asset may be assigned to is determined.

Please see Note 14(a) for additional information about goodwill and intangible assets.

Emission Rights Under IFRS, emission rights held under national and international emission-rights systems for the settlement of obligations are reported as intangible assets. Because emission rights are not amortized, they are reported as intangible assets not subject to amortization. Emission rights are capitalized at cost on acquisition or when issued for the respective reporting period as (partial) fulfillment of the notice of allocation from the responsible national authorities.

A provision is recognized for emissions produced. The provision is measured at the carrying amount of the emission rights held or, in the case of a shortfall, at the current fair value of the emission rights needed. Any expected shortfall in emission rights is recorded under miscellaneous provisions. The expenses incurred for the recognition of the provision are reported under cost of materials.

As part of operating activities, emission rights are also held for proprietary trading purposes. Emission rights held for proprietary trading are reported under other operating assets and measured at the lower of cost or fair value.

Property, Plant and Equipment Property, plant and equipment are initially measured at acquisition or production cost, including decommissioning or restoration cost that must be capitalized, and are depreciated over their expected useful lives, generally using the straight-line method, unless a different method of depreciation is deemed more suitable in certain exceptional cases.

Useful Lives of Property, Plant and Equipment

Buildings ...... 10to50years Technical equipment, plant and machinery ...... 10to65years Other equipment, fixtures, furniture and office equipment ...... 3to25years

Property, plant and equipment are tested for impairment whenever events or changes in circumstances indicate that an asset may be impaired. In such a case, property, plant and equipment are tested for impairment

F-16 according to the principles prescribed for intangible assets in IAS 36. If an impairment loss is determined, the remaining useful life of the asset might also be subject to adjustment, where applicable. If the reasons for previously recognized impairment losses no longer exist, such impairment losses are reversed and recognized in income. Such reversal shall not cause the carrying amount to exceed the amount that would have been presented had no impairment taken place during the preceding periods.

Investment subsidies do not reduce the acquisition and production costs of the respective assets; they are instead reported on the balance sheet as deferred income.

Subsequent costs arising, for example, from additional or replacement capital expenditure are only recognized as part of the acquisition or production cost of the asset, or else—if relevant—recognized as a separate asset if it is probable that the Group will receive a future economic benefit and the cost can be determined reliably.

Repair and maintenance costs that do not constitute significant replacement capital expenditure are expensed as incurred.

Borrowing Costs Borrowing costs that arise in connection with the acquisition, construction or production of a qualifying asset from the time of acquisition or from the beginning of construction or production until entry into service are capitalized and subsequently amortized alongside the related asset. Borrowing costs are generally allocated using the Group’s overall cost of financing as a basis. As of December 31, 2007, a financing rate uniform within the Group of 5.0 percent was applied. In the case of a specific financing arrangement, the respective specific borrowing costs for that arrangement are used. Other borrowing costs are expensed.

Government Grants Government investment subsidies do not reduce the acquisition and production costs of the respective assets; they are instead reported on the balance sheet as deferred income. They are amortized on a straight-line basis over the related asset’s expected useful life.

Government grants are recognized at fair value if it is highly probable that the grant will be issued and if the Group satisfies the necessary conditions for receipt of the grant.

Government grants for costs are recognized over the period in which the costs that are supposed to be compensated through the respective grants are incurred.

Leasing Leasing transactions are classified according to the lease agreements and to the underlying risks and rewards specified therein in line with IAS 17, “Leases” (“IAS 17”). In addition, IFRIC 4, “Determining Whether an Arrangement Contains a Lease” (“IFRIC 4”), further defines the criteria as to whether an agreement that conveys a right to use an asset meets the definition of a lease. Certain purchase and supply contracts in the electricity and gas business as well as certain rights of use may be classified as leases if the criteria are met. E.ON is party to some agreements in which it is the lessor and other agreements in which it is the lessee.

Leasing transactions in which E.ON is the lessee are classified either as finance leases or operating leases. If the Company bears substantially all of the risks and rewards incident to ownership of the leased property, the lease is classified as a finance lease. Accordingly, the Company recognizes on its balance sheet the asset and the associated liability in equal amounts.

F-17 Recognition takes place at the beginning of the lease term at the lower of the fair value of the leased property or the present value of the minimum lease payments.

The leased property is depreciated over its useful economic life or, if it is shorter, the term of the lease.

The liability is subsequently measured using the effective interest method. All other transactions in which E.ON is the lessee are classified as operating leases. Payments made under operating leases are generally expensed over the term of the lease.

Leasing transactions in which E.ON is the lessor and substantially all the risks and rewards incident to ownership of the leased property are transferred to the lessee are classified as finance leases. In this type of lease, E.ON records the present value of the minimum lease payments as a receivable. Payments by the lessee are apportioned between a reduction of the lease receivable and interest income. The income from such arrangements is recognized over the term of the lease using the effective interest method.

All other transactions in which E.ON is the lessor are treated as operating leases. E.ON retains the leased property on its balance sheet as an asset, and the lease payments are generally recorded as income over the term of the lease.

Financial Instruments The first-time adoption of IFRS 7, “Financial Instruments: Disclosures” (“IFRS 7”), became effective in the 2007 fiscal year. The new standard requires both quantitative and qualitative disclosures about the extent of risks arising from financial instruments (e.g., credit, liquidity and market risks).

Non-Derivative Financial Instruments Non-derivative financial instruments are recognized at fair value on the settlement date when acquired. Unconsolidated equity investments and securities are measured in accordance with IAS 39. E.ON categorizes financial assets as held for trading, available for sale, or as loans and receivables. Management determines the categorization of the financial assets at initial recognition.

Securities categorized as available for sale are carried at fair value on a continuing basis, with any resulting unrealized gains and losses, net of related deferred taxes, reported as a separate component within equity until realized. Realized gains and losses are recorded based on the specific identification method. Unrealized losses previously recognized in equity are recognized in financial results in the case of substantial impairment. Reversals of impairment losses relating to equity instruments are recognized exclusively in equity.

Loans and receivables (including trade receivables) are non-derivative financial assets with fixed or determinable payments that are not traded in an active market. Loans and receivables are reported on the balance sheet under “Receivables and other assets.” They are subsequently measured at amortized cost, using the effective interest method. Valuation allowances are provided for identifiable individual risks. If the loss of a certain part of the receivables is probable, valuation allowances are provided to cover the expected loss. Reversals of losses are recognized under “Other operating income.”

Non-derivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at amortized cost, using the effective interest method. Initial measurement takes place at fair value plus transaction costs. In subsequent periods, the amortization and accretion of any premium or discount is included in financial results.

F-18 Derivative Financial Instruments and Hedging Transactions Derivative financial instruments and separated embedded derivatives are measured at fair value as of the trade date at initial recognition and in subsequent periods. IAS 39 requires that they be categorized as held for trading as long as they are not a component of a hedge accounting relationship. Gains and losses from changes in fair value are immediately recognized in net income.

Instruments commonly used are foreign currency forwards and swaps, as well as interest-rate swaps and cross-currency swaps. Equity forwards are entered into to cover price risks on securities. In commodities, the instruments used include physically and financially settled forwards and options related to electricity, gas, coal, oil and emission rights. As part of conducting operations in commodities, derivatives are also acquired for proprietary trading purposes.

IAS 39 sets requirements for the designation and documentation of hedging relationships, the hedging strategy, as well as ongoing retrospective and prospective measurement of effectiveness in order to qualify for hedge accounting. The Company does not exclude any component of derivative gains and losses from the measurement of hedge effectiveness. Hedge accounting is considered to be appropriate if the assessment of hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80 to 125 percent effective at offsetting the change in fair value due to the hedged risk of the hedged item or transaction.

For qualifying fair value hedges, the change in the fair value of the derivative and the change in the fair value of the hedged item that is due to the hedged risk(s) are recognized in income. If a derivative instrument qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is recognized in equity (as a component of accumulated other comprehensive income) and reclassified into income in the period or periods during which the transaction being hedged affects income. The hedging result is reclassified into income immediately if it becomes probable that the hedged underlying transaction will no longer occur. For hedging instruments used to establish cash flow hedges, the change in fair value of the ineffective portion is recognized immediately in the income statement. To hedge the foreign currency risk arising from the Company’s net investment in foreign operations, derivative as well as non-derivative financial instruments are used. Gains or losses due to changes in fair value and from foreign currency translation are recognized separately within equity as currency translation adjustments.

Changes in fair value of derivative instruments that must be recognized in income are classified as other operating income or expenses. Gains and losses from interest-rate derivatives are netted for each contract and included in interest income. Gains and losses from derivative proprietary trading instruments are shown net as either revenues or cost of materials. Certain realized amounts are, if related to the sale of products or services, also included in sales or cost of materials.

Unrealized gains and losses resulting from the initial measurement of derivative financial instruments at the inception of the contract are not recognized in income. They are instead deferred and recognized in income systematically over the term of the derivative. An exception to the accrual principle applies if unrealized gains and losses from the initial measurement are verified by quoted market prices, observable prices of other current market transactions or other observable data supporting the valuation technique. In this case the gains and losses are recognized in income.

See Note 30 for additional information regarding the Company’s use of derivative instruments.

Inventories The Company measures inventories at the lower of acquisition or production cost and net realizable value. The cost of raw materials, finished products and goods purchased for resale is determined based on the average cost method. In addition to production materials and wages, production costs include material and production

F-19 overheads based on normal capacity. The costs of general administration are not capitalized. Inventory risks resulting from excess and obsolescence are provided for using appropriate valuation allowances whereby inventories are written down to net realizable value.

Receivables and Other Assets Receivables and other assets are initially measured at fair value, which generally approximates nominal value. They are subsequently measured at amortized cost, using the effective interest method. Valuation allowances, included in the reported net carrying amount, are provided for identifiable individual risks. If the loss of a certain part of the receivables is probable, valuation allowances are provided to cover the expected loss.

Liquid Funds Liquid funds include current available-for-sale securities, checks, cash on hand and bank balances. Bank balances and available-for-sale securities with an original maturity of more than three months are recognized under securities and fixed term deposits. Liquid funds with an original maturity of less than three months are considered to be cash and cash equivalents, unless they are restricted.

Restricted cash with a remaining maturity in excess of twelve months is classified as financial receivables and other financial assets.

Assets Held for Sale and Liabilities Associated with Assets Held for Sale Individual non-current assets or groups of assets held for sale and any directly attributable liabilities (disposal groups) are reported in these line items if they can be disposed of in their current condition and if there is sufficient probability of their disposal actually taking place. For a group of assets and associated liabilities to be classified as a disposal group, the assets and liabilities in it must be held for sale in a single transaction or as part of a comprehensive plan.

Discontinued operations are components of an entity that are either held for sale or have already been sold and can be clearly distinguished from other corporate operations, both operationally and for financial reporting purposes. Additionally, the component classified as a discontinued operation must represent a major business line or a specific geographic area of the Group.

Non-current assets that are held for sale either individually or collectively as part of a disposal group, or that belong to a discontinued operation, are no longer depreciated. They are instead accounted for at the lower of the carrying amount and the fair value less any remaining costs to sell. If the fair value is less than the carrying amount, an impairment loss is recognized.

The income and losses resulting from the measurement of components held for sale at fair value less any remaining costs to sell, as well as the gains and losses arising from the disposal of discontinued operations, are reported separately on the face of the income statement under income/loss from discontinued operations, net, as is the income from the ordinary operating activities of these divisions. Prior-year income statement figures are adjusted accordingly. The cash flows of discontinued operations are reported separately in the cash flow statement with prior-year figures being adjusted accordingly. However, there is no reclassification of prior-year balance sheet line items attributable to discontinued operations.

Equity Instruments IFRS defines equity as the residual interest in the Group’s assets after deducting all liabilities. Therefore, equity is the net amount of all recognized assets and liabilities.

F-20 E.ON has entered into conditional and unconditional purchase commitments to minority shareholders. By means of these agreements, the minority shareholders have the right to require E.ON to purchase their shares on specified conditions. None of the contractual obligations has led to the transfer of substantially all of the risk and rewards to E.ON at the time of entering into the contract. IAS 32, “Financial Instruments: Presentation” (“IAS 32”), prescribes that a liability must be recognized at the present value of the probable future exercise price. This amount is reclassified from a separate component within minority interests and reported separately as a liability. The reclassification occurs irrespective of the probability of exercise. Expenses resulting from the accretion of the liability are recognized in interest expenses. If a purchase commitment expires unexercised, the liability reverts to minority interests. Any difference between liabilities and minority interests is recognized directly in retained earnings.

Where shareholders of entities own statutory, non-excludable rights of termination (for example, in German partnerships), such termination rights require the reclassification of minority interests from equity into liabilities under IAS 32. The liability is recognized at the present value of the expected settlement amount irrespective of the probability of termination. Changes in the value of the liability are reported within other operating income. Accretion of the liability and the minority shareholders’ share in net income are shown as interest expense.

If an E.ON Group company buys treasury shares of E.ON AG, the value of the consideration paid, including directly attributable additional costs (net after income taxes), is deducted from E.ON AG’s equity until the shares are retired, distributed or resold. If such treasury shares are subsequently distributed or sold, the consideration received, net of any directly attributable additional transaction costs and associated income taxes, are added to E.ON AG’s equity.

Share-Based Payment Share-based payment plans issued in the E.ON Group are accounted for in accordance with IFRS 2, “Share- Based Payment” (“IFRS 2”). Both the E.ON Share Performance Plan introduced in fiscal 2006 and the remaining Stock Appreciation Rights granted between 1999 and 2005 as part of the virtual stock option program of E.ON AG are share-based payment transactions with cash compensation, the value of which is reported at fair value of the liability at each balance sheet date. Compensation expense is recorded pro rata over the vesting period. E.ON determines fair value using the Monte Carlo simulation technique.

Provisions for Pensions and Similar Obligations The valuation of defined benefit obligations in accordance with IAS 19, “Employee Benefits” (“IAS 19”), is based on actuarial computations using the projected unit credit method, with actuarial valuations performed at year-end. The valuation encompasses both pension obligations and pension entitlements that are known on the balance sheet date as well as economic trend assumptions made in order to reflect realistic expectations.

Actuarial gains and losses that may arise from differences between the estimated and actual number of beneficiaries and from the underlying assumptions are recognized in full in the period in which they occur. Such gains and losses are not reported within the Consolidated Statements of Income but rather are recognized within the Statements of Recognized Income and Expenses as part of equity.

The service cost representing the additional benefits that employees earned under the benefit plan during the fiscal year is reported under personnel costs; interest expenses and expected return on plan assets are reported under financial results.

Unrecognized past service cost is recognized immediately to the extent that the benefits are already vested or is amortized on a straight-line basis over the average period until the benefits become vested.

The amount reported in the balance sheet represents the present value of the defined benefit obligation adjusted for unrecognized past service cost and reduced by the fair value of plan assets. If a net asset position

F-21 arises from this calculation, the amount is limited to the unrecognized past service cost plus the present value of available refunds and reductions in future contributions.

Payments for defined contribution pension plans are expensed as incurred and reported under personnel costs. Contributions to government pension plans are treated like payments for defined contribution pension plans to the extent that the Group’s obligations under these pension plans correspond to those under defined contribution pension plans.

Provisions for Asset Retirement Obligations and Other Provisions In accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”), provisions are recognized when E.ON has a legal or constructive present obligation towards third parties as a result of a past event, it is probable that E.ON will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation. The provision is recognized at the expected settlement amount. Long- term obligations are reported as liabilities at the present value of their expected settlement amounts if the interest rate effect (the difference between present value and repayment amount) resulting from discounting is material; future cost increases that are foreseeable and likely to occur on the balance sheet date must also be included in the measurement. Long-term obligations are discounted at the market interest rate applicable as of the respective balance sheet date. The accretion amounts and the effects of changes in interest rates are generally presented as part of financial results. A reimbursement related to the provision that is virtually certain to be collected is capitalized as a separate asset. No offsetting within provisions is permitted. Advance payments remitted are deducted from the provisions.

Obligations arising from the decommissioning and restoration of property, plant and equipment are recognized during the period of their occurrence at their discounted settlement amounts, provided that the obligation can be reliably estimated. The carrying amounts of the respective property, plant and equipment are increased by the same amounts. In subsequent periods, capitalized asset retirement costs are amortized over the expected remaining useful lives of the assets, and the provision is accreted to its present value on an annual basis.

Changes in estimates arise in particular from deviations from original cost estimates, from changes to the maturity or the scope of the relevant obligation, and also as a result of the regular adjustment of the discount rate to current market interest rates. The adjustment of provisions for the decommissioning and restoration of property, plant and equipment for changes to estimates is generally recognized by way of a corresponding adjustment to assets, with no effect on income. If the property, plant and equipment to be decommissioned have already been fully depreciated, changes to estimates are recognized within the income statement.

The estimates for non-contractual nuclear decommissioning provisions are based on external studies and are continuously updated.

Under Swedish law, E.ON Sverige is required to pay fees to the country’s national fund for nuclear waste management. Each year, the Swedish Nuclear Power Inspectorate calculates the fees for the disposal of high- level radioactive waste and nuclear power plant decommissioning based on the amount of electricity produced at the particular nuclear power plant. The proposed fees are then submitted to government offices for approval. Upon approval, E.ON Sverige makes the corresponding payments. In accordance with IFRIC 5, “Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds” (“IFRIC 5”), payments into the Swedish national fund for nuclear waste management are offset by a right of reimbursement of asset retirement obligations, which is recognized as an asset under “Other assets.” In a departure from the policy applied in Germany, provisions for Sweden measured on the basis of the contributions to the fund are discounted at the real interest rate.

No provisions are established for contingent asset retirement obligations where the type, scope, timing and associated probabilities can not be determined reliably.

F-22 Contingent liabilities are potential or present obligations toward third parties in which an outflow of resources embodying economic benefits is not probable or where the amount of the obligation cannot be measured with sufficient reliability. Contingent liabilities are generally not recognized on the balance sheet.

Income Taxes Under IAS 12, “Income Taxes” (“IAS 12”), deferred taxes are recognized on temporary differences arising between the carrying amounts of assets and liabilities on the balance sheet and their tax bases (balance sheet liability method). Deferred tax assets and liabilities are recognized for temporary differences that will result in taxable or deductible amounts when taxable income is calculated for future periods, unless those differences are the result of the initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction, affects neither accounting nor taxable profit/loss. IAS 12 further requires that deferred tax assets be recognized for unused tax loss carryforwards and unused tax credits. Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and unused tax losses can be utilized. Each of the corporate entities is assessed individually with regard to the probability of a positive tax result in future years. Any existing history of losses is incorporated in this assessment. For those tax assets to which these assumptions do not apply, the value of the deferred tax assets has been reduced.

Deferred tax liabilities caused by temporary differences associated with investments in affiliated and associated companies are recognized unless the timing of the reversal of such temporary differences can be controlled within the Group and it is probable that, owing to this control, the differences will in fact not be reversed in the foreseeable future.

Deferred tax assets and liabilities are measured using the enacted or substantively enacted tax rates expected to be applicable for taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of changes in tax rates and tax law is generally recognized in income. Equity is adjusted for deferred taxes that had previously been recognized directly in equity. Following passage of the 2008 corporate tax reforms in Germany, deferred taxes for domestic companies were calculated using a total tax rate of 30 percent (2006: 39 percent). This tax rate includes, in addition to the 15 percent (2006: 25 percent) corporate income tax, the solidarity surcharge of 5.5 percent on the corporate tax, and the average trade tax rate of 14 percent (2006: 13 percent) applicable to the E.ON Group. Foreign subsidiaries use applicable national tax rates.

Note 10 shows the major temporary differences so recorded.

Consolidated Statement of Cash Flows In accordance with IAS 7, “Cash Flow Statements” (“IAS 7”), the Consolidated Statements of Cash Flows are classified by operating, investing and financing activities. Cash flows from discontinued operations are reported separately in the Consolidated Statement of Cash Flows. Interest received and paid, income taxes paid and refunded, as well as dividends received are classified as operating cash flows, whereas dividends paid are classified as financing cash flows. The purchase and sale prices respectively paid and received in connection with the acquisition and disposal of affiliated companies are reported under investing activities, net of the cash and cash equivalents acquired or divested as part of the transaction. This also applies to valuation changes due to exchange rate fluctuations, whose impact on cash and cash equivalents is separately disclosed.

Segment Information Segment reporting has for the first time taken place in accordance with IFRS 8. The so-called management approach required by IFRS 8 stipulates that the internal reporting organization used by management for making decisions on operating matters and the internal performance measure, i.e., adjusted EBIT, should be applied in the identification of the Company’s reportable segments (see Note 33).

F-23 Structure of the Consolidated Balance Sheets and Statements of Income In accordance with IAS 1, “Presentation of Financial Statements” (“IAS 1”), the Consolidated Balance Sheets have been prepared using a classified balance sheet structure. Assets that will be realized within twelve months of the reporting date, as well as liabilities that are due to be settled within one year of the reporting date are classified as current.

In addition, as part of the transition to IFRS, classification of the Income Statement was changed to the nature of expense method which is also applied for internal purposes.

Capital Structure Management At the end of May 2007, E.ON announced its future corporate strategy. As part of this strategic reorientation at E.ON, the financial strategy of the Group was also developed further.

Accordingly, E.ON has replaced adjusted EBITDA with the debt factor as a metric for the management of capital structure. The debt factor is defined as the ratio of net economic debt to adjusted EBITDA. Net economic debt includes provisions for pensions and waste disposal in addition to financial debt. E.ON has set a debt factor of 3 as its target, which is derived from the target rating of single A flat/A2 and is actively managed.

Based on adjusted EBITDA in 2007 of €12,450 million (2006: €11,724 million) and net economic debt of €24,138 million as of the balance sheet date (2006: €18,233 million), the debt factor is 1.9 (2006: 1.6).

Critical Accounting Estimates and Assumptions; Critical Judgments in the Application of Accounting Policies The preparation of the Consolidated Financial Statements requires management to make estimates and assumptions that may influence the application of accounting principles within the Group and affect the valuation and presentation of reported figures. Estimates are based on past experience and on additional knowledge obtained on transactions to be reported. Actual amounts could differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Adjustments to accounting estimates are recognized in the period in which the estimate is revised if the change affects only that period or in the period of the revision and subsequent periods if both current and future periods are affected.

Estimates are particularly necessary for the measurement of the value of property, plant and equipment and of intangible assets, especially in connection with purchase price allocations, the recognition and measurement of deferred tax assets, the accounting treatment of provisions for pensions and miscellaneous provisions, as well as for impairment testing in accordance with IAS 36.

The underlying principles used for estimates in each of the relevant topics are outlined in the respective sections.

New Standards and Interpretations The International Accounting Standards Board (“IASB”) and the IFRIC have issued standards and interpretations whose application is not yet mandatory in the reporting period. The application of some of these standards and interpretations is at the present time still subject to adoption by the EU, which remains outstanding.

IFRS 3, “Business Combinations” In January 2008, the IASB published a revised version of IFRS 3, “Business Combinations” (“IFRS 3”), as part of its “Business Combinations II” project. The most significant changes from the previous version relate to

F-24 the recognition and measurement of assets and liabilities acquired through a business combination, the measurement of non-controlling interests, as well as to the calculation of goodwill and the presentation of transactions with variable purchase prices. The revised standard is to be applied for transactions taking place in fiscal years beginning on or after July 1, 2009. However, the standard has not yet been transferred by the EU into European law. E.ON is currently evaluating the potential effects arising from the revision of IFRS 3.

IFRS 2, “Share-based Payment” In January 2008, the IASB issued revised IFRS 2, “Share-based Payment” (“IFRS 2”). The changes from the previous version relate primarily to the definition of vesting conditions and to the regulations governing the cancellation of a plan by a party other than the entity. The amendments are to be applied for fiscal years beginning on or after January 1, 2009. However, the standard has not yet been transferred by the EU into European law. Revised IFRS 2 will not have a material impact on E.ON’s Consolidated Financial Statements.

IAS 23, “Borrowing Costs” In March 2007, the IASB issued revised IAS 23, “Borrowing Costs” (“IAS 23”). IAS 23 eliminates the option of recognizing borrowing costs immediately as an expense, to the extent that they are directly attributable to the acquisition, construction or production of a qualifying asset. Capitalization of such directly attributable borrowing costs is now mandatory. The revised standard applies to borrowing costs relating to qualifying assets for which the commencement date for capitalization is on or after January 1, 2009. However, the standard has not yet been transferred by the EU into European law. Revised IAS 23 has no impact for E.ON as E.ON already capitalizes borrowing costs as a part of the cost of acquisition or construction.

IAS 1, “Presentation of Financial Statements” In September 2007, the IASB issued a revised version of IAS 1. The main changes from the previous version relate to the presentation of equity and to changes in the titles of the financial statements. The revised standard is to be applied for fiscal years beginning on or after January 1, 2009. However, the standard has not yet been transferred by the EU into European law. Revised IAS 1 will not have a material impact on E.ON’s Consolidated Financial Statements.

IAS 27, “Consolidated and Separate Financial Statements” In January 2008, the IASB published a revised version of IAS 27, “Consolidated and Separate Financial Statements” (“IAS 27”), as part of its “Business Combinations II” project, which contains rules on consolidation. In particular, this standard has for the first time dealt with transactions in which shares in a company (subsidiary) are bought or sold without resulting in a change of control. Additional significant changes from the previous version relate in particular to the recognition and measurement of the remaining investment in an entity after a loss of control of what had been a subsidiary, and to the recognition of losses attributable to minority interests. The amendments introduced by the revised standard are to be applied for fiscal years beginning on or after July 1, 2009. However, the standard has not yet been transferred by the EU into European law. E.ON is currently evaluating the potential effects arising from the revision of IAS 27.

Amendments to IAS 32 and IAS 1, “Puttable Financial Instruments and Obligations Arising on Liquidation” In February 2008, the IASB approved amendments to IAS 32 and IAS 1. The primary purpose of the amendments is to address the accounting treatment for particular types of puttable financial instruments that have characteristics similar to ordinary shares. IAS 32 previously required that such financial instruments be classified as a financial liability. The new version provides for reporting such instruments as equity if the holder can require the issuer to deliver a pro rata share of the net assets of the entity only on liquidation. The amendments are to be applied for fiscal years beginning on or after January 1, 2009. The amendments have not yet been

F-25 transferred by the EU into European law. E.ON is currently evaluating the potential effects of the amendments to IAS 32 and IAS 1.

IFRIC 11, “IFRS 2—Group and Treasury Share Transactions” IFRIC 11, “IFRS 2—Group and Treasury Share Transactions” (“IFRIC 11”), addresses how to apply IFRS 2 to share-based payment arrangements in which an entity’s own equity instruments or equity instruments of another company in the same group are granted. IFRIC 11 requires share-based compensation systems in which a company receives goods or services as consideration for its own equity instruments to be accounted for as equity- settled share-based payment transactions. IFRIC 11 further provides guidance on how share-based compensation systems in which a parent company’s equity instruments are granted should be accounted for at a member of a group of companies. IFRIC 11 is to be applied for fiscal years beginning on or after March 1, 2007. The adoption of IFRIC 11 will not have a material impact on E.ON’s Consolidated Financial Statements.

IFRIC 12, “Service Concession Arrangements” IFRIC 12, “Service Concession Arrangements” (“IFRIC 12”), governs accounting for arrangements in which a public-sector institution grants contracts to private companies for the performance of public services. In performing these services, the private company uses infrastructure that remains under the control of the public- sector institution. The private company is responsible for the construction, operation, and maintenance of the infrastructure. IFRIC 12 is to be applied for fiscal years beginning on or after January 1, 2008; however, it has not yet been transferred by the EU into European law. E.ON is currently evaluating the potential effects of an introduction of IFRIC 12.

IFRIC 13, “Customer Loyalty Programmes” IFRIC 13, “Customer Loyalty Programmes” (“IFRIC 13”), addresses accounting by entities that grant loyalty award credits. The interpretation clarifies how such entities should account for their obligations to provide free or discounted goods or services to customers who redeem award credits. The provisions of IFRIC 13 are to be applied for fiscal years beginning on or after July 1, 2008. However, the interpretation has not yet been transferred by the EU into European law. The adoption of IFRIC 13 will not have a material impact on E.ON’s Consolidated Financial Statements.

IFRIC 14, “IAS 19—The Limit on a Defined Benefit Asset, Minimum Funding Requirements and Their Interaction” IFRIC 14, “IAS 19—The Limit on a Defined Benefit Asset, Minimum Funding Requirements and Their Interaction” (“IFRIC 14”), provides general guidance on how to assess the limit in IAS 19 on the amount of the surplus that can be recognized as an asset. The interpretation also explains how the pension asset or liability for defined benefit plans may be affected when there is a statutory or contractual minimum funding requirement. Under IFRIC 14 no additional liability needs to be recognized by the employer unless the contributions that are payable under the minimum funding requirement cannot be returned to the Company. The interpretation is mandatory for fiscal years beginning on or after January 1, 2008; however, it has not yet been transferred by the EU into European law. The adoption of IFRIC 14 will not have a material impact on E.ON’s Consolidated Financial Statements.

F-26 (3) SCOPE OF CONSOLIDATION The number of consolidated companies changed as follows during the reporting year:

Scope of Consolidation

Domestic Foreign Total Consolidated companies as of January 1, 2006 ...... 129 379 508 Additions ...... 15 18 33 Disposals/Mergers ...... 5 35 40 Consolidated companies as of December 31, 2006 ...... 139 362 501 Additions ...... 23 100 123 Disposals/Mergers ...... 9 24 33 Consolidated companies as of December 31, 2007 ...... 153 438 591

In 2007, a total of 107 domestic and 78 foreign associated companies were accounted for under the equity method (2006: 108 domestic and 60 foreign).

See Note 4 for additional information on acquisitions, disposals and discontinued operations.

(4) ACQUISITIONS, DISPOSALS AND DISCONTINUED OPERATIONS Acquisitions in 2007 OGK-4 On October 12, 2007, E.ON acquired from the Russian government’s energy holding company RAO UES a majority stake in the Russian power-plant company OAO OGK-4 (“OGK-4”), Surgut, Tyumenskaya Oblast, Russian Federation. After the acquisition of additional smaller tranches following the purchase of the majority stake, E.ON holds 72.7 percent of OGK-4 as of the balance sheet date. The total expense incurred for this acquisition, which includes a contractually agreed capital increase of €1.3 billion to finance the investment program planned for the coming years, was approximately €4.4 billion.

Under Russian capital-markets legislation, E.ON was required to make a public offer to purchase the remainder of the shares held by the minority shareholders of OGK-4, and this offer, at a price of 3.3503 rubles per share, was made public on November 15, 2007. The acceptance period ended on February 4, 2008. E.ON was thus able to acquire additional shares equivalent to approximately 3.4 percent of OGK-4 and increase its total ownership stake to approximately 76.1 percent. As was expected, RAO UES did not accept the offer for its 22.5 percent stake in OGK-4.

OGK-4 operates conventional power plants at five locations with a total installed output of 8.6 gigawatts (GW) and plans to build additional power plants with a capacity of about 2.4 GW at the existing locations by 2011.

The initial recognition of the company in the E.ON Consolidated Financial Statements took place in the fourth quarter of 2007.

The E.ON Consolidated Financial Statements included revenues of €248 million and earnings of €3 million (after write-down of fair value adjustments from the purchase price allocation) attributable to OGK-4 for the period from October 1 through December 31, 2007. OGK-4’s revenues and earnings for the full year amounted to €898 million and €29 million, respectively.

F-27 The purchase price allocation for OGK-4 was not final as of December 31, 2007, because effects on property, plant and equipment and also from potential obligations, in particular, remain to be evaluated.

Major Balance Sheet Line Items—OGK-4

IFRS carrying Carrying amounts amounts before Purchase price at initial € in millions initial recognition allocation recognition Intangible assets ...... 11 — 11 Property, plant and equipment ...... 738 2,212 2,950 Other assets ...... 1,497 5 1,502 Total assets ...... 2,246 2,217 4,463 Non-current liabilities ...... 210 529 739 Current liabilities ...... 124 — 124 Total equity and liabilities ...... 334 529 863 Net assets ...... 1,912 1,688 3,600 Attributable to shareholders of E.ON AG ...... 1,390 (1,390) — Attributable to minority interests ...... 522 461 983 Total acquisition costs ...... 4,350 Goodwill (preliminary) ...... 1,733 1,733

ENERGI E2 Renovables Ibéricas On August 13, 2007, E.ON Climate & Renewables GmbH acquired a 100-percent stake in ENERGI E2 Renovables Ibéricas S.L.U. (“E2-I”), Madrid, Spain. The purchase price totaled roughly €481 million. E2-I and its affiliated companies were fully consolidated as of August 31, 2007. Through its affiliated and associated companies, E2-I primarily operates wind farms in Spain and Portugal with an installed generating capacity of 260 megawatts (MW). A more extensive development project pipeline is in place for the coming years. The purchase price allocation is still preliminary as a definitive clarification of certain technical issues remains outstanding.

The E.ON Consolidated Financial Statements included revenues of €5 million and a loss of €1 million (after write-down of fair-value adjustments from the purchase price allocation) attributable to E2-I for the period from September 1 through December 31, 2007. E2-I’s revenues and earnings for the full year amounted to roughly €15 million and €4 million, respectively.

Airtricity On December 18, 2007, E.ON North America Holdings LLC acquired all the shares of Airtricity Inc., Chicago, Illinois, U.S., and all the shares of Airtricity Holdings (Canada) Ltd., Toronto, Ontario, Canada, for a purchase price of approximately €580 million. Airtricity operates a number of wind farms in the U.S. states of Texas and New York with a total installed output of around 250 MW. Additional wind farms with greatly enhanced generating capacity are to be completed by the end of 2008. As the timing of this consolidation is so close to the preparation of the Consolidated Financial Statements, the entire difference between the purchase price and Airtricity’s equity is being carried provisionally as goodwill.

For the full year, Airtricity generated revenues of roughly €9 million and a loss of approximately €44 million.

F-28 Major Balance Sheet Line Items—E.ON Climate & Renewables (E2-I and Airtricity)

IFRS carrying Carrying amounts amounts before Purchase price at initial € in millions initial recognition allocation recognition Intangible assets and acquired goodwill ...... 74 231 305 Property, plant and equipment ...... 934 31 965 Other assets ...... 202 218 420 Total assets ...... 1,210 480 1,690 Non-current liabilities ...... 335 143 478 Current liabilities ...... 828 5 833 Total equity and liabilities ...... 1,163 148 1,311 Net assets ...... 47 332 379 Attributable to shareholders of E.ON AG ...... 43 (43) — Attributable to minority interests ...... 43236 Total acquisition costs ...... 1,061 Goodwill (preliminary) ...... 718 718

Disposals and Discontinued Operations in 2007 ONE E.ON and its partners Telenor and Tele Danmark had signed a contract in June 2007 to sell their shares in the Austrian telecommunications company ONE GmbH (“ONE”), Vienna, Austria, to a consortium of bidders consisting of France Télécom and the financial investor Mid Europa Partners. The transfer of E.ON’s 50.1- percent stake became effective on October 2, 2007. In the fourth quarter of 2007, E.ON realized cash proceeds of €569 million from the sale, including the consideration for the shareholder loans granted, as well as a disposal gain of €321 million.

RAG On August 7, 2007, E.ON, ThyssenKrupp and RWE came to an agreement with the foundation “RAG- Stiftung” to sell their shares of RAG AG (“RAG”), Essen, Germany, to that foundation. The three shareholding companies held a total of 90 percent of the share capital of RAG. The block of E.ON shares was transferred on November 30, 2007, for a price of €1.

The following were the effects arising from discontinued operations:

WKE Through Western Kentucky Energy Corp. (“WKE”), Henderson, Kentucky, U.S., E.ON U.S. has a 25-year lease on and operates the generating facilities of Big Rivers Electric Corporation (“BREC”), a power generation cooperative in western Kentucky, and a coal-fired facility owned by the city of Henderson, Kentucky, U.S.

In March 2007, E.ON U.S. entered into a termination agreement with BREC to terminate the lease and the operational agreements for nine coal-fired and one oil-fired electricity generation units in western Kentucky, which were all held through its wholly-owned company WKE and its subsidiaries.

The closing of the agreement is subject to a number of conditions, including review and approval by various regulatory agencies and acquisition of certain consents by other interested parties. Subject to such contingencies, the parties are working on completing the termination transaction by mid-2008. WKE therefore continued to be classified as a discontinued operation.

F-29 The tables below provide selected financial information from the discontinued WKE operations in the U.S. Midwest segment for the periods indicated: Selected Financial Information—WKE (Summary)

€ in millions 2007 2006 Sales ...... 204 227 Other income/(expenses), net ...... (338) (129) Income from continuing operations before income taxes and minority interests .. (134) 98 Income taxes ...... 53 (34) Income from discontinued operations ...... (81) 64

Major Balance Sheet Line Items—WKE (Summary)

December 31 January 1 € in millions 2007 2006 2006 Property, plant and equipment ...... 202 215 211 Other assets ...... 362 396 471 Total assets ...... 564 611 682 Total liabilities ...... 613 615 836

In addition, there were other gains from discontinued operations recognized in 2007. These relate to €418 million in intercompany gains from the sale of tranches of Degussa shares to RAG from previous years and arose from the transfer to RAG-Stiftung on November 30, 2007, of E.ON’s shareholding in RAG. Moreover, there were €6 million in gains from the discontinued operations of the Company’s former Viterra segment, which had already been disposed of in 2005, as well as a loss of €13 million from the sale of the former Oil segment.

Acquisitions in 2006 JCˇ P/DDGáz In the course of portfolio adjustments undertaken in the Czech Republic and Hungary, minority shareholdings in various companies were sold. In exchange, E.ON acquired, in addition to two other minority shareholdings, a further 46.7 percent of the company Jihocˇeská plynárenská, a.s. (“JCˇ P”), Cˇ eské Budeˇjovice, Czech Republic, in which E.ON previously held a 13.1 percent share. This company was fully consolidated as of September 1, 2006. An additional 39.2 percent interest was acquired in a separate transaction, which also took place in September. E.ON thus held 99.0 percent of JCˇ P. The remaining stake in JCˇ P was purchased in 2007.

As part of the portfolio adjustment, an additional 49.9 percent interest was acquired in the fully consolidated company Dél-dunántúli Gázszolgáltató ZRt. (“DDGáz”), Pécs, Hungary, in which E.ON previously held 50.02 percent interest. As a result E.ON held 99.9 percent of DDGáz.

The exchange transaction resulted in total acquisition costs of €104 million, taking into account a total cash component of €30 million. The gains on the disposal of the minority interests totaled €31 million.

F-30 E.ON Földgáz Storage/E.ON Földgáz Trade As of March 31, 2006, E.ON Ruhrgas had acquired a 100 percent interest in the gas trading and storage business of the Hungarian oil and gas company MOL through the acquisition of interests in MOL Földgázellátó ZRt. (now E.ON Földgáz Storage) and MOL Földgáztároló ZRt. (now E.ON Földgáz Trade), both of Budapest, Hungary. The purchase price was approximately €400 million. It had been agreed that, contingent on regulatory developments in Hungary, compensatory payments may be required until the end of 2009. The companies were fully consolidated as of March 31, 2006. As of December 31, 2006, the purchase price allocation resulted in preliminary goodwill of €119 million, which in 2007 was adjusted by €9 million to €110 million.

Disposals and Discontinued Operations in 2006 The following were reported as discontinued operations in 2006: E.ON Finland, Espoo, Finland, (“E.ON Finland”) in the Nordic market unit, the operations of WKE in the U.S. Midwest market unit, and Degussa. In addition, E.ON recorded a gain of approximately €54 million (net of tax: €53 million) in 2006 from a purchase price adjustment on the disposal of Viterra.

E.ON Finland On June 26, 2006, E.ON Nordic and the Finnish energy group Fortum Power and Heat Oy (“Fortum”) finalized the transfer to Fortum of all of E.ON Nordic’s shares in E.ON Finland pursuant to an agreement signed on February 2, 2006. The purchase price for the 65.56 percent stake totaled approximately €390 million. E.ON Finland was classified as a discontinued operation in mid-January 2006.

The table below provides selected financial information from the discontinued operations of the Nordic segment for the periods indicated: Selected Financial Information—E.ON Finland (Summary)

€ in millions 2006 Sales ...... 131 Gain on disposal, net ...... 11 Other income/(expenses), net ...... (115) Income from continuing operations before income taxes and minority interests ...... 27 Income taxes ...... (7) Income from discontinued operations ...... 20

Degussa In December 2005, E.ON and RAG signed a framework agreement on the sale of E.ON’s 42.9 percent stake in Degussa to RAG. As part of the implementation of that framework agreement, E.ON transferred its stake in Degussa into RAG Projektgesellschaft mbH, Essen, Germany on March 21, 2006. E.ON’s stake in this entity was forward sold to RAG on the same date. On July 3, 2006, E.ON and RAG executed the forward sales agreement for E.ON’s stake in RAG Projektgesellschaft mbH. Thus E.ON has sold its entire remaining, indirectly held stake in Degussa.

RAG paid E.ON the roughly €2.8 billion purchase price on August 31, 2006. The transaction initially resulted in a gain of €981 million, which subsequently had to be adjusted for the intercompany gain attributable to E.ON’s minority ownership interest in RAG (39.2 percent). An initial gain of €596 million was thus realized from the transfer and the subsequent sale.

F-31 As the interest in Degussa qualified as a discontinued operation under IFRS 5, “Non-current Assets Held for Sale and Discontinued Operations” (“IFRS 5”), until its disposal, this gain, together with the effect of the equity- method measurement of Degussa in the first quarter of 2006 of €37 million was reported as income from discontinued operations in E.ON’s Consolidated Financial Statements. In total, income of €633 million was recognized for Degussa.

Intercompany gains arising from the sale of tranches of Degussa shares to RAG totaled €418 million as of December 31, 2006.

(5) REVENUES Revenues are generally recognized upon delivery of products to customers or upon fulfillment of services. Delivery is considered to have occurred when the risks and rewards associated with ownership have been transferred to the buyer, compensation has been contractually established and collection of the resulting receivable is probable.

Revenues are generated primarily from the sale of electricity and gas to industrial and commercial customers and to retail customers. Additional revenue is earned from the distribution of gas and electricity and deliveries of steam and heat.

Revenues from the sale of electricity and gas to industrial and commercial customers and to retail customers are recognized when earned on the basis of a contractual arrangement with the customer; they reflect the value of the volume supplied, including an estimated value of the volume supplied to customers between the date of their last meter reading and period-end.

The classification of revenues by segment is presented in Note 33.

(6) OWN WORK CAPITALIZED Own work capitalized amounted to €517 million in 2007 (2006: €395 million) and resulted primarily from engineering services rendered in connection with new construction projects.

(7) OTHER OPERATING INCOME AND EXPENSES The table below provides details of other operating income for the periods indicated:

Other Operating Income

€ in millions 2007 2006 Income from exchange rate differences ...... 3,284 4,439 Gain on derivative financial instruments ...... 1,767 1,087 Gain on disposal of investments ...... 1,588 981 Other trade income ...... 232 169 Miscellaneous ...... 905 1,238 Total ...... 7,776 7,914

Realized gains from currency derivatives and the effects of positive exchange rate differences recognized in income are reported as income from exchange rate differences.

Gains on derivative financial instruments include the gains recognized as a result of the required marking to market and realized gains from derivatives under IAS 39, except for the income effects from interest rate derivatives.

F-32 Gains on the disposal of investments included proceeds from the sale of ONE in the amount of €321 million. The line item further included gains realized on the sale of securities in the amount of €1,128 million (2006: €613 million). In 2006, this line item also included gains from the disposal of institutional securities funds as part of the transfer to the Contractual Trust Arrangement (“CTA”) in the amount of €159 million (see also Note 24).

Miscellaneous other operating income in 2007 consisted primarily of reductions of valuation allowances on accounts receivable, rental and leasing income, the sale of scrap metal and materials, as well as compensation payments received for damages.

The following table provides details of other operating expenses for the periods indicated:

Other Operating Expenses

€ in millions 2007 2006 Loss from exchange rate differences ...... 3,218 4,447 Loss on derivative financial instruments ...... 1,331 3,052 Taxes other than income taxes ...... 216 190 Loss on disposal of investments ...... 138 125 Miscellaneous ...... 4,821 4,093 Total ...... 9,724 11,907

Realized losses from currency derivatives and the effects of negative exchange rate differences recognized in income are reported as losses from exchange rate differences.

Losses on derivative financial instruments include losses recognized as a result of the required marking to market and realized losses from derivatives under IAS 39, except for the income effects from interest rate derivatives.

Miscellaneous other operating expenses in 2007 consisted primarily of concession payments in the amount of €471 million (2006: €512 million), expenses for external audit and nonaudit services and consulting in the amount of €414 million (2006: €263 million), advertising and marketing expenses in the amount of €360 million (2006: €281 million), as well as write-downs of receivables in the amount of €333 million (2006: €293 million). Additionally reported in this item are services rendered by third parties, IT expenditures and insurance premiums.

(8) COST OF MATERIALS The principal components of expenses for raw materials and supplies and for purchased goods are the purchase of gas and electricity and of fuels for electricity generation, as well as the nuclear segment. Expenses for purchased services consist primarily of maintenance costs. Network usage charges are also included in the cost of materials.

Cost of Materials

€ in millions 2007 2006 Expenses for raw materials and supplies and for purchased goods ...... 47,667 44,171 Expenses for purchased services ...... 2,556 2,537 Total ...... 50,223 46,708

F-33 (9) FINANCIAL RESULTS The following table provides details of financial results for the periods indicated:

Financial Results

€ in millions 2007 2006 Income from companies in which equity investments are held ...... 215 209 Impairment of other financial assets ...... (36) (159) Income from equity investments ...... 179 50 Available for sale ...... 207 216 Loans and receivables ...... 696 779 Held for trading ...... 51 53 Other interest income ...... 81 121 Income from securities, interest and similar income ...... 1,035 1,169 Amortized cost ...... (929) (988) Held for trading ...... (78) (142) Other interest expenses ...... (979) (1,084) Interest and similar expenses ...... (1,986) (2,214) Net interest income ...... (951) (1,045) Financial results ...... (772) (995)

The measurement categories are described in detail in Note 2.

Reduced impairments of minority shareholdings and lower interest expenses led to a significant improvement in financial results for 2007 as compared with the previous year.

A total of €140 million in impairment charges that arose in connection with changes in network regulation on minority interests in Germany were recognized in 2006 as impairments of other financial assets.

Net interest and similar expenses improved in 2007 primarily as a result of an increase in expected returns on plan assets determined in connection with the measurement of the provisions for pensions and similar obligations.

Other interest income consists mostly of the income from lease receivables (finance leases). Other interest expense includes accretion of provisions for asset retirement obligations in the amount of €708 million (2006: €713 million).

Also included in this item is the interest expense from provisions for pensions—net of the expected return on plan assets—in the amount of €79 million (2006: €242 million).

The accretion of liabilities in connection with put options resulted in an expense of €22 million (2006: €102 million) pursuant to IAS 32.

Interest expense was reduced by capitalized interest on debt totaling €62 million (2006: €27 million).

Realized gains and losses from interest rate swaps are shown net.

F-34 (10) INCOME TAXES The following table provides details of income taxes, including deferred taxes, for the periods indicated:

Income Taxes

€ in millions 2007 2006 Current taxes Domestic corporate income tax ...... 931 (407) Domestic trade tax ...... 735 354 Foreign income taxes ...... 648 553 Other income taxes ...... 10 5 Total ...... 2,324 505 Deferred taxes Domestic ...... (149) (61) Foreign ...... 114 (404) Total ...... (35) (465) Total Income Taxes ...... 2,289 40

The increase in tax expense of €2,249 million compared with 2006 primarily reflects the special effect of first-time capitalization of discounted corporate tax credits which in 2006 had produced tax income of €1,279 million. The remainder of the increase is attributable to increased earnings.

The Corporate Tax Reform Act of 2008, which took effect on August 18, 2007, provides for extensive tax changes in Germany. In particular, the corporate income tax rate is cut from 25 percent in 2007 to 15 percent in 2008, while the average domestic trade tax rises from 13 percent in 2007 to 14 percent in 2008. The solidarity surcharge remains unchanged at 5.5 percent of the corporate income tax rate. The change in the overall tax rate from the previous rate of 39 percent to 30 percent necessitates a revaluation of all domestic deferred tax assets and deferred tax liabilities as of December 31, 2007. This revaluation in 2007 produced non-cash deferred tax income in the amount of €59 million.

German legislation providing for fiscal measures to accompany the introduction of the European Company and amending other fiscal provisions (“SE-Steuergesetz” or “SEStEG”), which came into effect on December 13, 2006, altered the regulations on corporate tax credits arising from the corporate imputation system (“Anrechnungsverfahren”), which had existed until 2001. The change de-links the corporate tax credit from distributions of dividends. Instead, after December 31, 2006, an unconditional claim for payment of the credit in ten equal annual installments from 2008 through 2017 has been established. While the recognition of the discounted credits resulted in tax income of €1,279 million in 2006, the change in corporate tax credits resulted in tax income of €75 million in 2007.

With the entry into force on December 29, 2007, of the Annual Tax Act of 2008 in Germany, those currently untaxed income components that until then had been recognized in a type of equity called “EK 02” now have to be declared retrospectively irrespective of distributions. Taxes on this income must be paid in up to ten equal annual installments, with the first payment due on September 30, 2008. This so-called corporate income tax surcharge is equal to 3 percent of the EK 02 calculated as of December 31, 2006. This produces a gross amount of €88 million. A one-time payment option is also available. Assuming a scheduled payment on September 30, 2008, the tax expense for 2007 is €70 million.

No deferred tax liabilities were recognized in 2006 for the differences between net assets and the tax bases of subsidiaries and associated companies (the so-called “outside basis differences”). As of December 31, 2007,

F-35 deferred tax liabilities amounted to €7 million. Deferred tax liabilities were not recognized for subsidiaries and associated companies to the extent that the Company can control the reversal effect and insofar as it is probable that temporary differences will not be reversed in the foreseeable future. No deferred tax liabilities were recognized for temporary differences of €1,646 million (2006: €1,335 million) at subsidiaries and associated companies, as E.ON is able to control the timing of their reversal and the temporary difference will not reverse in the foreseeable future.

Changes in tax rates in the United Kingdom, the Czech Republic and a number of other countries resulted in deferred tax income of €118 million. In 2006, changes in foreign tax rates produced total deferred tax income of €21 million.

The differences between the 2007 base income tax rate of 39 percent (2006: 39 percent) applicable in Germany and the effective tax rate are reconciled as follows: Reconciliation to Effective Income Taxes/Tax Rate

2007 2006 € in millions % € in millions % Expected corporate income tax ...... 3,776 39.0 2,085 39.0 Credit for dividend distributions ...... (75) (0.8) (76) (1.4) Foreign tax rate differentials ...... (405) (4.2) (71) (1.3) Changes in tax rate/tax law ...... (177) (1.8) (21) (0.4) Tax effects on tax-free income ...... (790) (8.2) (491) (9.2) Tax effects on equity accounting ...... (353) (3.6) (227) (4.2) Other (1) ...... 313 3.2 (1,159) (21.7) Effective income taxes/tax rate ...... 2,289 23.6 40 0.8

(1) Income from capitalization of corporate tax credits in 2006: €(1,279) million.

As discussed in Note 4, the corporate income taxes relating to discontinued operations are reported in E.ON’s Consolidated Statement of Income under “Income/Loss from discontinued operations, net,” and break down as follows: Income Taxes from Discontinued Operations

€ in millions 2007 2006 WKE...... (53) 34 E.ON Finland ...... — 7 Viterra ...... — 1 Total ...... (53) 42

Income from continuing operations before income taxes and minority interests was attributable to the following geographic locations in the periods indicated:

€ in millions 2007 2006 Domestic ...... 5,500 3,463 Foreign ...... 4,183 1,884 Total ...... 9,683 5,347

F-36 Deferred tax assets and liabilities as of December 31, 2007, and December 31, 2006, break down as shown in the following table: Deferred Tax Assets and Liabilities

December 31 € in millions 2007 2006 Intangible assets ...... 73 62 Property, plant and equipment ...... 608 647 Financial assets ...... 138 209 Inventories ...... 9 12 Receivables ...... 70 397 Provisions ...... 3,107 4,209 Liabilities ...... 2,070 2,418 Net operating loss carryforwards ...... 452 613 Tax credits ...... 81 38 Other ...... 163 187 Subtotal ...... 6,771 8,792 Valuation allowance ...... (212) (435) Deferred tax assets ...... 6,559 8,357 Intangible assets ...... 1,033 1,101 Property, plant and equipment ...... 6,501 6,547 Financial assets ...... 1,727 1,977 Inventories ...... 176 246 Receivables ...... 1,946 2,076 Provisions ...... 443 502 Liabilities ...... 253 178 Other ...... 880 1,546 Deferred tax liabilities ...... 12,959 14,173 Net deferred tax assets/liabilities (–) ...... (6,400) (5,816)

Of the deferred taxes reported, a total of €2,246 million was charged directly to equity in 2007 (2006: €2,223 million).

Net deferred taxes break down as follows based on the timing of their reversal:

Net Deferred Tax Assets and Liabilities

December 31, 2007 December 31, 2006 € in millions current non-current current non-current Deferred tax assets ...... 298 1,069 254 1,428 Changes in value ...... (4) (208) (11) (424) Net deferred tax assets ...... 294 861 243 1,004 Deferred tax liabilities ...... (712) (6,843) (568) (6,495) Net deferred tax assets/liabilities (–) ...... (418) (5,982) (325) (5,491)

In the acquisition of OGK-4, the purchase price allocation resulted in deferred tax liabilities of €529 million as of December 31, 2007. The purchase price allocation for E2-I resulted in deferred tax liabilities of €148 million as of December 31, 2007.

F-37 The purchase price allocations of other acquisitions resulted in the recognition on December 31, 2007, of a total of €19 million in deferred tax liabilities.

The acquisitions of DDGáz, E.ON Földgáz Trade, E.ON Földgáz Storage, Somet and E.ON Värme resulted in the recognition on December 31, 2006, of a total of €6 million in deferred tax assets and €27 million in deferred tax liabilities.

The tax loss carryforwards as of the dates indicated are as follows: Tax Loss Carryforwards

December 31 € in millions 2007 2006 Domestic tax loss carryforwards ...... 1,646 2,016 Foreign tax loss carryforwards ...... 739 956 Total ...... 2,385 2,972

Since January 1, 2004, domestic tax loss carryforwards can only be offset against up to 60 percent of taxable income, subject to a full offset against the first €1 million. This minimum corporate taxation also applies to trade tax loss carryforwards.

Of the tax credits for which no deferred taxes have been recognized, €12 million expire after 2012.

(11) PERSONNEL-RELATED INFORMATION Personnel Costs The following table provides details of personnel costs for the periods indicated:

Personnel Costs

€ in millions 2007 2006 Wages and salaries ...... 3,692 3,553 Social security contributions ...... 556 580 Pension costs and other employee benefits ...... 349 396 Pension costs ...... 327 377 Total ...... 4,597 4,529

In 2007, E.ON purchased on the market a total of 373,905 of its own shares (0.05 percent of the shares of E.ON AG) for resale to employees as part of the employee stock purchase program at an average purchase price of €121.10 per share (in 2006, treasury share usage: 443,290 shares; 0.06 percent). These shares were sold to employees at preferential prices between €45.20 and €104.64 (2006: between €38.37 and €74.77). The costs arising from the granting of these preferential prices were charged to personnel costs as “wages and salaries.” Further information about the changes in the number of its own shares held by E.ON AG can be found in Note 19.

Since the 2003 fiscal year, employees in the U.K. have the opportunity to purchase E.ON shares through an employee stock purchase program and to acquire additional bonus shares. The cost of issuing these bonus shares is also recorded under personnel costs as part of “Wages and salaries.”

F-38 Share-Based Payment Members of the Board of Management of E.ON AG and certain executives of E.ON AG and of the market units receive share-based payment as part of their long-term variable compensation. Share-based payment can only be granted if the qualified executive owns a certain minimum number of shares of E.ON stock, which must be held until maturity or full exercise. The purpose of such compensation is to reward their contribution to E.ON’s growth and to further the long-term success of the Company. This variable compensation component, comprising a long-term incentive effect along with a certain element of risk, provides for a sensible linking of the interests of shareholders and management.

The following discussion includes a report on the E.ON AG Stock Appreciation Rights plan, which ended in 2005, and on the E.ON Share Performance Plan, newly introduced in 2006.

Stock Appreciation Rights of E.ON AG From 1999 up to and including 2005, E.ON annually granted virtual stock options (“Stock Appreciation Rights” or “SAR”) through the E.ON AG Stock Appreciation Rights program. The third tranche of SAR was exercised in full in 2007. SAR from the fourth through seventh tranches may still be exercised after the end of the program, in accordance with the SAR terms and conditions.

Stock Appreciation Rights of E.ON AG

7th tranche 6th tranche 5th tranche 4th tranche 3rd tranche Date of issuance ...... Jan. 3, 2005 Jan. 2, 2004 Jan. 2, 2003 Jan. 2, 2002 Jan. 2, 2001 Term ...... 7years 7 years 7 years 7 years 7 years Blackout period ...... 2years 2 years 2 years 2 years 2 years Price at issuance (1) ...... €61.10 €44.80 €37.86 €50.70 €58.70 Level of the Dow Jones STOXX Utilities Index (Price EUR) ...... 268.66 211.58 202.14 262.44 300.18 Number of participants in year of issuance ...... 357 357 344 186 231 Number of SAR issued ...... 2.9m 2.7m 2.6m 1.7m 1.8m Exercise hurdle (minimum percentage by which exercise price exceeds the price at issuance) ...... 10% 10% 10% 10% 20% Exercise hurdle (minimum exercise price) (1) ...... €67.21 €49.28 €41.65 €55.77 €70.44 Maximum exercise gain ...... €65.35 €49.05 — — — (1) Adjusted for special dividend distribution in 2006.

SAR can be exercised by eligible executives following the blackout period within preset exercise windows, provided that the exercise thresholds have been crossed.

The amount paid to executives when they exercise their SAR is paid out in cash, and is equal to the difference between the E.ON AG share price at the time of exercise and the underlying share price at issuance multiplied by the number of SAR exercised. Beginning with the sixth tranche, a cap on gains on SAR equal to 100 percent of the underlying price at the time of issuance was put in place in order to limit the effect of unforeseen extraordinary increases in the underlying share price. This cap on gains took effect for the first time in the 2006 fiscal year.

In accordance with IFRS 2 measurement criteria, the SAR were measured by reference to the fair value of the rights as of December 31, 2007.

F-39 A recognized option pricing model is used for measuring the value of these options. This option pricing model simulates a large number of different possible developments of the E.ON share price and the benchmark Dow Jones STOXX Utilities Index (Price EUR) (Monte Carlo simulation).

A certain exercise behavior is assumed when determining fair value. Individual exercise rates are defined for each of the tranches, depending on the price performance of the E.ON share. Historical volatility and correlations of the E.ON share price and of the benchmark index that reflect remaining maturities are used in the calculations. The risk-free interest rate used for reference is the zero swap rate for the corresponding remaining maturity. The dividend yields of the E.ON share (2.30 percent) and of the benchmark index (3.18 percent) are also included in the pricing model. The dividend yield used for the E.ON share in the calculations is based on the ratio of the most recent dividend distributed and the share price on the valuation date. Accordingly, as of the balance sheet date, this yield corresponds approximately to the anticipated future dividend yield. The average of the Xetra closing prices for E.ON AG shares was €118.08 in 2007. The Xetra closing price for E.ON AG shares at year-end was €145.59. The Dow Jones STOXX Utilities Index (Price EUR) closed at 549.75 points.

The following overview contains additional parameters used for measurement:

SAR Program of E.ON AG—Measurement Parameters of the Option Pricing Model

7th tranche 6th tranche 5th tranche 4th tranche Intrinsic value as of December 31, 2007 ...... €65.35 €49.05 €107.73 €94.89 Fair value as of December 31, 2007 ...... €64.09 €48.64 €104.39 €93.81 Swap rate ...... 4.43% 4.42% 4.45% 4.55% Volatility of the E.ON share ...... 25.61% 25.47% 24.44% 21.97% Volatility of the Dow Jones STOXX Utilities Index (Price EUR) ...... 14.74% 14.78% 14.54% 13.78% Correlation between the E.ON share price and the Dow Jones STOXX Utilities Index (Price EUR) ...... 0.7015 0.7191 0.7492 0.7845

2,902,786 SAR from tranches three through seven were exercised on an ordinary basis in 2007. In addition, 100,349 SAR from tranches three, four, five, and seven were exercised in accordance with the SAR terms and conditions on an extraordinary basis. The total gain to the holders on exercise amounted to €163.2 million (2006: €134.4 million). 7,000 SAR from tranche three expired during 2007.

The provision for the SAR program was €23.2 million as of the balance sheet date (2006: €143.1 million). The expense for the 2007 fiscal year amounted to €43.4 million (2006: €113.0 million).

F-40 The number of SAR, provisions for and expenses arising from the E.ON SAR program have changed as shown in the following table:

Changes in the E.ON AG SAR Program

7th tranche 6th tranche 5th tranche 4th tranche 3rd tranche SAR outstanding as of December 31, 2005 ...... 2,885,428 2,417,995 613,711 238,909 158,750 SAR granted in 2006 ...... — — — — — SAR exercised in 2006 ...... 49,511 2,349,731 346,358 169,742 85,750 SAR expired in 2006 ...... 26,041 13,717 2,423 — — SAR outstanding as of December 31, 2006 ..... 2,809,876 54,547 264,930 69,167 73,000 SAR granted in 2007 ...... — — — — — SAR exercised in 2007 ...... 2,754,876 26,547 113,379 42,333 66,000 SAR expired in 2007 ...... — — — — 7,000 SAR outstanding as of December 31, 2007 ..... 55,000 28,000 151,551 26,834 — Gains on exercise in 2007 ...... €145.3 m €1.3 m €9.2 m €2.8 m €4.6 m Provision as of December 31, 2007 ...... €3.5 m €1.4 m €15.8 m €2.5 m €0.0 m Expense in 2007 ...... €31.2 m €0.1 m €8.7 m €2.0 m €1.4 m

The SAR of tranches four through seven were exercisable on December 31, 2007.

E.ON Share Performance Plan In 2007, virtual shares (“Performance Rights”) from the second tranche of the E.ON Share Performance Plan were granted. For the first time, certain members of senior management were also granted Performance Rights alongside top management.

E.ON Share Performance Rights

2nd tranche 1st tranche Date of issuance ...... Jan. 1, 2007 Jan. 1, 2006 Term ...... 3years 3 years Target value at issuance ...... €96.52 €79,22 Number of participants in year of issuance ...... 501 396 Number of Performance Rights issued ...... 395,025 458,641 Maximum amount paid ...... €289.56 €237.66

At the end of its three-year term, each Performance Right is entitled to a cash payout linked to the final E.ON share price established at that time. The amount of the payout is also linked to the relative performance of the E.ON share price in comparison with the benchmark index Dow Jones STOXX Utilities Index (Total Return EUR). The amount paid out is equal to the target value of this compensation component if the E.ON share price at the end of the term is equal to the initial price at the beginning of the term and the performance matches that of the benchmark. The maximum amount to be paid out to each participant per Performance Right is limited to three times the original target value on the grant date.

60-day average prices are used to determine the initial price, the final price and the relative performance, in order to mitigate the effects of incidental, short-lived price movements.

The calculation of the amount to be paid out takes place at the same time for all plan participants with effect on the last day of the term of the tranche. If the performance of the E.ON share matches that of the index, the

F-41 amount paid out is not adjusted; the final share price is paid out. However, if the E.ON share outperforms the index, the amount paid out is increased proportionally. If, on the other hand, the E.ON share underperforms the index, disproportionate deductions are made. In the case of underperformance by 20 percent or more, no payment at all takes place.

The plan contains adjustment mechanisms to eliminate the effect of events such as interim corporate actions. Accordingly, to compensate for the economic effects of the special dividend payment of May 5, 2006, capital adjustment factors were established for the first tranche.

The fair value is determined for the Performance Rights in accordance with IFRS 2 using a recognized option pricing model. Similar to the option pricing model used for the SAR program, this model involves the simulation of a large number of different possible development tracks for the E.ON share price (taking into account the effects of reinvested dividends and capital adjustment factors) and the benchmark index (Monte Carlo simulation). However, unlike the SAR program, the benchmark for this plan is the Dow Jones STOXX Utilities Index (Total Return EUR), which stood at 968.95 points on December 31, 2007. Since payments to all plan participants take place on a specified date, no assumptions concerning exercise behavior are made in this plan structure, and such assumptions are therefore not considered in this option pricing model. Dividend payments and corporate actions are taken into account through corresponding factors that are analogous to those employed by the index provider.

E.ON Share Performance Plan—Measurement Parameters of the Option Pricing Model

2nd tranche 1st tranche Intrinsic value as of December 31, 2007 ...... €162.93 €157.47 Fair value as of December 31, 2007 ...... €163.59 €158.72 Swap rate ...... 4.45% 4.55% Volatility of the E.ON share ...... 21.73% 21.56% Volatility of the Dow Jones STOXX Utilities Index (Total Return EUR) . . . 13.46% 13.81% Correlation between the E.ON share price and the Dow Jones STOXX Utilities Index (Total Return EUR) ...... 0.7977 0.8056

395,025 second-tranche Performance Rights were granted in 2007. In 2007, the cash amount from 15,500 of the first and second tranches of Performance Rights was paid out on an extraordinary basis in accordance with the terms and conditions of the plan. Total payments amounted to €1.6 million (2006: €0.1 million). 4,349 first and second-tranche Performance Rights expired in the 2007 fiscal year. Provisions for the plan totaled €67.8 million at year-end (2006: €8.9 million). Each provision is prorated for the respective period elapsed of the total three-year term. The total expense for the E.ON Share Performance Plan amounted to €60.5 million in 2007 (2006: €9.0 million).

Changes in the E.ON Share Performance Plan

2nd tranche 1st tranche Performance Rights granted in 2006 ...... — 458,641 Settled Performance Rights in 2006 ...... — 2,020 Performance Rights expired in 2006 ...... — 2,020 Performance Rights outstanding as of December 31, 2006 ...... — 454,601 Performance Rights granted in 2007 ...... 395,025 — Settled Performance Rights in 2007 ...... 4,458 11,042 Performance Rights expired in 2007 ...... 1,658 2,691 Performance Rights outstanding as of December 31, 2007 ...... 388,909 440,868 Cash amount paid in 2007 ...... €0.6 m €1.0 m Provision as of December 31, 2007 ...... €21.2 m €46.6 m Expense in 2007 ...... €21.7 m €38.8 m

F-42 The first and second tranches were not yet payable on an ordinary basis on the balance sheet date.

The issue of a third tranche of the E.ON Share Performance Plan is planned for 2008.

Employees During 2007, the Company employed an average of 83,434 people (2006: 80,453), not including 2,352 apprentices (2006: 2,280). The breakdown by market unit is shown below:

Employees

2007 2006 Central Europe ...... 44,054 44,148 Pan-European Gas ...... 12,204 12,653 U.K...... 16,499 14,599 Nordic ...... 5,872 5,697 U.S. Midwest ...... 2,940 2,919 Corporate Center/New Markets ...... 1,865 437 Total ...... 83,434 80,453

(12) OTHER INFORMATION German Corporate Governance Code On December 17, 2007, the Board of Management and Supervisory Board of E.ON AG made a declaration of compliance pursuant to Article 161 of the German Stock Corporation Act (“AktG”). The declaration was made publicly accessible on E.ON’s Web site (www.eon.com).

Fees and Services of the Independent Auditor During 2007 and 2006, the Company incurred the following fees for services provided by its independent auditor, PwC:

Independent Auditor Fees

€ in millions 2007 2006 Financial statement audits ...... 33 33 Other attestation services ...... 22 25 Tax advisory services ...... 1 1 Other services ...... 1 2 Total ...... 57 61

The fees for the financial statement audits concern the audit of the Consolidated Financial Statements and the legally mandated financial statements of E.ON AG and its affiliates. This item also includes the additional fees charged for the audit of internal controls over financial reporting.

Fees for other attestation services concern in particular the review of the interim IFRS financial statements and, in 2006, the review of the conversion to IFRS. Further included in this item are project-related reviews connected to the introduction of IT and internal-control systems, due-diligence services rendered in connection with acquisitions and disposals, and other specific items.

F-43 Fees for tax advisory services primarily include advisory on a case-by-case basis with regard to the tax treatment of M&A transactions, ongoing consulting related to preparing tax returns and review of tax assessments, as well as advisory on other tax-related issues, both in Germany and abroad.

Fees for other services consist primarily of technical support in IT projects, technical training measures and regulatory matters.

Shareholdings and Other Interests A listing of all shareholdings and other interests of E.ON AG has been compiled and will be published separately in the Electronic Federal Gazette (“elektronischer Bundesanzeiger”) in Germany. That listing also contains those shareholdings for which the preparation and publication of consolidated financial statements and of a corresponding management report under Articles 264 (3) and 264b HGB, respectively, is not required.

(13) EARNINGS PER SHARE The computation of basic and diluted earnings per share for the periods indicated is shown below:

Earnings per Share

€ in millions 2007 2006 Income/Loss (–) from continuing operations ...... 7,394 5,307 less: Minority interests ...... (520) (486) Income/Loss (–) from continuing operations (attributable to shareholders of E.ON AG) ...... 6,874 4,821 Income/Loss (–) from discontinued operations, net ...... 330 775 less: Minority interests ...... — (10) Income/Loss (–) from discontinued operations, net (attributable to shareholders of E.ON AG) ...... 330 765 Net income attributable to shareholders of E.ON AG ...... 7,204 5,586 in € Earnings per share (attributable to shareholders of E.ON AG) from continuing operations ...... 10.55 7.31 from discontinued operations ...... 0.51 1.16 from net income ...... 11.06 8.47 Weighted-average number of shares outstanding (in millions) ...... 651 659

The computation of diluted EPS is identical to basic EPS, as E.ON AG has not issued any potentially dilutive common stock.

F-44 [THIS PAGE INTENTIONALLY LEFT BLANK]

F-45 (14) GOODWILL, INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT Goodwill, Intangible Assets and Property, Plant and Equipment

Acquisition and production costs Change Exchange in scope January 1, rate of consoli- December 31, € in millions 2007 differences dation Additions Disposals Transfers 2007 Goodwill ...... 15,604 (822) 2,489 13 (10) (229) 17,045 Marketing-related intangible assets ...... 227 (4) — — (175) — 48 Customer-related intangible assets ...... 2,482 (98) 25 1 (2) 10 2,418 Contract-based intangible assets . . . 1,694 (22) 305 66 (12) (11) 2,020 Technology-based intangible assets ...... 503 (8) 10 49 (23) 68 599 Internally generated intangible assets ...... 218 (21) — 32 — — 229 Intangible assets subject to amortization ...... 5,124 (153) 340 148 (212) 67 5,314 Intangible assets not subject to amortization ...... 1,263 (43) — 990 (239) (400) 1,571 Advance payments on intangible assets ...... 15 — — 29 (1) (13) 30 Intangible assets ...... 6,402 (196) 340 1,167 (452) (346) 6,915 Real estate and leasehold rights .... 3,970 (119) 1 25 (61) 18 3,834 Buildings ...... 7,996 (163) 1,183 74 (146) 200 9,144 Technical equipment, plant and machinery ...... 80,098 (1,963) 1,901 2,327 (1,428) 1,468 82,403 Other equipment, fixtures, furniture and office equipment ...... 3,362 (141) (9) 276 (206) (70) 3,212 Advance payments and construction in progress ...... 2,088 (176) 1,001 3,961 (12) (1,190) 5,672 Property, plant and equipment ... 97,514 (2,562) 4,077 6,663 (1,853) 426 104,265

F-46 Net carrying Accumulated depreciation amounts Change Exchange in scope January 1, rate of consoli- December 31, December 31, 2007 differences dation Additions Disposals Transfers Impairment Reversals 2007 2007 (284) — — — — — — — (284) 16,761

(217) 4 — (9) 175 — — — (47) 1

(983) 56 — (198) — — — — (1,125) 1,293 (778) 14 (1) (42) 6 30 — — (771) 1,249

(365) 5 1 (78) 23 (34) — — (448) 151

(165) 16 — (24) 1 — — — (172) 57

(2,508) 95 — (351) 205 (4) — — (2,563) 2,751

— 2 — — — (4) (66) — (68) 1,503

——— ——— — — — 30 (2,508) 97 — (351) 205 (8) (66) — (2,631) 4,284 (252) 4 — (12) 3 — (1) 1 (257) 3,577 (4,117) 95 — (242) 117 (11) (5) 2 (4,161) 4,983

(48,264) 831 (50) (2,272) 781 (94) (17) 1 (49,084) 33,319

(2,371) 85 15 (218) 193 102 — — (2,194) 1,018

(26) 1 — — 8 10 (10) — (17) 5,655 (55,030) 1,016 (35) (2,744) 1,102 7 (33) 4 (55,713) 48,552

F-47 Goodwill, Intangible Assets and Property, Plant and Equipment

Acquisition and production costs Change Exchange in scope January 1, rate of consoli- December 31, € in millions 2006 differences dation Additions Disposals Transfers 2006 Goodwill ...... 15,792 (245) 74 56 (12) (61) 15,604 Marketing-related intangible assets ...... 223 4 — — — — 227 Customer-related intangible assets ...... 2,443 31 2 2 (5) 9 2,482 Contract-based intangible assets ...... 1,689 10 (24) 28 (18) 9 1,694 Technology-based intangible assets ...... 346 1 3 65 (32) 120 503 Internally generated intangible assets ...... 291 4 — 20 (2) (95) 218 Intangible assets subject to amortization ...... 4,992 50 (19) 115 (57) 43 5,124 Intangible assets not subject to amortization ...... 1,171 11 (39) 391 (244) (27) 1,263 Advance payments on intangible assets ..... 26 1 — 11 — (23) 15 Intangible assets ...... 6,189 62 (58) 517 (301) (7) 6,402 Real estate and leasehold rights ...... 4,030 86 (12) 55 (49) (140) 3,970 Buildings ...... 7,716 5 (59) 100 (24) 258 7,996 Technical equipment, plant and machinery . . 78,028 95 182 2,067 (1,169) 895 80,098 Other equipment, fixtures, furniture and office equipment ...... 3,343 26 (77) 243 (180) 7 3,362 Advance payments and construction in progress ...... 1,330 (27) 42 1,815 (32) (1,040) 2,088 Property, plant and equipment ...... 94,447 185 76 4,280 (1,454) (20) 97,514

F-48 Net carrying Accumulated depreciation amounts Change Exchange in scope January 1, rate of consoli- December 31, December 31, 2006 differences dation Additions Disposals Transfers Impairment Reversals 2006 2006 (298) — 14 — — — — — (284) 15,320 (123) (3) — (50) — — (41) — (217) 10 (782) (13) 9 (197) 1 (1) — — (983) 1,499 (601) (5) 12 (51) 8 (1) (140) — (778) 916 (267) (1) (3) (54) 31 (71) — — (365) 138 (209) (3) — (26) — 73 — — (165) 53

(1,982) (25) 18 (378) 40 — (181) — (2,508) 2,616

— — — — — — — — — 1,263 —— — — —— — — — 15 (1,982) (25) 18 (378) 40 — (181) — (2,508) 3,894 (333) (1) — (12) 2 96 (5) 1 (252) 3,718 (3,813) (8) 36 (216) 5 (96) (25) — (4,117) 3,879 (46,847) (64) 392 (2,275) 914 (29) (355) — (48,264) 31,834

(2,378) (20) 38 (205) 178 16 — — (2,371) 991

(9) 1 — — — — (18) — (26) 2,062 (53,380) (92) 466 (2,708) 1,099 (13) (403) 1 (55,030) 42,484

F-49 a) Goodwill and Other Intangible Assets Goodwill During the 2007 and 2006 fiscal years, the carrying amount of goodwill changed as follows in each of E.ON’s segments:

Changes in Goodwill by Segment

Corporate Pan- Center/ Central European U.S. New € in millions Europe Gas U.K. Nordic Midwest Markets Total Net carrying amount as of January 1, 2006 ...... 2,419 4,200 4,955 368 3,552 — 15,494 Changes resulting from acquisitions and divestments ...... 65 146 — 3 — — 214 Other changes (1) ...... 1 53 1 (73) (370) — (388) Net carrying amount as of December 31, 2006 ..... 2,485 4,399 4,956 298 3,182 — 15,320 Changes resulting from acquisitions and divestments ...... 17 15 — 2 — 2,458 2,492 Other changes (1) ...... (28) (39) (614) (12) (330) (28) (1,051) Net carrying amount as of December 31, 2007 ..... 2,474 4,375 4,342 288 2,852 2,430 16,761

(1) Other changes include transfers and exchange rate differences from the respective reporting year as well as reclassifications to discontinued operations (2006, Nordic segment: (€83 million)).

IFRS 3 prohibits the amortization of goodwill. Instead, goodwill is tested for impairment at least annually at the level of the cash-generating units. Goodwill must also be tested for impairment at the level of individual cash-generating units between these annual tests if events or changes in circumstances indicate that the recoverable amount of a particular cash-generating unit might be impaired.

To perform the impairment tests, the Company first determines the fair values less costs to sell of its cash- generating units, which are calculated based on discounted cash flow methods and verified through the use of suitable multiples. In addition, to the extent available, market transactions or valuations by third parties are taken into account for similar assets.

Valuation is based on the corporate planning authorized by the Board of Management. Underlying the calculations is a detailed forecasting period of five years, which extends to ten years in exceptional cases. The cash flow assumptions extending beyond the detailed forecasting period are determined using unit-specific growth rates that are based on historical analysis and prospective forecasting. The after-tax interest rates used for discounting cash flows are calculated on a unit-specific basis using market data, and as of December 31, 2007, ranged between 5.6 and 7.3 percent after taxes (2006: 5.4 to 7.8 percent).

Principal assumptions underlying the determination by management of fair value less costs to sell include forecasts of commodity market prices, of future electricity and gas prices in the wholesale and retail markets, of investment activity, and of changes in the regulatory framework as well as in rates of growth and discount rates.

As all the fair values less costs to sell of the cash-generating units exceeded their respective carrying amounts, no charges were recognized in 2007 or 2006 in connection with the testing of goodwill for impairment.

Intangible Assets In 2007, the Company recorded an aggregate amortization expense of €351 million (2006: €378 million). Impairment charges of €66 million on intangible assets were recognized in 2007 (2006: €181 million).

F-50 Intangible assets not subject to amortization include emission rights from a variety of trading systems with a carrying amount of €228 million (2006: €289 million).

Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for each of the five succeeding fiscal years is as follows:

Estimated Aggregated Amortization Expense

€ in millions 2008 ...... 335 2009 ...... 275 2010 ...... 211 2011 ...... 177 2012 ...... 151 Total ...... 1,149

As acquisitions and disposals occur in the future, actual amounts may vary.

b) Property, Plant and Equipment Borrowing costs in the amount of €62 million were capitalized in 2007 (2006: €27 million) as part of the historical cost of property, plant and equipment.

In 2007, the Company recorded depreciation of property, plant and equipment in the amount of €2,744 million (2006: €2,708 million). Impairment charges on property, plant and equipment amounted to €33 million (2006: €403 million). In 2006, the amount included €227 million in impairment charges for gas distribution network operations in Germany that resulted from the regulation of network charges. Reversals of impairments on property, plant and equipment amounted to €4 million in 2007 (2006: €1 million).

Restrictions on disposals of the Company’s property, plant and equipment exist in the amount of €5,228 million (2006: €4,236 million) mainly with regard to land, buildings and technical equipment.

Certain power plants, gas storage facilities and supply networks are utilized under finance leases and capitalized in the E.ON Consolidated Financial Statements because the economic ownership of the assets leased is attributable to E.ON.

The property, plant and equipment thus capitalized had the following carrying amounts as of December 31, 2007:

E.ON as Lessee—Carrying Amounts of Capitalized Lease Assets

December 31 € in millions 2007 2006 Land ...... — — Buildings ...... 2 3 Technical equipment, plant and machinery ...... 271 285 Other equipment, fixtures, furniture and office equipment ...... 2 6 Net carrying amount of capitalized lease assets ...... 275 294

F-51 The corresponding payment obligations under finance leases are due as shown below:

E.ON as Lessee—Payment Obligations Under Finance Leases

Minimum lease Covered Present payments interest share values € in millions 2007 2006 2007 2006 2007 2006 Due within 1 year ...... 56 58 17 15 39 43 Due in 1 to 5 years ...... 104 127 50 42 54 85 Due in more than 5 years ...... 288 295 188 203 100 92 Total ...... 448 480 255 260 193 220

The present value of the minimum lease obligations is reported primarily under liabilities from leases. A further €22 million (2006: €24 million) is included in financial liabilities to entities in which an ownership interest exists.

Regarding future obligations under operating leases where economic ownership is not transferred to E.ON as the lessee, see Note 27.

E.ON also functions in the capacity of lessor. The lease installments from operating leases are due as shown in the table at right:

E.ON as Lessor—Operating Leases

€ in millions 2007 Nominal value of outstanding lease installments Due within 1 year ...... 29 Due in 1 to 5 years ...... 87 Due in more than 5 years ...... 190 Total ...... 306

See Note 17 for information on receivables from finance leases.

(15) COMPANIES ACCOUNTED FOR UNDER THE EQUITY METHOD AND OTHER FINANCIAL ASSETS The following table shows the structure of the companies accounted for under the equity method and the other financial assets as of the dates indicated:

Companies Accounted for Under the Equity Method and Other Financial Assets

Dec. 31 Dec. 31 Jan. 1 € in millions 2007 2006 2006 Companies accounted for under the equity method ...... 8,411 7,770 9,507 Equity investments ...... 14,583 13,533 10,073 Equity investment in OAO Gazprom ...... 13,061 11,918 8,141 Non-current securities ...... 6,895 7,146 6,471 Total ...... 29,889 28,449 26,051

F-52 The amount shown for non-current securities relates primarily to fully marketable fixed-income securities.

In 2007, impairment charges on companies accounted for under the equity method amounted to €1 million (2006: €215 million) and impairments on other financial assets amounted to €28 million (2006: €152 million). In 2006, €335 million in impairment charges were related to equity method companies and minority shareholdings with network operations in Germany, and resulted from the regulation of network charges. The carrying amount of other financial assets with impairment losses was €524 million as of the end of the fiscal year (2006: €436 million).

€1,524 million (2006: €1,169 million) in non-current securities is restricted for the fulfillment of legal insurance obligations of VKE.

Shares in Associated Companies Accounted for Under the Equity Method The financial information below summarizes income statement and balance sheet data for the investments of the associated companies that are accounted for under the equity method.

Earnings Data for Companies Accounted for Under the Equity Method

€ in millions 2007 2006 Sales ...... 48,656 49,531 Net income/loss ...... 4,399 3,715

Investment income generated from associated companies accounted for under the equity method amounted to €1,019 million in 2007 (2006: €880 million).

Balance Sheet Data for Companies Accounted for Under the Equity Method

December 31 € in millions 2007 2006 Non-current assets ...... 24,940 42,011 Current assets ...... 14,353 27,034 Provisions ...... 8,636 23,114 Liabilities and deferred income ...... 15,280 26,381 Equity ...... 15,377 19,550

The carrying amount of associated companies accounted for under the equity method whose shares are marketable was €1,104 million in 2007 (2006: €973 million). The fair value of E.ON’s share in these companies was €2,284 million (2006: €2,401 million).

Additions of investments in associated companies accounted for under the equity method resulted in a total goodwill of €102 million in 2007 (2006: €54 million).

Investments in associated companies totaling €79 million (2006: €76 million) were restricted because they were pledged as collateral for financing as of the balance sheet date.

F-53 (16) INVENTORIES The following table provides details of inventories as of the dates indicated:

Inventories

December 31 € in millions 2007 2006 Raw materials and supplies ...... 1,946 2,144 Goods purchased for resale ...... 1,801 1,987 Work in progress and finished products ...... 64 68 Inventories ...... 3,811 4,199

Raw materials, goods purchased for resale and finished products are generally valued at average cost.

Write-downs totaled to €3 million in 2007 (2006: €6 million). Reversals of write-downs amounted to €5 million in 2007 (2006: €5 million). The carrying amount of inventories recognized at net realizable value was €183 million.

No inventories have been pledged as collateral.

(17) RECEIVABLES AND OTHER ASSETS The following table lists receivables and other assets by remaining time to maturity as of the dates indicated:

Receivables and Other Assets

December 31, 2007 December 31, 2006 € in millions current non-current current non-current Financial receivables from entities in which an ownership interest exists ...... 463 564 451 593 Accounts receivable from finance leases ...... 43 529 61 531 Other financial receivables and financial assets ...... 1,009 1,356 965 1,507 Financial receivables and other financial assets ...... 1,515 2,449 1,477 2,631 Operating receivables from entities in which an ownership interest exists ...... 842 4 1,018 28 Trade receivables ...... 9,064 — 9,760 — Receivables from derivative financial instruments ...... 5,232 328 4,714 4 Other operating assets ...... 2,835 348 2,565 341 Trade receivables and other operating assets ...... 17,973 680 18,057 373 Receivables and other assets ...... 19,488 3,129 19,534 3,004

As of December 31, 2007, other financial assets include receivables from owners of minority interests in jointly owned power plants of €518 million (2006: €609 million) and margin account deposits for futures trading of €262 million (2006: €135 million). In addition, in line with the application of IFRIC 5, other financial assets include a claim for a refund from the Swedish nuclear fund in the amount of €1,280 million (2006: €1,290 million) in connection with the decommissioning of nuclear power plants and nuclear waste disposal. Since this asset is designated for a particular purpose, E.ON’s access to it is restricted.

F-54 Other operating assets consist primarily of accrued interest receivables of €598 million (2006: €555 million).

The aging schedule of trade receivables is presented in the following table:

Aging Schedule of Trade Receivables

€ in millions 2007 2006 Total trade receivables ...... 9,064 9,760 Not impaired and not yet due ...... 6,874 7,113 Not impaired and up to 90 days past-due ...... 1,449 1,938 Not impaired and 91 to 180 days past-due ...... 285 192 Not impaired and 181 to 360 days past-due ...... 263 285 Not impaired and over 360 days past-due ...... 161 189 Net value of impaired receivables ...... 32 43

The individual impaired receivables are due from a large number of retail customers from whom it is unlikely that full repayment will ever be received. Receivables are monitored by the various market units. There are no indications that the carrying amounts reported are impaired.

Valuation allowances for trade receivables have changed as shown in the following table:

Valuation Allowances for Trade Receivables

€ in millions 2007 2006 Balance as of January 1 ...... (503) (394) Change in scope of consolidation ...... — 3 Write-downs ...... (333) (293) Reversals of write-downs ...... 64 54 Derecognition ...... 198 149 Other (1) ...... 18 (22) Balance as of December 31 ...... (556) (503)

(1) “Other” consists primarily of additions and currency translation differences.

Receivables from finance leases are primarily the result of certain electricity delivery contracts that must be treated as leases according to IFRIC 4. The nominal and present values of the outstanding lease payments have the following due dates:

E.ON as Lessor—Finance Leases

Present Gross value of investment in Unrealized minimum finance lease interest lease arrangements income payments € in millions 2007 2006 2007 2006 2007 2006 Due within 1 year ...... 104 102 44 35 60 67 Due in 1 to 5 years ...... 359 351 169 155 190 196 Due in more than 5 years ...... 879 1,007 429 547 450 460 Total ...... 1,342 1,460 642 737 700 723

F-55 Of the present value of the outstanding lease payments, €572 million (2006: €592 million) are reported as receivables from finance leases and 128 million (2006: €131 million) are reported as financial receivables from entities in which an ownership interest exists.

(18) LIQUID FUNDS The following table provides details of liquid funds ordered according to maturity as of the dates indicated:

Liquid Funds

December 31 € in millions 2007 2006 Securities and fixed-term deposits ...... 3,888 4,448 Current securities with an original maturity greater than 3 months ...... 2,862 4,399 Fixed-term deposits with an original maturity greater than 3 months ...... 1,026 49 Restricted cash ...... 300 587 Cash and cash equivalents ...... 2,887 1,154 Total ...... 7,075 6,189

Restricted cash, of which €12 million (2006: €18 million) has a maturity greater than three months, includes €67 million (2006: €74 million) in collateral deposited at banks, which serves to limit the utilization of credit lines in connection with the marking to market of derivatives transactions. In addition, current securities with an original maturity greater than three months include €578 million (2006: €566 million) in securities held by VKE that are restricted for the fulfillment of legal insurance obligations toward companies of the E.ON Group. Additional securities in the amount of €234 million (2006: €371 million) are restricted as collateral for financial transactions.

Cash and cash equivalents include checks, cash on hand and balances in Bundesbank accounts and at other credit institutions, as well as €2,847 million (2006: €1,115 million) in securities with an original maturity of less than three months, to the extent that they are not restricted.

(19) CAPITAL STOCK The Company’s authorized capital stock of €1,734,200,000 (2006: €1,799,200,000) consists of 667,000,000 (2006: 692,000,000) ordinary shares issued with no par value. The €65 million reduction in capital is due to the cancellation of 25,000,000 treasury shares in December 2007. The number of outstanding shares as of December 31, 2007, totaled 631,622,782 (2006: 659,597,269).

As of December 31, 2007, E.ON AG held a total of 6,905,024 treasury shares (2006: 3,930,537) having a consolidated book value of €616 million (equivalent to 1.03 percent or €17,953,062 of the capital stock). The increase in the number of treasury shares resulted from inflows of own shares that were purchased under the share buyback program and had not yet been cancelled as of the balance sheet date. 373,905 shares were purchased on the market for E.ON’s employee stock program and subsequently distributed to employees in 2007 (2006: distribution of 443,290 treasury shares). See also Note 11 with regard to the distribution of shares under the employee stock program. 457 treasury shares (2006: 427 shares) were also distributed to employees.

A further 28,472,194 shares of E.ON AG are held by one of its subsidiaries as of December 31, 2007 (2006: 28,472,194).

E.ON Energie AG acquired a total of 2,890 E.ON AG shares on the open market that were immediately tendered in lieu of payments to third parties.

F-56 The Company plans to buy back a total of €7 billion in shares of E.ON AG under the share buyback program. The goals of the share buyback are to optimize E.ON’s capital structure and to make E.ON stock more attractive. At the Annual Shareholders Meeting of May 3, 2007, the Board of Management was authorized to cancel treasury shares without requiring an additional shareholder resolution.

In its meeting of December 4, 2007, the Board of Management of E.ON AG resolved to cancel 25,000,000 of the shares acquired by the Company through its share buyback program. This was equivalent to 3.61 percent or €65 million of the capital stock of E.ON AG. The reduction of capital proceeded as a simplified capital reduction as specified in Article 71 (1) No. 8 AktG.

Moreover, E.ON entered into put option arrangements in 2007 for a further 10,000,000 of its own shares, again as part of the share buyback program. Pursuant to IAS 32, the €1,098 million in conditional purchase price obligations arising from the put options, which had been recognized as a separate component of equity, have now been reclassified as a liability. The €64 million option premium received had the net effect, after deduction of €19 million in deferred taxes, of increasing equity by a total of €45 million.

Authorized Capital At the Annual Shareholders Meeting on April 27, 2005, the Board of Management was authorized, subject to the Supervisory Board’s approval, to increase the Company’s capital stock by up to €540 million (“Article 202 ff. AktG Authorized Capital”) through one or more issuances of new ordinary shares with no par value in return for contributions in cash and/or in kind (with the option to exclude shareholders’ subscription rights). This capital increase is authorized until April 27, 2010. Subject to the Supervisory Board’s approval, the Board of Management is authorized to exclude shareholders’ subscription rights.

At the Annual Shareholders Meeting of April 30, 2003, conditional capital (with the option to exclude shareholders’ subscription rights) in the amount of €175.0 million (“Conditional Capital”) was authorized until April 30, 2008. This Conditional Capital may be used to issue bonds with conversion or option rights and to fulfill conversion obligations towards creditors of bonds containing conversion obligations. The securities underlying these rights and obligations are either E.ON AG shares or those of companies in which E.ON AG directly or indirectly holds a majority stake.

For the 2007 fiscal year, the following disclosures about voting rights have been made pursuant to Article 21 (1) of the German Securities Trading Act (“WpHG”):

On June 6, 2007, UBS AG, Zurich, Switzerland, informed us pursuant to Article 21 (1) WpHG that its share of the voting rights of E.ON AG, Düsseldorf, Germany, ISIN: DE0007614406, WKN: 761440, passed the threshold of 3 percent on June 1, 2007, and that it stands at 3.48 percent (equivalent to 24,100,066 votes) as of that date. 0.16 percent of the voting rights (equivalent to 1,102,568 votes) are attributable to UBS AG pursuant to Article 22 (1), sentence 1, no. 1, WpHG.

On December 21, 2007, Capital Research and Management Company, Los Angeles, California, U.S., informed us pursuant to Article 21 (1) WpHG that its share of the voting rights of E.ON AG, Düsseldorf, Germany, ISIN: DE0007614406, WKN: 761440, passed the threshold of 5 percent on December 13, 2007, and that it stands at 5.06 percent (equivalent to 33,743,064 votes) as of that date. 5.06 percent of the voting rights of E.ON AG (equivalent to 33,743,064 votes) are attributable to Capital Research and Management Company pursuant to Article 22 (1), sentence 1, no. 6, WpHG.

(20) ADDITIONAL PAID-IN CAPITAL Additional paid-in capital results exclusively from share issuance premiums. As of December 31, 2007, additional paid-in capital amounts to €11,825 million (2006: €11,760 million). This represents an increase of €65 million since December 31, 2006. This increase is due to the retirement of 25,000,000 shares.

F-57 The €11 million increase in 2006 resulted from the distribution of 443,290 E.ON AG shares to employees.

(21) RETAINED EARNINGS The following table breaks down the E.ON Group’s retained earnings as of the dates indicated:

Retained Earnings

December 31 € in millions 2007 2006 Legal reserves ...... 45 45 Other retained earnings ...... 26,783 24,305 Total ...... 26,828 24,350

The cancellation of 25,000,000 shares in the form of a simplified capital reduction had the effect of reducing retained earnings by a corresponding amount of €3,115 million as of December 31, 2007.

Under German securities law, E.ON AG shareholders may only receive distributions from the retained earnings of E.ON AG as defined by German GAAP. As of December 31, 2007, these German-GAAP retained earnings amounted to €3,627 million (2006: €4,593 million). Of these, legal reserves of €45 million (2006: €45 million) pursuant to Article 150 (3) and (4) AktG and reserves for treasury shares of €230 million (2006: €230 million) pursuant to Article 272 (4) HGB were not distributable on December 31, 2007. Accordingly, an amount of €3,352 million (2006: €4,318 million) is in principle available for dividend payments.

The Group’s retained earnings as of December 31, 2007, include accumulated undistributed earnings of €1,297 million (2006: €910 million) from companies that have been accounted for under the equity method.

A proposal to increase the cash dividend for 2007 by 22 percent, from €3.35 per share to €4.10 per share, will be submitted to the Annual Shareholders Meeting. The dividend will thus have increased from €1.75 to €4.10 since 2002, which corresponds to an average annual increase of 19 percent. Based on E.ON AG’s 2007 year-end closing price, the dividend yield is 2.8 percent. Based on a €4.10 dividend, the total profit distribution is €2,590 million.

(22) CHANGES IN OTHER COMPREHENSIVE INCOME The change in unrealized gains from available-for-sale securities was primarily attributable to an increase of €1,143 million (before deferred taxes) in the fair value of the investment in Gazprom.

In 2007, reclassification adjustments from available-for-sale securities recognized in income resulted primarily from the sale of securities at the Central Europe market unit. In 2006, this item included a gain of €159 million from the deconsolidation of institutional securities funds that took place as part of the funding of the CTA (see also Note 24).

F-58 (23) MINORITY INTERESTS Minority interests as of the dates indicated are attributable to the segments as shown below:

Minority Interests

December 31 € in millions 2007 2006 Central Europe ...... 2,578 2,299 Pan-European Gas ...... 212 832 U.K...... 84 63 Nordic ...... 1,782 1,789 U.S. Midwest ...... 29 77 Corporate Center/New Markets ...... 1,071 (2,527) Total ...... 5,756 2,533

The increase in minority interests in 2007 resulted primarily from the expiration of an obligation concerning the purchase of the outstanding stake in E.ON Sverige and from the acquisition of OGK-4 (see also Notes 26 and 4).

(24) PROVISIONS FOR PENSIONS AND SIMILAR OBLIGATIONS The retirement benefit obligations toward the employees of the E.ON Group, which amounted to €15.9 billion, were covered by plan assets having a fair value of €13.1 billion as of December 31, 2007. This corresponds to a funded status of 82 percent.

In addition to the reported plan assets, VKE manages financial investments and liquid funds totaling €2.4 billion (2006: €2.3 billion) that do not constitute plan assets under IAS 19 but which nevertheless are solely intended for the coverage of employee retirement benefits in the Central Europe market unit and at Corporate Center/New Markets.

In 2006 and 2007, the funded status, measured as the difference between the defined benefit obligation for the pension units and the fair value of plan assets, has changed as follows:

Two-Year History

December 31 January 1 € in millions 2007 2006 2006 Defined benefit obligation ...... 15,936 17,306 17,849 Fair value of plan assets ...... (13,056) (13,342) (8,076) Funded status ...... 2,880 3,964 9,773

Description of the Benefit Obligations In addition to their entitlements under government retirement systems and the income from private retirement planning, most E.ON Group employees are also covered by occupational retirement plans.

Both defined benefit pension plans and defined contribution pension plans are maintained at E.ON. The majority of the benefit obligations reported consists of obligations of those companies in the E.ON Group in which the retirement pension is calculated either on the salaries earned during the most recent years of service (final-pay arrangements) or on a scale of fixed amounts.

F-59 In order to reduce the risks associated with this type of benefit obligations, a majority of the final-pay retirement pension plans were closed between 1998 and 2006 to new employees joining the Company and replaced by newly designed pension plans in Germany and the U.K. containing elements of both defined benefit and defined contribution pension plans, and by defined contribution pension plans in the United States. The newly designed pension plans were also introduced at many of the Group’s German companies to cover existing benefits for years of service beyond 2004.

The provisions for pensions and similar obligations further include minor provisions for obligations from the assumption of costs for post-employment health care benefits, which are granted primarily in the United States.

Under defined contribution pension plans, the Company discharges its obligations toward the employees in defined contribution pension plans when it pays agreed contribution amounts into funds managed by external retirement insurers.

Changes in the Benefit Obligation The following table shows the changes in the benefit obligation, as measured by the defined benefit obligation, for the periods indicated:

Changes in the Defined Benefit Obligation

2007 2006 € in millions Total Domestic Foreign Total Domestic Foreign Defined benefit obligation as of January 1 ...... 17,306 8,840 8,466 17,849 9,205 8,644 Employer service cost ...... 256 161 95 265 172 93 Interest cost ...... 810 388 422 771 361 410 Change in scope of consolidation ...... 24 2 22 (2) 5 (7) Past service cost ...... 10 — 10 14 1 13 Actuarial gains (–)/losses ...... (920) (1,003) 83 (816) (492) (324) Exchange rate differences ...... (761) — (761) 45 — 45 Employee contributions ...... 25 — 25 21 — 21 Pensions paid ...... (863) (426) (437) (847) (416) (431) Other ...... 49 1 48 6 4 2 Defined benefit obligation as of December 31 ...... 15,936 7,963 7,973 17,306 8,840 8,466

Foreign benefit obligations relate almost entirely to the benefit plans at the market units U.K. (2007: €7,134 million) and U.S. Midwest (2007: €779 million). The portion of the entire benefit obligation allocated to health care benefits amounted to €139 million (2006: €179 million).

The addition of OGK-4 (€22 million) was the principal factor behind the change shown as “Change in scope of consolidation” in 2007.

Actuarial gains in 2006 and 2007 are attributable primarily to the increase of the discount rate, which led to a relative decrease of the defined benefit obligation.

F-60 Actuarial values of the pension obligations of the principal German, U.K. and U.S. subsidiaries were computed based on the following average assumptions for each region:

Actuarial Assumptions

December 31, 2007 December 31, 2006 Germany Germany in % CTA plans Other U.K. U.S. CTA plans Other U.K. U.S. Discount rate ...... 5.50 5.50 5.80 6.65 4.50 4.50 5.10 5.95 Salary increase rate ...... 2.75 2.75 4.20 5.25 2.75 2.75 4.00 5.25 Expected return on plan assets ...... 5.40 4.50 5.90 8.25 4.90 4.50 5.90 8.25 Pension increase rate ...... 1.75 1.75 3.20 — 1.50 1.50 3.00 — Health care cost trend ...... — — — 9.00 — — — 10.00

Other company-specific actuarial assumptions, including employee fluctuation, have also been included in the computations. In Germany, the increase in age limits provided by the Retirement Pension Age Limit Adjustment Act (“RV-Altersgrenzenanpassungsgesetz”) was included for the first time in the determination of the benefit obligation in 2007.

To measure the E.ON Group’s occupational pension obligations for accounting purposes, the Company has employed the most recent biometric tables recognized in each respective country for the calculation of pension obligations.

The discount rate assumptions used by E.ON reflect the country-specific rates available at the end of the respective fiscal year for high-quality fixed-rate corporate bonds with a duration corresponding to the average period to maturity of the pension benefit obligations.

Description of Plan Assets Defined benefit pension plans in the Group’s companies, be they within or outside of Germany, are mostly financed through the accumulation of plan assets in specially created pension vehicles that legally are distinct from the Company.

In 2006, a number of German subsidiaries established a so-called Contractual Trust Arrangement (CTA), with two trusts (Pensionsabwicklungstrust e.V., E.ON Pension Trust e.V.) created for this purpose. The funds administered on a fiduciary basis by E.ON Pension Trust e.V. amounted to €5,204 million on December 31, 2007, and must be treated as plan assets under IAS 19. The remainder of the domestic plan assets in the amount of €318 million is held by pension funds in the Central Europe market unit.

The foreign plan assets, which amounted to €7,534 million in 2007 (2006: €7,974 million) and are managed by independent pension trusts, are dedicated almost entirely to the financing of the pension plans at the U.K. and U.S. Midwest market units. The majority of these plan assets, namely €6,944 million (2006: €7,401 million), is attributable to the U.K. market unit.

F-61 The changes in the fair value of the plan assets covering the benefit obligation for defined benefit pension plans are shown in the following table:

Changes in Plan Assets

2007 2006 € in millions Total Domestic Foreign Total Domestic Foreign Fair value of plan assets as of January 1...... 13,342 5,368 7,974 8,076 307 7,769 Expected return on plan assets ...... 731 266 465 529 102 427 Employer contributions ...... 436 269 167 5,241 5,126 115 Employee contributions ...... 25 — 25 21 — 21 Change in scope of consolidation ...... 4 4 — (4) — (4) Actuarial gains/losses (–) ...... (65) (72) 7 (36) (21) (15) Exchange rate differences ...... (715) — (715) 87 — 87 Pensions paid ...... (747) (313) (434) (575) (146) (429) Other ...... 45 — 45 3 — 3 Fair value of plan assets as of December 31 ...... 13,056 5,522 7,534 13,342 5,368 7,974

The €2.4 billion (2006: €2.3 billion) in financial assets and liquid funds administered by VKE are not included in the determination of the funded status since they do not constitute plan assets under IAS 19. However, these assets, which are primarily dedicated to the coverage of the Central Europe market unit’s benefit obligations, do additionally have to be taken into consideration for a comprehensive evaluation of the funded status of the E.ON Group’s benefit obligations.

The principal investment objective for the pension plan assets is to provide full coverage of benefit obligations at all times for the payments due under the corresponding pension plans. Plan assets do not include any owner-occupied real estate. Investment in equity and debt instruments issued by E.ON Group companies is generally not intended.

To implement the investment objective, the E.ON Group in principle pursues a liability-driven investment (LDI) approach that takes into account the structure of the benefit obligations. This long-term LDI strategy seeks to manage the funded status, with the result that any changes in the defined benefit obligation, especially those caused by fluctuating inflation and interest rates are, to a certain degree, counteracted by simultaneous corresponding changes in the fair value of plan assets. The LDI strategy may also involve the use of derivatives (e.g., interest rate swaps and inflation swaps). In order to improve the funded status, i.e., the difference between the defined benefit obligations for all pension plans and the fair value of all plan assets, of the E.ON Group as a whole, a portion of the plan assets will also be invested in a diversified portfolio of asset classes that are expected to provide for long-term returns in excess of those of fixed-income investments.

The determination of the target portfolio structure is based on regular asset-liability studies. In these studies, the target portfolio structure is reviewed under consideration of existing investment principles, the current funded status, the condition of the capital markets and the structure of the benefit obligations developments, and is adjusted as necessary. The anticipated long-term returns on the individual plan assets are derived from the portfolio structure targeted and from the long-term returns forecast for the individual asset classes in the asset- liability studies.

F-62 Plan assets were invested in the asset classes shown in the following table as of the dates indicated:

Classification of Plan Assets

December 31, 2007 December 31, 2006 in % Total Domestic Foreign Total Domestic Foreign Equity securities ...... 18 6 27 18 1 29 Debt securities ...... 49 31 62 39 3 63 Real estate ...... 8 10 7 5 4 5 Other (primarily fixed-term deposits) ...... 25 53 4 38 92 3

Provision for Pensions and Similar Obligations The E.ON Group’s recognized provision for pensions and similar obligations is derived from the difference between the defined benefit obligation and the fair value of plan assets and is adjusted for unrecognized past service cost, and is determined as shown in the following table:

Derivation of the Provision for Pensions and similar obligations

December 31 January 1 € in millions 2007 2006 2006 Defined benefit obligation—fully or partially funded plans ...... 15,632 16,996 17,508 Fair value of plan assets ...... (13,056) (13,342) (8,076) Defined benefit obligation—unfunded plans ...... 304 310 341 Funded status ...... 2,880 3,964 9,773 Unrecognized past service cost ...... (3) (4) (5) Net amount recognized ...... 2,877 3,960 9,768 Operating receivables ...... (13) (2) — Provisions for pensions and similar obligations ...... 2,890 3,962 9,768

The decline during 2006 in the provision for pensions and similar obligations resulted primarily from the first-time funding of the CTA in Germany in the amount of €5.1 billion. The additional decline in the provision for pensions and similar obligations as of December 31, 2007, was due primarily to the increase in the discount rates applied, which had the effect of reducing the entire defined benefit obligation.

Contributions and Pension Payments In 2007, E.ON made employer contributions to plan assets totaling €436 million (2006: €5,241 million, including CTA funding) to fund existing defined benefit obligations. For 2008, it is expected that overall employer contributions to plan assets will amount to a total of €188 million and primarily involve the funding of new and existing benefit obligations.

Prospective Employer Contributions in 2008

€ in millions Domestic Foreign Prospective Employer Contributions ...... 112 76

F-63 Pension payments to cover benefit obligations totaled €863 million in 2007 (2006: €847 million). Prospective pension payments existing as of December 31, 2007, for the next ten years are shown in the following table:

Prospective Pension Payments

€ in millions Total Domestic Foreign 2008 ...... 867 447 420 2009 ...... 892 462 430 2010 ...... 919 479 440 2011 ...... 940 489 451 2012 ...... 962 497 465 2013–2017 ...... 5,145 2,615 2,530 Total ...... 9,725 4,989 4,736

Pension Cost The net periodic pension cost for defined benefit pension plans is shown in the table below:

Net Periodic Pension Cost

2007 2006 € in millions Total Domestic Foreign Total Domestic Foreign Employer service cost ...... 256 161 95 265 172 93 Interest cost ...... 810 388 422 771 361 410 Expected return on plan assets ...... (731) (266) (465) (529) (102) (427) Past service cost ...... 10 — 10 14 1 13 Total ...... 345 283 62 521 432 89

Actuarial gains and losses have been recognized in full in the period in which they occurred. They are reported outside of the income statement as part of equity in the statements of recognized income and expenses.

The actual return on plan assets totaled €666 million in 2007 (2006: €486 million).

In addition to the total net periodic pension cost, an amount of €53 million in 2007 (2006: €54 million) was incurred for defined contribution pension plans and other retirement provisions, under which the Company pays fixed contributions to external insurers or similar institutions.

The total net periodic pension cost shown includes an amount of €12 million in 2007 (2006: €15 million) for retiree health care benefits. A one-percentage-point increase or decrease in the assumed health care cost trend rate would affect the interest and service components and result in a change in net periodic pension cost of +€0.5 million or –€0.4 million (2006: +€0.7 million or –€0.6 million), respectively. The resulting accumulated post-employment benefit obligation would change by +€4.9 million or –€4.4 million (2006: +€7.7 million or –€6.9 million), respectively.

F-64 The changes in actuarial gains and losses recognized in equity are shown in the following table:

Accumulated Actuarial Gains and Losses Recognized in Equity

€ in millions 2007 2006 Accumulated actuarial gains (+) and losses (–) recognized in equity as of January 1 . . 781 — Recognition in equity of current-year actuarial gains (+) and losses (–) ...... 852 781 Accumulated actuarial gains (+) and losses (–) recognized in equity as of December 31 ...... 1,633 781

In 2007 and 2006, the following experience adjustments were made to the present value of all benefit obligations and to the fair value of plan assets:

Experience Adjustments

December 31 in % 2007 2006 Experience adjustments to the amount of the benefit obligation ...... 1.22 0.73 Experience adjustments to the value of plan assets ...... (0.50) (0.22)

The experience adjustments reflect the effects on the benefit obligations and plan assets at the E.ON Group resulting from differences between the actual changes in these amounts during the fiscal year from the assumption made with respect to these changes at the beginning of the year. This includes, among other things, the development of salary increases and of other measures relevant in the determination of the benefit obligations, increases in state pensions, employee fluctuation and biometric data such as death and disability.

(25) MISCELLANEOUS PROVISIONS The following table lists the miscellaneous provisions as of the dates indicated:

Miscellaneous Provisions

December 31, 2007 December 31, 2006 € in millions current non-current current non-current Non-contractual obligations for nuclear waste management ...... 133 10,022 120 10,425 Contractual obligations for nuclear waste management ...... 300 3,335 294 3,389 Personnel obligations ...... 593 690 686 804 Other asset retirement obligations ...... 301 943 295 901 Supplier-related obligations ...... 451 290 419 107 Customer-related obligations ...... 296 80 309 41 Environmental remediation and similar obligations ...... 32 456 15 474 Other ...... 1,886 2,257 1,856 1,997 Total ...... 3,992 18,073 3,994 18,138

F-65 The changes in the miscellaneous provisions are shown in the table below:

Changes in Miscellaneous Provisions

Exchange Change in Changes Jan. 1, rate scope of Reclassi- in Dec. 31, € in millions 2007 differences consolidation Accretion Additions Utilization fications Reversals estimates 2007 Non-contractual obligations for nuclear waste management . . . 10,545 (52) — 492 25 — (110) — (745) 10,155 Contractual obligations for nuclear waste management ...... 3,683 (13) — 181 55 (384) 110 — 3 3,635 Personnel obligations . . . 1,490 (6) 3 3 598 (717) 1 (89) — 1,283 Other asset retirement obligations ...... 1,196 (20) 2 35 5 (23) — — 49 1,244 Supplier-related obligations ...... 526 (2) — 6 297 (51) — (35) — 741 Customer-related obligations ...... 350 (4) — 1 237 (113) (3) (92) — 376 Environmental remediation and similar obligations ...... 489 (3) — 15 23 (17) — (19) — 488 Other ...... 3,853 (37) 42 30 1,504 (984) (21) (244) — 4,143 Total ...... 22,132 (137) 47 763 2,744 (2,289) (23) (479) (693) 22,065

The accretion expense resulting from the changes in provisions is shown in the financial results (see Note 9).

The interest rates applied for the nuclear power segment, calculated on a country-specific basis, were 5.5 percent (2006: 5.0 percent) in Germany and 2.5 percent (2006: 2.1 percent to 2.5 percent) in Sweden. For the other provision items, the interest rates used ranged from 3.0 percent to 4.5 percent, depending on maturity (2006: 3.8 percent to 5.2 percent).

Provisions for Non-Contractual Nuclear Waste Management Obligations The provisions based on German and Swedish nuclear power legislation totaling €10.2 billion comprise all those nuclear obligations relating to the disposal of spent nuclear fuel rods and low-level nuclear waste and to the retirement and decommissioning of nuclear power plant components that are determined on the basis of external studies and cost estimates.

The provisions are classified primarily as non-current provisions and measured at their settlement amounts, discounted to the balance sheet date.

The asset retirement obligations recognized for non-contractual nuclear obligations include the anticipated costs of runout operation of the facility, dismantling costs, and the cost of removal and disposal of the nuclear components of the nuclear power plant.

Additionally included as part of the disposal of spent fuel rods are costs for transports to be conducted from central and local temporary facilities to the conditioning plant and to the final storage facility, the cost of proper conditioning prior to final storage and the cost of procurement of final storage containers.

F-66 The decommissioning costs and the cost of disposal of spent nuclear fuel rods and low-level nuclear waste also respectively include the actual final storage costs. The cost estimates used to determine the provision amounts are all based on studies performed by external specialists and are updated annually.

Measurement of the provisions takes into account the influencing factors agreed in the understanding reached between the German government and the country’s major power utilities on June 14, 2000, and signed on June 11, 2001. Final storage costs consist mainly of investment and operating costs for the planned final storage facilities Gorleben and Konrad based on Germany’s ordinance on advance payments for the establishment of facilities for the safe custody and final storage of radioactive wastes in the country (“Endlagervorausleistungsverordnung”) and on data from the German Federal Office for Radiation Protection (“Bundesamt für Strahlenschutz”). Advance payments remitted to the Bundesamt für Strahlenschutz in the amount of €781 million (2006: €781 million) have been deducted from the provisions. These payments are made each year in the amount spent by the Bundesamt für Strahlenschutz on the construction of the final storage facilities Gorleben and Konrad, which are calculated based on the Endlagervorausleistungsverordnung.

Changes in estimates in 2007 reduced provisions by €859 million at the Central Europe market unit. The Nordic market unit recorded an increase of €114 million as a result of changes in estimates.

Provisions for Contractual Nuclear Waste Management Obligations The provisions based on German and Swedish nuclear power legislation totaling €3.6 billion comprise all those nuclear obligations relating to the disposal of spent nuclear fuel rods and low-level nuclear waste and to the retirement and decommissioning of nuclear power plant components that are valued at amounts firmly specified in legally binding civil agreements.

Most of the provisions are classified as non-current provisions and measured at their settlement amounts, discounted to the balance sheet date.

Advance payments made to reprocessors and to other waste management companies in the amount of €126 million (2006: €113 million) have been deducted from the provisions attributed to Germany. The advance payments relate to reprocessing services and to the delivery of interim storage containers, as well as the return of waste resulting from reprocessing. Concerning the disposal of spent nuclear fuel rods, the obligations recognized in the provisions comprise the contractual costs of finalizing reprocessing and the associated transports and containers for the return of waste into the central interim storage facilities Gorleben and Ahaus and the actual central interim storage itself, as well as the procurement of interim storage containers, transports of spent fuel rods to interim on-site storage facilities and the actual temporary storage itself arising from the “direct permanent storage” path. The provisions also include the contractual costs of decommissioning and the conditioning of low-level radioactive waste.

Changes in estimates in 2007 reduced provisions by €58 million at the Central Europe market unit. The Nordic market unit recorded an increase of €61 million as a result of changes in estimates.

Personnel Obligations Provisions for personnel costs primarily cover provisions for vacation pay, early retirement benefits, anniversary obligations, share-based payment and other deferred personnel costs.

Provisions for Other Asset Retirement Obligations The provisions for other asset retirement obligations consist of obligations for conventional and renewable- energy power plants, including the conventional plant components in the nuclear power segment, that are based on legally binding civil agreements and public regulations. Also reported here are provisions for environmental improvements at opencast mining and gas storage facilities and the dismantling of installed infrastructure.

F-67 Supplier-Related Obligations Provisions for supplier-related liabilities consist primarily of provisions for potential losses on open purchase contracts.

Customer-Related Obligations Provisions for customer-related liabilities consist primarily of potential losses on open sales contracts. Also included are provisions for warranties.

Environmental Remediation and Similar Obligations Provisions for environmental remediation refer primarily to redevelopment and water protection measures and to the rehabilitation of contaminated sites. Also included here are provisions for reversion of title, other environmental improvements and land reclamation obligations at mining sites.

Other The other miscellaneous provisions consist primarily of provisions from the electricity and gas business, including the provision established in 2006 for the risk of retroactive application of lower network charges resulting from the regulation of network charges in Germany. They further include provisions for obligations arising from the acquisition and disposal of businesses, provisions for taxes other than income taxes, provisions from emissions trading systems and provisions for tax-related interest expenses.

(26) LIABILITIES The following table provides details of liabilities as of the dates indicated:

Liabilities

December 31, 2007 December 31, 2006 non- non- € in millions current current Total current current Total Financial liabilities to banks and third parties ...... 3,481 15,876 19,357 1,472 9,993 11,465 Financial liabilities to entities in which an ownership interest exists ...... 2,068 39 2,107 1,971 36 2,007 Financial liabilities to affiliated companies ...... 152 9 161 147 7 154 Financial liabilities to associated companies and other equity investments ...... 1,916 30 1,946 1,824 29 1,853 Financial liabilities ...... 5,549 15,915 21,464 3,443 10,029 13,472 Trade payables ...... 4,477 — 4,477 5,311 — 5,311 Operating liabilities to entities in which an ownership interest exists ...... 474 65 539 274 70 344 Operating liabilities to affiliated companies ...... 135 44 179 75 48 123 Operating liabilities to associated companies and other equity investments ...... 339 21 360 199 22 221 Capital expenditure grants ...... 26 219 245 23 243 266 Construction grants from energy consumers ...... 434 2,978 3,412 360 3,110 3,470 Liabilities from derivatives ...... 5,011 260 5,271 5,897 41 5,938 Advance payments ...... 451 6 457 400 9 409 Other operating liabilities ...... 7,381 1,904 9,285 7,313 1,949 9,262 Trade payables and other operating liabilities ...... 18,254 5,432 23,686 19,578 5,422 25,000 Total ...... 23,803 21,347 45,150 23,021 15,451 38,472

F-68 Financial Liabilities The following is a description of the E.ON Group’s significant credit arrangements and debt issuance programs. Included under “Bonds” are the bonds currently outstanding, including those issued under the Debt Issuance Program.

Corporate Center €30 Billion Debt Issuance Program The existing €20 billion Medium Term Note program was increased to €30 billion in December 2007 and renamed “Debt Issuance Program.” The program allows E.ON AG and E.ON International Finance B.V. (“EIF”), Amsterdam, the Netherlands, under the unconditional guarantee of E.ON AG, to periodically issue debt instruments through public and private placements to investors. At year-end 2007, the following EIF bonds were outstanding:

Debt Issues of E.ON International Finance

Volume issued in the respective currency Initial term Repayment Coupon Listing EUR 4,250 m ...... 7years May 2009 5.750% Luxembourg CHF200m ...... 3years Dec 2010 3% SWX Swiss Exchange GBP500m ...... 10years May 2012 6.375% Luxembourg EUR 1,750 m ...... 5years Oct 2012 5.125% Luxembourg CHF225m ...... 7years Dec 2014 3.25% SWX Swiss Exchange EUR900m...... 15years May 2017 6.375% Luxembourg EUR 1,750 m ...... 10years Oct 2017 5.5% Luxembourg GBP600m ...... 12years Oct 2019 6% Luxembourg GBP975m ...... 30years June 2032 6.375% Luxembourg GBP900m ...... 30years Oct 2037 5.875% Luxembourg

The Debt Issuance Program documentation and the documentation of the outstanding bonds are customary for such financing programs and instruments.

€10 Billion Commercial Paper Program The existing €10 billion commercial paper program allows E.ON AG and certain wholly owned subsidiaries, under the unconditional guarantee of E.ON AG, to periodically issue commercial paper with maturities of up to 729 days to investors. As of December 31, 2007, €1,757 million in commercial paper was outstanding under the program (2006: €123 million).

€15 Billion Syndicated Multi-Currency Revolving Credit Facility Agreement In November 2007, E.ON increased the amount available under its existing revolving credit facility from €10 billion to €15 billion. Under the facility, E.ON AG and certain subsidiaries, each under the unconditional guarantee of E.ON AG, may make borrowings in various currencies in an aggregate amount of up to €15 billion. The facility is divided into Tranche A in the amount of €10 billion and Tranche B in the amount of €5 billion. Tranche A has a maturity date of November 27, 2008. Tranche B runs until December 2, 2011. Borrowings under the credit facility generally bear interest equal to EURIBOR or LIBOR for the respective currency plus a margin of 15 basis points. As of December 31, 2007, there were no borrowings outstanding under this facility (2006: €0).

F-69 As of December 31, 2007, the book values financial liabilities of E.ON AG and EIF to banks and third parties outside the E.ON Group had the following maturities:

Financial Liabilities of E.ON AG and E.ON International Finance

Due in Due in Due in Due in Due in Due after € in millions Total 2008 2009 2010 2011 2012 2012 Bonds ...... 12,822 — 4,162 120 — 2,423 6,117 Commercial paper ...... 1,757 1,757 — — — — — Bank loans / Liabilities to banks ...... 425 425 — — — — — Liabilities from finance leases ...... —————— — Other financial liabilities ...... 12 4 4 4 — — — Total ...... 15,016 2,186 4,166 124 — 2,423 6,117

Financial Liabilities by Segment The following table shows the financial liabilities to banks and third parties by segment:

Financial Liabilities by Market Unit as of December 31

Corporate Central U.S. Center/New Europe Pan-European Gas U.K. Nordic Midwest Markets Total € in millions 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 Bonds ...... — — — — 275 406 738 634 635 729 12,822 7,234 14,470 9,003 Commercial paper ...... — — — — — — 227 243 — — 1,757 123 1,984 366 Bank loans / Liabilities to banks ...... 992 1,040 40 69 8 27 — 54 — — 972 48 2,012 1,238 Liabilities from finance leases ...... 39 24 63 66 25 54 30 36 — — 14 16 171 196 Other financial liabilities ...... 136 126 47 105 — 6 431 383 — 15 106 27 720 662 Financial liabilities to banks and third parties ...... 1,167 1,190 150 240 308 493 1,426 1,350 635 744 15,671 7,448 19,357 11,465

Other Financial Liabilities Other financial liabilities include collateral received, measured at a fair value of €407 million (2006: €55 million). This collateral includes amounts pledged by banks to limit the utilization of credit lines in connection with the marking to market of derivatives transactions and margin deposits received in connection with forward transactions on futures exchanges. Also included here is collateral received in connection with goods and services in the amount of €75 million (2006: €77 million). E.ON can sell or repledge this collateral with no subsidiary conditions.

Trade Payables and Other Operating Liabilities Trade payables totaled €4,477 million as of December 31, 2007 (2006: €5,311 million).

Capital expenditure grants of €245 million (2006: €266 million) were paid primarily by customers for capital expenditures made on their behalf, while E.ON retains the assets. The grants are non-refundable and are recognized in other operating income over the period of the depreciable lives of the related assets.

F-70 Construction grants of €3,412 million (2006: €3,470 million) were paid by customers for the cost of new gas and electricity connections in accordance with the generally binding terms governing such new connections. These grants are customary in the industry, generally non-refundable and recognized as revenue according to the useful lives of the related assets.

Other operating liabilities consist primarily of accruals in the amount of €3,530 million (2006: €2,673 million), interest payable in the amount of €760 million (2006: €672 million) and the €1,111 million in obligations under the put options that were written in 2007 as part of the share buyback program. Also included in other operating liabilities are counterparty obligations to acquire additional shares in already consolidated subsidiaries and minority interests in fully consolidated partnerships totaling €754 million (2006: €2,781 million). This decrease in liabilities from counterparty obligations resulted primarily from the obligation toward Statkraft concerning the purchase of its remaining stake in E.ON Sverige for approximately €2 billion, which expired unexercised in 2007.

(27) CONTINGENCIES AND COMMITMENTS As part of its business activities, E.ON is subject to contingencies and commitments involving a variety of underlying matters. These primarily include guarantees, obligations from litigation and claims (as discussed in more detail in Note 28), short-and long-term contractual and legal obligations and other commitments.

Contingencies The contingent liabilities of the E.ON Group arising from existing contingencies amounted to €96 million as of December 31, 2007 (2006: €114 million). E.ON currently does not have reimbursement rights relating to the contingent liabilities disclosed.

E.ON has issued direct and indirect guarantees to third parties, which require E.ON to make contingent payments based on the occurrence of certain events or changes in an underlying instrument that is related to an asset, a liability or an equity instrument of the guaranteed party, on behalf of both related parties and external entities. These consist primarily of financial guarantees and warranties.

In addition, E.ON has also entered into indemnification agreements. Along with other guarantees, these indemnification agreements are incorporated in agreements entered into by Group companies concerning the disposal of shareholdings and, above all, cover the customary representations and warranties, as well as environmental damage and tax contingencies. In some cases the buyer of such shareholdings is required to either share costs or cover certain specific costs before E.ON itself is required to make any payments. Some obligations are covered in the first instance by insurance contracts or provisions of the disposed companies. Guarantees issued by companies that were later sold by E.ON AG (or VEBA AG and VIAG AG before their merger) are included in the respective final sales contracts in the form of indemnities.

Moreover, E.ON has commitments under which it assumes joint and several liability arising from its interests in the civil-law companies (“GbR”), non-corporate commercial partnerships and consortia in which it participates.

The guarantees of E.ON also include items related to the operation of nuclear power plants. With the entry into force on April 27, 2002, of the German Nuclear Power Regulations Act (“Atomgesetz” or “AtG”), as amended, and of the ordinance regulating the provision for coverage under the Atomgesetz (“Atomrechtliche Deckungsvorsorge-Verordnung” or “AtDeckV”), as amended, German nuclear power plant operators are required to provide nuclear accident liability coverage of up to €2.5 billion per incident.

The coverage requirement is satisfied in part by a standardized insurance facility in the amount of €255.6 million. The institution Nuklear Haftpflicht Gesellschaft bürgerlichen Rechts (“Nuklear Haftpflicht GbR”) now

F-71 only covers costs between €0.5 million and €15 million for claims related to officially ordered evacuation measures. Group companies have agreed to place their subsidiaries operating nuclear power plants in a position to maintain a level of liquidity that will enable them at all times to meet their obligations as members of the Nuklear Haftpflicht GbR, in proportion to their shareholdings in nuclear power plants.

To provide liability coverage for the additional €2,244.4 million per incident required by the above- mentioned amendments, E.ON Energie AG and the other parent companies of German nuclear power plant operators reached a Solidarity Agreement (“Solidarvereinbarung”) on July 11, July 27, August 21, and August 28, 2001. If an accident occurs, the Solidarity Agreement calls for the nuclear power plant operator liable for the damages to receive—after the operator’s own resources and those of its parent company are exhausted— financing sufficient for the operator to meet its financial obligations. Under the Solidarity Agreement, E.ON Energie’s share of the liability coverage currently stands at 42.0 percent (2006: 42.0 percent), with an additional 5.0 percent charge for the administrative costs of processing damage claims.

In accordance with Swedish law, the companies of the Nordic market unit have issued guarantees to governmental authorities. The guarantees were issued to cover possible additional costs related to the disposal of high-level radioactive waste and to nuclear power plant decommissioning. These costs could arise if actual costs exceed accumulated funds. In addition, Nordic is also responsible for any costs related to the disposal of low-level radioactive waste.

In Sweden, owners of nuclear facilities are liable for damages resulting from accidents occurring in those nuclear facilities and for accidents involving any radioactive substances connected to the operation of those facilities. The liability per incident as of December 31, 2007, was limited to SEK 3,063 million, or €324 million (2006: SEK 3,102 million, or €343 million), which amount must be insured according to the Law Concerning Nuclear Liability. The Nordic market unit has purchased the necessary insurance for its nuclear power plants. The Swedish government is currently in the process of reviewing the regulatory framework for the aforementioned liability limitation. The extent to which this review will result in changes to the Swedish regulations on the limitation of nuclear liability is still unclear at present.

Other than in the Central Europe and Nordic market units, there are no nuclear power plants in operation. Accordingly, there are no additional contingent liabilities comparable to those mentioned above.

Other Commitments In addition to provisions and liabilities carried on the balance sheet and to the reported contingent liabilities, there also are other mostly long-term commitments arising from contracts entered into with third parties or on the basis of legal requirements.

As of December 31, 2007, purchase commitments and obligations totaled €7.9 billion (2006: €4.9 billion). This total includes obligations for as yet outstanding investments in connection with new power plant construction projects as well as modernizations of existing power plants, particularly at the Central Europe, Nordic and U.K. market units and at the power plant operator OGK-4 acquired in Russia. As of December 31, 2007, purchase commitments and obligations for new power plant construction totaled €5.4 billion (2006: €2.5 billion). These commitments also include obligations concerning the construction of wind power plants.

F-72 In addition, other financial obligations arose from rental, and tenancy agreements and from operating leases. The corresponding minimum lease payments, presented at their nominal values, are due as broken down in the table below:

E.ON as Lessee—Operating Leases

Minimum lease € in millions payments Due within 1 year ...... 148 Due in 1 to 5 years ...... 401 Due in more than 5 years ...... 334 Total ...... 883

The expenses reported in the income statement for such contracts amounted to €218 million (2006: €236 million).

Additional long-term contractual obligations in place at the E.ON Group as of December 31, 2007, relate primarily to the purchase of fossil fuels such as gas, lignite and hard coal. Obligations under these purchase contracts amounted to roughly €250 billion on December 31, 2007.

Gas is usually procured on the basis of long-term purchase contracts with large international producers of natural gas. Such contracts are generally of a “take-or-pay” nature. The prices paid for natural gas are normally tied to the prices of competing energy sources, as dictated by market conditions. The conditions of these long- term contracts are reviewed at certain specific intervals (usually every 3 years) as part of contract negotiations and may thus change accordingly. In the absence of an agreement on a pricing review, a neutral board of arbitration makes a final binding decision. Financial obligations arising from these contracts are calculated based on the same principles that govern internal budgeting. Furthermore, the take-or-pay conditions in the individual contracts are also considered in the calculations.

As of December 31, 2007, €7.7 billion in contractual obligations are in place for the purchase of electricity; these relate in particular to purchases from jointly operated power plants in the Central Europe market unit. The purchase price of electricity from jointly operated power plants is determined by the supplier’s production cost plus a profit margin that is generally calculated on the basis of an agreed return on capital.

Long-term contractual obligations have also been entered into by the Central Europe market unit for the procurement of services in the area of reprocessing and interim storage of spent nuclear fuel elements delivered through June 30, 2005.

Other financial obligations in place as of December 31, 2007, totaled approximately €3.7 billion. They consist primarily of obligations concerning the acquisition of equity investments and the acquisition of real estate funds held as financial assets, as well as obligations arising from the network connection of offshore wind farms. These items concern primarily the Central Europe market unit.

In addition, there is an obligation toward the minority shareholders of the Russian power plant operator OGK-4 to acquire their shares. More information on this is contained in Note 4.

(28) LITIGATION AND CLAIMS A number of different court actions (including product liability lawsuits), governmental investigations and proceedings, and other claims are currently pending or may be instituted or asserted in the future against companies of the E.ON Group. This in particular includes legal actions and proceedings concerning alleged price-fixing agreements and anticompetitive practices. In addition, there are lawsuits pending against E.ON AG

F-73 and U.S. subsidiaries in connection with the disposal of VEBA Electronics in 2000. E.ON Ruhrgas is a party to a number of different arbitration proceedings in connection with the acquisition of Europgas a.s. and in connection with gas delivery contracts. Since litigation or claims are subject to numerous uncertainties, their outcome cannot be ascertained; however, in the opinion of management, any potential obligations arising from these matters will not have a material adverse effect on the financial condition, results of operations or cash flows of the Company.

(29) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION The following table indicates supplemental disclosures of cash flow information:

Supplemental Disclosure of Cash Flow Information

€ in millions 2007 2006 Non-cash investing and financing activities Exchanges and contributions of assets as part of acquisitions ...... — 138 Funding of external fund assets for pension obligations through transfer of fixed-term deposits and securities ...... — 5,126

The sales price of deconsolidated shareholdings and activities amounted to €25 million in 2007 (2006: €989 million). The deconsolidation of shareholdings and activities resulting from asset sales led to reductions of €21 million (2006: €1,523 million) related to assets and €11 million (2006: €562 million) related to provisions and liabilities. Cash and cash equivalents divested herewith amounted to €2 million (2006: €550 million).

Purchase prices for acquisitions of subsidiaries totaled €5,416 million (2006: €550 million). Cash and cash equivalents acquired in connection with the acquisitions amounted to €1,450 million (2006: €57 million). These purchases resulted in assets amounting to €8,615 million (2006: €1,935 million) and in provisions and liabilities totaling €2,182 million (2006: €1,365 million).

Cash provided by operating activities was 22 percent higher in 2007 than in 2006. This increase is due primarily to the positive cash flow effects of operational improvements and a reduced commitment of funds to working capital at the Pan-European Gas and Nordic market units. An additional positive contribution came from the reduction of receivables at the U.K. market unit. Negative cash flow effects in 2007 occurred at the Corporate Center and were caused primarily by higher tax payments outside of the Group.

Cash provided by investing activities was negative in 2007. With declining proceeds from sales of shareholdings, spending on investments in property, plant and equipment and on equity investments rose significantly over the previous year. The largest individual project was the acquisition of the majority of the shares of the Russian power plant company OGK-4. This increased spending was offset by a reduction in funds used for fixed-term deposits and securities purchases.

Increased borrowing led to a strong increase in cash provided by financing activities. For the first time since 2002, these cash flows were positive in 2007, in spite of the effect of the share buyback program.

(30) DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING TRANSACTIONS Strategy and Objectives The Company’s policy generally permits the use of derivatives if they are associated with underlying assets or liabilities, forecasted transactions, or legally binding rights or obligations. Some of the companies in the market units also conduct proprietary trading in commodities within the risk management guidelines described below.

Hedge accounting in accordance with IAS 39 is used primarily for interest rate derivatives used to hedge long-term debts, as well as for currency derivatives used to hedge net investments in foreign operations and long-

F-74 term receivables and debts denominated in foreign currencies. In commodities, potentially volatile future cash flows resulting primarily from planned purchases and sales of electricity and from gas supply requirements are hedged. Forward transactions are used to hedge price risks on equities.

Fair Value Hedges Fair value hedges are used to protect against the risk from changes in market values. The Company uses fair value hedge accounting specifically in the exchange of fixed-rate commitments in long-term receivables and liabilities denominated in foreign currencies and euro for variable rates. The hedging instruments used for such exchanges are interest rate and cross-currency interest rate swaps. Gains and losses on these hedges are generally reported in that line item of the income statement which also includes the respective hedged items. Interest rate fair value hedges are reported under “Interest and similar expenses.” Adjustments to the carrying amounts of hedged items produced a loss in 2007 of €9 million (2006: €14 million gain), which was offset by realized gains of €12 million (2006: €15 million loss) for the year in the designated hedging instruments. The negative fair values of the derivatives used in fair value hedges totaled €90 million (2006: negative €98 million).

Cash Flow Hedges Cash flow hedges are used to protect against the risk arising from variable cash flows. Interest rate and cross-currency interest rate swaps are the principal instruments used to limit interest rate and currency risks. The purpose of these swaps is to maintain the level of payments arising from long-term interest-bearing receivables and liabilities denominated in foreign currencies and euro by using cash flow hedge accounting in the functional currency of the respective E.ON company.

To reduce cash flow fluctuations arising from future electricity and gas transactions effected at variable spot prices, futures and forward contracts are concluded and also accounted for using cash flow hedge accounting.

As of December 31, 2007, the hedged transactions in place included foreign currency cash flow hedges with maturities of up to ten years (2006: up to eleven years) and up to 25 years (2006: up to 26 years) for interest cash flow hedges. Share price risk is hedged up to one year (2006: one year). Planned commodity cash flow hedges have maturities of up to four years (2006: up to four years).

The amount of ineffectiveness for cash flow hedges recorded for the year ended December 31, 2007, produced a gain of €3 million (2006: €3 million gain).

Pursuant to the information available as of the balance sheet date, the following effects will accompany the reclassifications from accumulated other comprehensive income to the income statement in subsequent periods:

Timing of Reclassifications from OCI1 to the Income Statement—2007

Carrying € in millions amount 2008 2009 2010–2012 >2012 OCI—Currency cash flow hedges ...... (103) (35) (9) (10) (49) OCI—Interest cash flow hedges ...... 6 (1) — (2) 9 OCI—Commodity cash flow hedges ...... 249 128 84 37 — OCI—Other cash flow hedges ...... (1) (1) — — — (1) OCI = Other comprehensive income. Figures are pre-tax.

F-75 Timing of Reclassifications from OCI1 to the Income Statement—2006

Carrying € in millions amount 2007 2008 2009–2011 >2011 OCI—Currency cash flow hedges ...... (98) (43) (10) (25) (20) OCI—Interest cash flow hedges ...... 3 (1) (1) — 5 OCI—Commodity cash flow hedges ...... 274 253 20 1 — OCI—Other cash flow hedges ...... (31) (31) — — — (1) OCI = Other comprehensive income. Figures are pre-tax.

Gains and losses from reclassification are generally reported in that line item of the income statement which also includes the respective hedged transaction. Gains and losses from the ineffective portions of cash flow hedges are classified as other operating income or other operating expenses. Interest cash flow hedges are reported under “Interest and similar expenses.” The negative fair values of the derivatives used in cash flow hedges totaled €339 million (2006: negative €359 million).

A negative amount of €82 million (2006: negative €302 million) was added to other comprehensive income in 2007, while during the same period a gain of €1 million (2006: €26 million) was reclassified from OCI to the income statement.

Net Investment Hedges The Company uses foreign currency loans, foreign currency forwards and foreign currency swaps to protect the value of its net investments in its foreign operations denominated in foreign currencies. For the year ended December 31, 2007, the Company recorded an amount of €1,489 million (2006: €909 million) in accumulated other comprehensive income within equity due to changes in fair value of derivatives and currency translation results of non-derivative hedging instruments. There were no ineffective portions from net investment hedges in 2007 (2006: €2 million gain).

Valuation of Derivative Instruments The fair value of derivative instruments is sensitive to movements in underlying market rates and other relevant variables.

The Company assesses and monitors the fair value of derivative instruments on a periodic basis. Fair values for each derivative financial instrument are determined as being equal to the price at which one party would assume the rights and duties of another party, and calculated using common market valuation methods with reference to available market data as of the balance sheet date.

The following is a summary of the methods and assumptions for the valuation of utilized derivative financial instruments in the Consolidated Financial Statements. • Currency, electricity, gas, oil and coal forward contracts, swaps, and emissions-related derivatives are valued separately at their forward rates and prices as of the balance sheet date. Forward rates and prices are based on spot rates and prices, with forward premiums and discounts taken into consideration. Market data are used to the extent possible. • Market prices for currency, electricity and gas options are valued using standard option pricing models commonly used in the market. The fair values of caps, floors and collars are determined on the basis of quoted market prices or on calculations based on option pricing models. • The fair values of existing instruments to hedge interest risk are determined by discounting future cash flows using market interest rates over the remaining term of the instrument. Discounted cash values are

F-76 determined for interest rate, cross-currency and cross-currency interest rate swaps for each individual transaction as of the balance sheet date. Interest income is recognized in income at the date of payment or accrual. • Equity forwards are valued on the basis of the stock prices of the underlying equities, taking into consideration any timing components. • Exchange-traded energy futures and option contracts are valued individually at daily settlement prices determined on the futures markets that are published by their respective clearing houses. Paid initial margins are disclosed under other assets. Variation margins received or paid during the term of such contracts are stated under other liabilities or other assets, respectively. • Certain long-term energy contracts are valued with the aid of valuation models that use internal data if market prices are not available.

Losses of €11 million (2006: €49 million) and gains of €141 million (2006: €96 million) from the initial measurement of derivative financial instruments at the inception of the contract were deferred and will be recognized in income during subsequent periods as the contracts are fulfilled. The following two tables include both derivatives that qualify for IAS 39 hedge accounting treatment and those that do not qualify.

Total Volume of Foreign Currency, Interest Rate and Equity-Based Derivatives

December 31, 2007 December 31, 2006 Nominal Fair Nominal Fair € in millions value value value value FX forward transactions Buy...... 8,466.8 (24.2) 4,532.7 (27.1) Sell ...... 9,738.3 67.3 6,982.4 19.4 FX currency options Buy...... — — 7.4 0.1 Sell ...... — — — — Subtotal ...... 18,205.1 43.1 11,522.5 (7.6) Cross-currency swaps ...... 19,847.2 686.6 18,499.3 7.4 Cross-currency interest rate swaps ...... 301.6 (49.6) 321.9 (17.0) Subtotal ...... 20,148.8 637.0 18,821.2 (9.6) Interest rate swaps Fixed-rate payer ...... 1,894.0 (21.5) 2,292.5 (16.4) Fixed-rate receiver ...... 6,153.7 (85.9) 6,078.3 (89.8) Interest rate future ...... 1,719.4 30.2 — — Subtotal ...... 9,767.1 (77.2) 8,370.8 (106.2) Other derivatives ...... 117.3 12.0 636.7 31.0 Subtotal ...... 117.3 12.0 636.7 31.0 Total ...... 48,238.3 614.9 39,351.2 (92.4)

F-77 Total Volume of Electricity, Gas, Coal, Oil and Emissions-Related Derivatives

December 31, 2007 December 31, 2006 Nominal Fair Nominal Fair € in millions value value value value Electricity forwards ...... 25,733.5 (794.1) 29,049.7 (854.0) Exchange-traded electricity forwards ...... 10,033.6 (98.8) 8,089.5 (275.0) Electricity swaps ...... 21.4 (1.1) 15.1 0.5 Exchange-traded electricity options ...... 104.9 9.5 0.3 0.2 Coal forwards and swaps ...... 5,024.4 193.1 1,320.2 29.2 Exchange-traded coal forwards ...... 38.1 25.7 58.9 (1.1) Oil derivatives ...... 780.4 11.6 1,213.4 (30.6) Gas forwards ...... 12,932.1 335.3 16,757.1 6.7 Gas swaps ...... 313.8 (36.2) 153.4 (17.4) Gas options ...... 4.5 (3.6) 5.3 2.8 Exchange-traded gas forwards ...... 1.2 0.1 — — Emissions-related derivatives ...... 1,808.0 6.0 461.0 2.8 Exchange-traded emissions-related derivatives ...... 407.8 (0.1) 33.9 3.8 Total ...... 57,203.7 (352.6) 57,157.8 (1,132.1)

F-78 (31) ADDITIONAL DISCLOSURES ON FINANCIAL INSTRUMENTS The following table shows the carrying amounts of the financial instruments, their grouping into IAS 39 categories, their fair values and their measurement sources by class:

Carrying Amounts and Fair Values by Class Within the Scope of IFRS 7 as of December 31, 2007

Total carrying amounts within the IAS 39 Determined Carrying scope of measurement using market € in millions amounts IFRS 7 category (1) Fair value prices Equity investments ...... 14,583 14,583 AfS 14,583 13,061 Financial receivables and other financial assets ..... 3,964 3,920 4,140 262 Financial receivables from entities in which an ownership interest exists ...... 899 899 LaR 899 — Receivables from finance leases (2) ...... 700 700 n/a 705 — Other financial receivables and financial assets ...... 2,365 2,321 LaR 2,536 262 Trade receivables and other operating assets ...... 18,653 17,021 16,940 377 Receivables from entities in which an ownership interest exists ...... 846 845 LaR 845 — Trade receivables ...... 9,064 9,064 LaR 9,064 — Derivatives with no hedging relationships ..... 4,928 4,928 HfT 4,928 365 Derivatives with hedging relationships ...... 632 632 n/a 632 — Other operating assets ...... 3,183 1,552 LaR 1,471 12 Securities and fixed-term deposits ...... 10,783 10,783 AfS 10,783 9,635 Cash and cash equivalents ...... 2,887 2,887 AfS 2,887 2,860 Restricted cash ...... 300 300 AfS 300 300 Assets held for sale ...... 577 — AfS — — Total assets ...... 51,747 49,494 49,633 26,495 Financial liabilities ...... 21,464 21,464 21,903 12,869 Financial liabilities to entities in which an ownership interest exists ...... 2,085 2,085 AmC 2,085 — Bonds ...... 14,470 14,470 AmC 14,886 12,823 Commercial paper ...... 1,984 1,984 AmC 1,984 — Bank loans/Liabilities to banks ...... 2,012 2,012 AmC 1,931 — Liabilities from finance leases (2) ...... 193 193 n/a 297 — Other financial liabilities ...... 720 720 AmC 720 46 Trade payables and other operating liabilities ...... 23,686 17,356 17,356 502 Liabilities to entities in which an ownership interest exists ...... 539 539 AmC 539 — Trade payables ...... 4,477 4,477 AmC 4,477 — Derivatives with no hedging relationships ..... 4,630 4,630 HfT 4,630 502 Derivatives with hedging relationships ...... 641 641 n/a 641 — Put option liabilities under IAS 32 ...... 754 754 AmC 754 — Other operating liabilities ...... 12,645 6,315 AmC 6,315 — Total liabilities ...... 45,150 38,820 39,259 13,371

(1) AfS: Available for sale; LaR: Loans and receivables; HfT: Held for trading; AmC: Amortized cost. The categories are described in detail in Note 2. (2) Includes finance leases with third parties and with entities in which an ownership interest exists.

F-79 Carrying Amounts and Fair Values by Class Within the Scope of IFRS 7 as of December 31, 2006

Total carrying amounts within the IAS 39 Determined Carrying scope of measurement using market € in millions amounts IFRS 7 category (1) Fair value prices Equity investments ...... 13,533 13,533 AfS 13,533 11,928 Financial receivables and other financial assets ..... 4,108 4,095 4,361 235 Financial receivables from entities in which an ownership interest exists ...... 913 913 LaR 913 — Receivables from finance leases (2) ...... 723 723 n/a 730 — Other financial receivables and financial assets ...... 2,472 2,459 LaR 2,718 235 Trade receivables and other operating assets ...... 18,430 16,980 16,980 85 Receivables from entities in which an ownership interest exists ...... 1,046 1,046 LaR 1,046 — Trade receivables ...... 9,760 9,760 LaR 9,760 — Derivatives with no hedging relationships ..... 4,294 4,294 HfT 4,294 85 Derivatives with hedging relationships ...... 424 424 n/a 424 — Other operating assets ...... 2,906 1,456 LaR 1,456 — Securities and fixed-term deposits ...... 11,594 11,594 AfS 11,594 11,266 Cash and cash equivalents ...... 1,154 1,154 AfS 1,154 1,154 Restricted cash ...... 587 587 AfS 587 587 Assets held for sale ...... 611 134 AfS 134 — Total assets ...... 50,017 48,077 48,343 25,255 Financial liabilities ...... 13,472 13,472 14,239 8,654 Financial liabilities to entities in which an ownership interest exists ...... 1,983 1,983 AmC 1,982 — Bonds ...... 9,003 9,003 AmC 9,670 8,622 Commercial paper ...... 366 366 AmC 366 — Bank loans/Liabilities to banks ...... 1,238 1,238 AmC 1,238 — Liabilities from finance leases (2) ...... 220 220 n/a 321 — Other financial liabilities ...... 662 662 AmC 662 32 Trade payables and other operating liabilities ...... 25,000 18,791 18,791 421 Liabilities to entities in which an ownership interest exists ...... 344 344 AmC 344 — Trade payables ...... 5,311 5,311 AmC 5,311 — Derivatives with no hedging relationships ..... 5,436 5,436 HfT 5,436 421 Derivatives with hedging relationships ...... 502 502 n/a 502 — Put option liabilities under IAS 32 ...... 2,781 2,781 AmC 2,781 — Other operating liabilities ...... 10,626 4,417 AmC 4,417 — Total liabilities ...... 38,472 32,263 33,030 9,075

(1) AfS: Available for sale; LaR: Loans and receivables; HfT: Held for trading; AmC: Amortized cost. The categories are described in detail in Note 2. (2) Includes finance leases with third parties and with entities in which an ownership interest exists.

The carrying amounts of cash and cash equivalents and of trade receivables are considered reasonable estimates of their fair values because of their short maturity.

F-80 Where financial instruments are listed on an active market, the respective price quotes at that market constitute the fair value. This applies in particular to equities held and bonds issued.

The fair value of shareholdings in unlisted companies and of debt securities that are not actively traded, such as loans received, loans granted and financial liabilities, is determined by discounting future cash flows. Discounting takes place using current customary market interest rates through the remaining terms of the financial instruments. Fair value measurement was not applied in the case of shareholdings with a carrying amount of €58.3 million (2006: €58.3 million) as cash flows could not be determined reliably for them. Fair values could not be derived on the basis of comparable transactions. The shareholdings are not material by comparison with the overall position of the Group.

The fair value of commercial paper and borrowings under revolving short-term credit facilities and of trade receivables is used as the fair value due to the short maturities of these instruments.

See Note 30 for information on the determination of the fair value of derivative financial instruments.

The following two tables illustrate the contractually agreed (undiscounted) cash outflows arising from the financial liabilities included in the scope of IFRS 7:

Cash Flow Analysis

December 31, 2007 Cash Cash Cash Cash outflows outflows outflows outflows € in millions 2008 2009 2010–2012 from 2013 Financial liabilities to entities in which an ownership interest exists . . . 2,099 5 16 23 Bonds ...... 1,018 5,324 4,648 12,024 Commercial paper ...... 2,026 — — — Bank loans/Liabilities to banks ...... 1,112 144 713 221 Liabilities from finance leases with third parties ...... 52 25 63 278 Other financial liabilities ...... 175 97 225 379 Cash outflows for financial liabilities ...... 6,482 5,595 5,665 12,925 Liabilities to entities in which an ownership interest exists ...... 473 11 5 49 Trade payables ...... 4,477 — — — Derivatives (with/without hedging relationships) ...... 27,758 13,339 9,007 10,333 Put option liabilities under IAS 32 ...... 131 327 125 185 Other operating liabilities ...... 6,026 32 136 368 Cash outflows for trade payables and other operating liabilities ... 38,865 13,709 9,273 10,935 Cash outflows for liabilities within the scope of IFRS 7 ...... 45,347 19,304 14,938 23,860

F-81 Cash Flow Analysis

December 31, 2006 Cash Cash Cash Cash outflows outflows outflows outflows € in millions 2008 2009 2010–2012 from 2013 Financial liabilities to entities in which an ownership interest exists . . . 1,982 4 19 20 Bonds ...... 790 679 5,658 6,541 Commercial paper ...... 367 — — — Bank loans/Liabilities to banks ...... 523 130 574 194 Liabilities from finance leases with third parties ...... 56 42 70 285 Other financial liabilities ...... 487 89 42 113 Cash outflows for financial liabilities ...... 4,205 944 6,363 7,153 Liabilities to entities in which an ownership interest exists ...... 305 — — 53 Trade payables ...... 5,311 — — — Derivatives (with/without hedging relationships) ...... 22,555 9,027 12,445 11,157 Put option liabilities under IAS 32 ...... 2,187 292 101 136 Other operating liabilities ...... 4,168 128 100 21 Cash outflows for trade payables and other operating liabilities ... 34,526 9,447 12,646 11,367 Cash outflows for liabilities within the scope of IFRS 7 ...... 38,731 10,391 19,009 18,520

For financial liabilities that bear floating interest rates, the rates that were fixed on the balance sheet date are used to calculate future interest payments for subsequent periods as well. Financial liabilities that can be terminated at any time are assigned to the earliest maturity time band in the same way as put options that are exercisable at any time.

In gross-settled derivatives (usually currency derivatives and commodity derivatives), outflows are accompanied by related inflows of funds or commodities.

The net gains and losses from financial instruments by IAS 39 category are shown in the following table:

Net Gains and Losses by Category1

€ in millions 2007 2006 Loans and receivables ...... 385 520 Available for sale ...... 1,533 847 Held for trading ...... 446 (1,858) Amortized cost ...... (929) (989) Total ...... 1,435 (1,480)

(1) The categories are described in detail in Note 2.

In addition to interest income and expenses from financial receivables, the net gains and losses in the loans and receivables category consist primarily of valuation allowances on trade payables. Gains and losses on the disposal of available-for-sale securities and equity investments are reported under other operating income and other operating expenses, respectively.

In addition, the interest income and expenses from interest-bearing securities is included in this net result.

The net gains and losses in the held-for-trading category encompass both the changes in fair value of the derivative financial instruments and the gains and losses on realization.

F-82 Risk Management Principles The prescribed processes, responsibilities and actions concerning financial and risk management are described in detail in internal risk management guidelines applicable throughout the Group. The market units have developed additional guidelines of their own within the confines of the Group’s overall guidelines. To ensure efficient risk management at the E.ON Group, the Trading (Front Office), Financial Settlement (Back Office) and Risk Controlling (Middle Office) departments are organized as strictly separate units. A new department was set up in 2007 at Group level to manage all risk controlling and reporting in the area of commodities, while risk controlling and reporting in the areas of interest rates and currencies remains the responsibility of the Financial Controlling department.

The Company uses a Group-wide treasury, risk management and reporting system. This system is a standard information technology solution and is both fully integrated and continuously updated. The system is designed to provide for the analysis and monitoring of the E.ON Group’s exposure to liquidity, foreign exchange and interest risks. The market units employ established systems for commodities.

Counterparty risks are monitored on a Group-wide basis by Financial Controlling, with the support of a standard software package.

A separate Risk Committee is responsible for the maintenance and further development of the strategy set by the Board of Management of E.ON AG with regard to commodity and credit risk management policies.

1. Liquidity Management The primary objectives of E.ON’s internal liquidity management consist of ensuring ability to pay at all times, the timely fulfillment of all payment obligations and the optimization of costs within the E.ON Group.

In order to control liquidity, the Group’s financial guidelines provide for a general obligation to tender in the case of financial transactions by companies of which E.ON is the sole owner. Cash pooling and external financing are largely centralized at E.ON AG and certain financing companies. The funds are transferred internally to the other Group companies as needed.

While maintaining a strategic credit line reserve, E.ON AG makes arrangements with banks for sufficient liquidity on the basis of current liquidity planning. The subsidiaries submit their liquidity requirements to E.ON AG.

2. Price Risks In the normal course of business, the E.ON Group is exposed to foreign exchange, interest and commodity price risks, and also to price risks in equity investments in the context of cash investment activities. These risks create volatility in earnings, equity and cash flows from period to period. The Company makes use of derivative financial instruments in various strategies to limit or eliminate these risks.

The following discussion of the Company’s risk management activities and the estimated amounts generated from profit-at-risk, value-at-risk and sensitivity analyses are “forward-looking statements” that involve risks and uncertainties. Actual results could differ materially from those projected due to actual, unforeseeable developments in the global financial markets. The methods used by the Company to analyze risks, as discussed below, should not be considered projections of future events or losses. The Company also faces risks that are either non-financial or non-quantifiable. Such risks principally include country risk, operational risk and legal risk, which are not represented in the following analyses.

F-83 Foreign Exchange Risk Management Due to the international nature of some of its business activities, the E.ON Group is exposed to exchange risks related to sales, assets, receivables and liabilities denominated in foreign currencies, investments in foreign operations and anticipated foreign currency payments. The Company’s exposure results mainly from transactions in U.S. dollars, British pounds, Hungarian forint, Swedish kronor and Russian rubles, and from net investments in foreign operations.

E.ON AG is responsible for controlling the currency risks to which the E.ON Group is exposed, and sets appropriate risk parameters. The subsidiaries are responsible for controlling their operating currency risks. Recognized assets and liabilities are generally hedged in the full amount. For unrecognized firm commitments, hedging takes place after consultation between the subsidiary and E.ON AG.

The foreign exchange risk arising from net investments in foreign operations with a functional currency other than the euro is reduced at Group level as needed through hedges of net investments. In addition, borrowings are made in foreign currency to control foreign exchange risks.

In line with the Company’s internal risk-reporting process and international banking standards, market risk has been calculated using the value-at-risk method on the basis of historical market data. The value-at-risk (or “VaR”) is equal to the maximum potential loss (on the basis of a probability of 99 percent) from foreign-currency positions that could be incurred within the following business day. The calculations take account of correlations between individual transactions; the risk of a portfolio is generally lower than the sum of its individual risks.

The one-day value-at-risk from the translation of deposits and borrowings denominated in foreign currency, plus foreign currency derivatives, amounted to €148 million (2006: €54 million) and, as in 2006, resulted primarily from the open positions denominated in British pounds and U.S. dollars. The increase in the VaR over the previous year is due in particular to the increased volatility of the EUR/GBP exchange rate and to overall higher volumes denominated in foreign currency.

This VaR has been calculated in accordance with the requirements of IFRS 7. In practice, however, another value will result, since certain underlying transactions (e.g., scheduled transactions and off-balance-sheet own-use agreements) are not considered in the calculation according to IFRS 7.

Interest Risk Management Several line items on the Consolidated Balance Sheet and certain financial derivatives are based on fixed interest rates, and are therefore subject to changes in fair value resulting from changes in market rates. In the case of balance sheet items and financial derivatives based on floating interest rates, E.ON is exposed to profit risks. E.ON seeks to maintain a specific mix of fixed and floating-rate debt in its overall debt portfolio. The Company uses interest rate swaps in order to benefit from the spread between short-term and long term interest rates and from any potential easing of interest rates in general.

As of December 31, 2007, the E.ON Group has entered into interest rate swaps with a nominal value of €9,767 million (2006: €8,371 million).

A sensitivity analysis was performed on the Group’s short-term and variable-rate borrowings, including interest rate derivatives. A one-percent increase (decline) in the level of interest rates would cause net interest expense to rise (fall) by €30 million per annum (2006: €35 million).

Commodity Price Risk Management E.ON is exposed to substantial risks resulting from fluctuations in the prices of commodities, both on the supply and demand side. This risk is measured based on potential negative deviation from the target adjusted EBIT.

F-84 The maximum permissible risk is determined centrally by the Board of Management in its medium-term planning and translated into a decentralized limit structure in coordination with the market units. Before fixing any limits, the investment plans and all other known obligations and quantifiable risks have been taken into account.

E.ON conducts commodity transactions primarily within the system portfolio, which includes core operations, existing sales and procurement contracts and any energy derivatives used for hedging purposes or for power plant optimization. The risk in the system portfolio thus arises from the open position between planned procurement and generation and planned sales volumes. The risk of these open positions is measured using the profit-at-risk (“PaR”) number, which quantifies the risk by taking into account the size of the open position and the prices, the volatility and the liquidity of the underlying commodities. PaR is defined as the maximum potential negative change in the value of the portfolio at a probability of 95 percent in the event that the open position is closed as quickly as possible.

The principal derivative instruments used by E.ON to cover commodity price risk exposures are electricity, gas, coal and oil swaps and forwards, as well as emissions-related derivatives. Commodity derivatives are used by the market units for the purposes of price risk management, system optimization, equalization of burdens and improvement of margins. Proprietary trading is permitted only within very tightly defined limits. The risk metric used for the proprietary trading portfolio is a five-day value-at-risk with a 95-percent confidence interval.

The trading limits for proprietary trading as well as for all other trading activities are established and monitored by bodies that are independent from trading operations. Limits used on hedging and proprietary trading activities include five-day value-at-risk and profit-at-risk numbers, as well as stop-loss limits. Additional key elements of the risk management system are a set of Group-wide commodity risk guidelines, the clear division of duties between scheduling, trading, settlement and controlling, as well as a risk reporting system independent of the trading operations. Group-wide developments in commodity risks are reported to the Risk Committee on a monthly basis.

As of December 31, 2007, the E.ON Group has entered into electricity, gas, coal, oil and emissions-related derivatives with a nominal value of €57,204 million (2006: €57,158 million).

The VaR for the proprietary trading portfolio amounted to €13 million as of December 31, 2007 (2006: €16 million). The PaR for the financial instruments in the scope of IFRS 7 included in the system portfolio was €433 million as of December 31, 2007 (2006: €289 million).

The restriction to financial instruments included in the scope of IFRS 7 that has been applied in this calculation does not reflect the economic position of the E.ON Group. Consequently, none of the off-balance sheet transactions, such as own-use contracts under normal trading relationships, may be included when calculating the PaR according to IFRS 7, even though such transactions represent a material component of the economic position. The PaR reflecting the actual economic position therefore differs significantly from the PaR determined in accordance with IFRS 7.

Equity Risk The value of all exchange-traded equity investments on the balance sheet date was €13,457 million (2006: €12,871 million). The most significant component of these investments is the interest in Gazprom, which is valued at €13,061 million (2006: €11,918 million). This investment is treated as strategic and is not being hedged at this time. Some additional equity positions held are hedged using forward transactions. The nominal volume of these forward transactions totaled €97 million as of the balance sheet date (2006: €567 million). All exchange traded equity investments are classified as available for sale. Changes in value are generally shown as a change in OCI.

F-85 Credit Risk Management Credit risk management involves the identification, measurement and control of credit risks. Credit risk results from non delivery or partial delivery by a counterparty of the agreed consideration for services rendered or of payments owing on existing accounts receivable, and from the additional expenses for replenishment of the funds thus lost.

In order to minimize credit risk arising from the use of financial instruments and from operating activities, the Company enters into transactions only with counterparties that satisfy the Company’s internally established minimum requirements. Maximum credit risk limits are set on the basis of internally established credit quality ratings. The setting and monitoring of credit limits is subject to certain minimum requirements applicable throughout the Group. Not included in this process are long-term contracts arising from the operating activities and asset management transactions. Some of these are monitored separately at market unit level.

In principle, the respective Group companies are responsible for managing the credit risks in their operating activities. Depending on the nature of the operating activities and the level of the credit limit, additional credit risk monitoring and controls take place at both market unit and Group levels. Monthly reports on the levels of credit limits, and on their utilization by significant counterparties in the areas of financial and energy trading, are forwarded to the E.ON Risk Committee.

The carrying amounts of primary and derivative financial assets plus the financial guarantees made represent the maximum credit risk as of the reference date.

To the extent possible, pledges of collateral are negotiated with counterparties for the purpose of reducing credit risk. Accepted as collateral are guarantees issued by the respective parent companies of counterparties or evidence of profit-and-loss-pooling agreements in combination with letters of awareness. To a lesser extent, the Company also requires bank guarantees and deposits of cash and securities as collateral to reduce credit risk. The levels and backgrounds of financial assets received as collateral is described in more detail in Note 26.

Derivative transactions are generally executed on the basis of standard agreements that allow for the netting of all outstanding transactions with individual counterparties. For currency and interest rate derivatives in the banking sector, this netting option is reflected in the accounting treatment. Although the greater part of the transactions was completed on the basis of contracts that do allow netting, the table on the following page does not show netting of positive and negative fair values of continuous transactions. Moreover, collateral received is not taken into account. This means that the counterparty risk is shown to be higher in the following table than it actually is. The counterparty risk is equal to the sum of the positive fair values. In summary, as of December 31, 2007, the Company’s derivative financial instruments had the credit ratings and maturities shown in the table. Because derivatives in particular are subject to significant market fluctuations, short-term concentrations of credit risk may occur. For that reason, the credit risk concentrations arising from derivative receivables are shown separately.

F-86 Rating of Counterparties Standard & Poor’s and/or Moody’s December 31, 2007 Total Up to 1 year 1 to 5 years More than 5 years Nominal Counter- Nominal Counter- Nominal Counter- Nominal Counter- € in millions value party risk value party risk value party risk value party risk AAA and Aaa through AA- and Aa3 ...... 38,474.2 2,235.0 17,384.4 1,000.1 16,163.8 901.3 4,926.0 333.6 AA- and A1 or A+ and Aa3 through A- and A3 ...... 27,355.1 2,030.8 14,778.1 1,229.3 10,149.3 728.3 2,427.7 73.2 A- and Baa1 or BBB+ and A3 through BBB- or Baa3 ...... 3,396.0 325.5 2,352.0 220.9 948.6 95.7 95.4 8.9 BBB- and Ba1 or BB+ and Baa3 through BB- and Ba3 4,662.7 211.9 1,583.9 132.1 2,647.0 47.2 431.8 32.6 Other (1) ...... 19,353.9 387.6 11,590.8 141.3 4,706.7 181.6 3,056.4 64.7 Total ...... 93,241.9 5,190.8 47,689.2 2,723.7 34,615.4 1,954.1 10,937.3 513.0

(1) This position consists primarily of parties to contracts with respect to which E.ON has received collateral from counterparties with ratings of the above categories or with an equivalent internal rating.

Rating of Counterparties Standard & Poor’s and/or Moody’s December 31, 2006 Total Up to 1 year 1 to 5 years More than 5 years Nominal Counter- Nominal Counter- Nominal Counter- Nominal Counter- € in millions value party risk value party risk value party risk value party risk AAA and Aaa through AA- and Aa3 ...... 34,452.3 1,941.3 13,592.5 941.2 15,000.6 616.8 5,859.2 383.3 AA- and A1 or A+ and Aa3 through A- and A3 ...... 22,849.7 1,585.1 9,319.7 944.5 11,607.9 585.5 1,922.1 55.1 A- and Baa1 or BBB+ and A3 through BBB- or Baa3 ...... 3,511.6 279.8 2,181.4 218.1 1,084.5 61.7 245.7 0.0 BBB- and Ba1 or BB+ and Baa3 through BB- and Ba3 2,032.2 156.4 1,196.6 111.1 827.3 45.3 8.3 0.0 Other (1) ...... 25,482.2 395.9 11,125.1 200.3 6,332.5 93.2 8,024.6 102.4 Total ...... 88,328.0 4,358.5 37,415.3 2,415.2 34,852.8 1,402.5 16,059.9 540.8

(1) This position consists primarily of parties to contracts with respect to which E.ON has received collateral from counterparties with ratings of the above categories or with an equivalent internal rating.

Exchange-traded forward and option contracts as well as emissions-related derivatives having an aggregate nominal value of €12,200 million as of December 31, 2007, (2006: €8,182 million) bear no counterparty risk.

Asset Management For the purpose of financing long-term payment obligations, including those relating to asset retirement obligations (see Note 25), financial investments totaling €7.3 billion (2006: €8.9 billion) were held by companies of the Central Europe market unit as of December 31, 2007.

These financial assets are invested on the basis of an accumulation strategy (total-return approach), with investments broadly diversified across money market instruments, bonds, real estate and equities. Asset

F-87 allocation studies are performed by external financial advisors at regular intervals to determine the target portfolio structure. The majority of the assets are held in investment funds managed by external fund managers. Risk management for the funds is based on a value-at-risk method, with the VaR figures derived from a three month holding period and a confidence interval of 98 percent. The VaR determined for 2007 using these parameters was €202 million (2006: €383 million). Corporate Asset Management at E.ON AG, which is part of the Company’s Finance Department, is responsible for continuous monitoring of overall risks and those concerning individual fund managers.

At year-end 2007, VKE, which is organized in the form of a German mutual insurance fund (“Versicherungsverein auf Gegenseitigkeit”), managed a total of €2.4 billion (2006: €2.3 billion) in financial assets dedicated almost exclusively to the coverage of employee retirement benefits in the Central Europe market unit. The pension plan assets held by VKE do not constitute plan assets under IAS 19 and are shown as both non-current and current assets on the balance sheet. VKE is subject to the provisions of the Insurance Supervision Act (“Versicherungsaufsichtsgesetz” or “VAG”) and its operations are supervised by the German Federal Financial Supervisory Authority (“Bundesanstalt für Finanzdienstleistungsaufsicht” or “BaFin”). Financial investments and continuous risk management are conducted within the regulatory confines set by BaFin. The majority of the diversified portfolio, consisting of money market instruments, bonds, real estate and equities, is held in investment funds managed by external fund managers. The 3-month VaR with a confidence interval of 98 percent for the assets managed by VKE was €118 million in 2007 (2006: €71 million).

(32) TRANSACTIONS WITH RELATED PARTIES E.ON exchanges goods and services with a large number of companies as part of its continuing operations. Some of these companies are related companies accounted for under the equity method or reported at fair value. Transactions with related parties are summarized as follows:

Related-Party Transactions

€ in millions 2007 2006 Income ...... 6,626 7,467 Expenses ...... 4,407 3,804 Receivables ...... 1,988 1,892 Liabilities ...... 3,116 2,440

Income from transactions with related companies is generated mainly through the delivery of gas and electricity to distributors and municipal entities, especially municipal utilities. The relationships with these entities do not generally differ from those that exist with municipal entities in which E.ON does not have an interest.

Expenses from transactions with related companies are generated mainly through the procurement of gas, coal and electricity.

Receivables from related companies consist mainly of trade receivables.

Liabilities of E.ON payable to related companies include €515 million (2006: €286 million) in trade payables to operators of jointly-owned nuclear power plants. These payables bear interest at 1.0 percent per annum (2006: 1.0 percent) and have no fixed maturity. E.ON procures electricity from these power plants both under a cost-transfer agreement and under a cost-plus-fee agreement. The settlement of such liabilities occurs mainly through clearing accounts. In addition, E.ON reported financial liabilities in 2007 of €1,233 million (2006: €1,255 million) resulting from fixed-term deposits undertaken by the jointly-owned nuclear power plants at E.ON.

F-88 The transfer of E.ON’s minority stake in Degussa into RAG Projektgesellschaft mbH and the subsequent forward sale of that company to RAG produced a gain of €596 million in 2006. For additional information, see Note 4.

Under IAS 24, compensation paid to key management personnel (i.e., the members of the Board of Management of E.ON AG) must be disclosed. The total expense for 2007 amounted to €16.1 million (2006: €16.5 million) in short-term benefits and €3.0 million (2006: €3.3 million) in post-employment benefits.

The service cost of post-employment benefit is equal to the service cost of the provisions for pensions.

The expense determined in accordance with IFRS 2 for the tranches of the E.ON SAR Program and the E.ON Share Performance Plan in existence in 2007 was €11.4 million (2006: €17.7 million).

Detailed and individualized information on compensation can be found on pages 117 through 121 of the Compensation Report.

(33) SEGMENT INFORMATION The reportable segments of the E.ON Group are presented in line with the Company’s internal organizational and reporting structure. • The Central Europe market unit focuses on E.ON’s integrated electricity business and the downstream gas business in central Europe. • Pan-European Gas is responsible for the upstream and midstream gas business. Additionally, this market unit holds a number of minority shareholdings in the downstream gas business. • The U.K. market unit encompasses the integrated energy business in the United Kingdom. • The Nordic market unit is concentrated on the integrated energy business in Northern Europe. • The U.S. Midwest market unit is primarily active in the regulated energy market in the U.S. state of Kentucky. • Corporate Center/New Markets contains those interests managed directly by E.ON AG that have not been allocated to any of the other segments, including the operations acquired in 2007 in Russia and in the area of renewable energy (see also Note 4), as well as E.ON AG itself and consolidation effects at the Group level.

Under IFRS segments or material business units that have been sold or are held for sale must be reported as discontinued operations. In 2007, this includes WKE, which is held for sale.

In 2006, E.ON Finland and Degussa, which had been sold in June and August of 2006 respectively, were reported as discontinued operations along with WKE. The corresponding figures as of December 31, 2007, as well as those for the preceding period, have been adjusted for all components of the discontinued operations (see explanations in Note 4).

Adjusted EBIT is used as the key figure at E.ON for purposes of internal management control and as an indicator of a business’s long-term earnings power. Adjusted EBIT is derived from income/loss before interest and taxes and adjusted to exclude certain special items. The adjustments include adjusted net interest income, net book gains, cost-management and restructuring expenses, and other non-operating income and expenses.

Adjusted net interest income is calculated by taking the net interest income shown in the income statement and adjusting it using economic criteria and excluding certain special items, i.e., the portions of interest expense that are non-operating. Net book gains are equal to the sum of book gains and losses from disposals, which are

F-89 included in other operating income and other operating expenses. Cost-management and restructuring expenses are non-recurring in nature. Other non-operating earnings encompass other non-operating income and expenses that are unique or rare in nature. Depending on the case, such income and expenses may affect different line items in the income statement. For example, effects from the marking to market of derivatives are included in other operating income and expenses, while impairment charges on property, plant and equipment are included in depreciation, amortization and impairments.

Due to the adjustments, the key figures by segment may differ from the corresponding IFRS figures reported in the Consolidated Financial Statements.

The following table shows the reconciliation of adjusted EBIT to net income as reported in the IFRS Consolidated Financial Statements:

Net Income

€ in millions 2007 2006 Adjusted EBIT ...... 9,208 8,356 Adjusted interest income (net) ...... (960) (948) Net book gains ...... 1,345 829 Restructuring expenses ...... (77) — Other non-operating earnings ...... 167 (2,890) Income/Loss from continuing operations before taxes ...... 9,683 5,347 Income taxes ...... (2,289) (40) Income/Loss from continuing operations ...... 7,394 5,307 Income/Loss from discontinued operations, net ...... 330 775 Net income ...... 7,724 6,082 Attributable to shareholders of E.ON AG ...... 7,204 5,586 Attributable to minority interests ...... 520 496

Net book gains in 2007 increased by €516 million over the previous year. As in 2006, they were generated primarily from the sale of securities at the Central Europe market unit.

In 2007, cost-management and restructuring expenses arose primarily in the U.K. market unit’s retail customer business. In 2006 there were no cost-management and restructuring expenses.

Other non-operating earnings resulted primarily from the marking to market of derivatives (€564 million) used to protect the operating businesses from fluctuations in prices. This improvement was attributable primarily to gains of €2.5 billion at the U.K. and Pan-European Gas market units.

F-90 Financial Information by Business Segment

Corporate Center/New Central Europe Pan-European Gas U.K. Nordic U.S. Midwest Markets E.ON Group € in millions 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 External sales ...... 31,350 26,384 19,714 20,555 12,455 12,355 3,216 2,740 1,819 1,930 177 127 68,731 64,091 Intersegment sales ...... 679 813 3,031 2,392 129 163 123 87 — — (3,962) (3,455) — — Sales ...... 32,029 27,197 22,745 22,947 12,584 12,518 3,339 2,827 1,819 1,930 (3,785) (3,328) 68,731 64,091 Adjusted EBITDA ...... 6,222 5,747 3,176 3,092 1,657 1,804 1,027 871 543 595 (175) (385) 12,450 11,724 Depreciation and amortization ...... (1,521) (1,495) (530) (502) (521) (554) (345) (359) (155) (163) (51) (14) (3,123) (3,087) Impairments (1) ...... (31) (17) (70) (243) — (11) (12) — — (6) (6) (4) (119) (281) Adjusted EBIT ...... 4,670 4,235 2,576 2,347 1,136 1,239 670 512 388 426 (232) (403) 9,208 8,356 Earnings from companies accounted for under the equity method (1) ..... 317 315 696 536 24 6 10 1 23 21 8 (10) 1,078 869 Cash provided by operating activities ...... 3,811 3,802 3,041 604 1,615 724 914 715 216 381 (871) 935 8,726 7,161 F-91 Investments ...... 2,581 2,279 2,424 882 1,364 863 914 642 690 398 3,333 (27) 11,306 5,037 Intangible assets and property, plant and equipment ...... 2,390 1,883 1,381 377 1,364 860 892 592 690 398 199 (14) 6,916 4,096 Equity investments (2) .... 191 396 1,043 505 — 3 22 50 — — 3,134 (13) 4,390 941 Total assets ...... 63,442 59,093 39,090 36,994 18,170 19,636 11,759 11,290 8,130 8,387 (3,297) (7,825) 137,294 127,575 Intangible assets ...... 1,889 1,965 1,137 867 675 793 213 229 13 20 357 20 4,284 3,894 Property, plant and equipment ...... 18,375 17,664 6,746 6,289 7,506 7,157 7,429 7,184 4,153 4,000 4,343 190 48,552 42,484 Companies accounted for under the equity method ...... 2,134 1,962 5,602 5,276 2 8 357 383 32 40 284 101 8,411 7,770 (1) Impairments recognized in adjusted EBIT differ from the relevant amounts reported in accordance with IFRS due to impairments on equity-method companies and other financial assets, which under IFRS are included in income/loss (-) from companies accounted for under the equity method and financial results, respectively. In 2007, differences resulted primarily from impairment charges and reversals recognized on equity investments.In 2006, differences were primarily due to impairments stemming from regulation on property, plant and equipment and on equity investments at the Central Europe and Pan-European Gas market units. (2) In addition to those accounted for using the equity method, equity investments also include acquisitions of fully consolidated companies and investments in equity holdings that need not be consolidated. These gains were offset by costs associated with the attempted acquisition of Endesa (€288 million) and the severe storm in Sweden at the beginning of 2007 (€95 million). In 2006, the reduction of network charges enforced by the German Federal Network Agency (“Bundesnetzagentur”) resulted in impairment charges totaling €374 million at the Central Europe and Pan-European Gas market units in the gas distribution networks and in minority shareholdings with activities in the area of networks. Moreover, additional impairments had to be recorded for gas storage facilities and CHP plants at the U.K. market unit (€187 million), as well as for property, plant and equipment at the Pan-European Gas and Nordic market units (€100 million in total).

Adjusted Interest Income (Net)

€ in millions 2007 2006 Interest and similar expenses (net) as shown in the Consolidated Statements of Income ...... (951) (1,045) Non-operating interest expense (+)/income (–) ...... (9) 97 Adjusted interest income (net) ...... (960) (948)

An additional adjustment to the internal profit analysis relates to interest income, which is adjusted on an economic basis. Adjusted net interest income is calculated by taking the net interest income shown in the income statement and adjusting it using economic criteria and excluding certain special (i.e., non-operating) items.

Adjusted net interest income is largely unchanged from 2006. Compared with 2006, net interest and similar expenses decreased primarily due to increases in expected returns on plan assets. This is offset at Group level by an increase in net non-operating interest income. The positive change in non-operating interest income is due to reduced interest expense incurred in connection with put options.

Transactions within the E.ON Group are generally effected at market prices.

Geographic Segmentation The following table details external sales (by location of customers and by location of seller) and property, plant and equipment information by geographic area:

Geographic Segment Information

Europe (euro area excluding Germany Germany) Europe (other) United States Other Total € in millions 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 External sales by location of customer ...... 36,895 34,929 4,491 3,783 25,520 23,431 1,769 1,884 56 64 68,731 64,091 External sales by location of seller ...... 40,614 38,942 2,780 2,051 23,518 21,168 1,768 1,879 51 51 68,731 64,091 Property, plant and equipment ...... 18,898 18,380 1,573 1,104 23,107 18,999 4,910 3,928 64 73 48,552 42,484

Information on Major Customers and Suppliers E.ON’s customer structure in 2007 and 2006 did not result in any major concentration in any given geographical region or business area. Due to the large number of customers the Company serves and the variety of its business activities, there are no individual customers whose business volume is material compared with the Company’s total business volume.

Gas is procured primarily from Russia, Norway, Germany, the Netherlands and the United Kingdom.

F-92 (34) COMPENSATION OF SUPERVISORY BOARD AND BOARD OF MANAGEMENT Supervisory Board Provided that E.ON’s shareholders approve the proposed dividend at the Annual Shareholders Meeting on April 30, 2008, total remuneration to members of the Supervisory Board will be €4.5 million (2006: €4.1 million).

There were no loans to members of the Supervisory Board in 2007.

The Supervisory Board’s compensation structure and the amounts for each member of the Supervisory Board are presented on pages 117 through 121 of the Compensation Report, which is part of the Combined Group Management Report.

Additional information regarding members of the Supervisory Board is provided on pages 19 and 212.

Board of Management Total remuneration to members of the Board of Management in 2007 amounted to €20.4 million (2006: €21.7 million). This consisted of base salary, bonuses, other compensation elements and share-based payments.

Total payments to former members of the Board of Management and their beneficiaries amounted to €6.6 million (2006: €11.7 million). Provisions of €97.4 million (2006: €99.9 million) have been established for the pension obligations to former members of the Board of Management and their beneficiaries.

There were no loans to members of the Board of Management in the 2007 fiscal year.

The Board of Management’s compensation structure and the amounts for each member of the Board of Management are presented on pages 117 through 121 of the Compensation Report, which is part of the Combined Group Management Report.

Additional information regarding members of the Board of Management is provided on pages 14, 15 and 213.

(35) E.ON GROUP IFRS RECONCILIATIONS Explanatory Notes Concerning the Transition of Group Accounting Policies to International Financial Reporting Standards (IFRS) E.ON has prepared its first Consolidated Financial Statements in accordance with IFRS for the year ended December 31, 2007. The effective date of the E.ON Group’s IFRS Consolidated Opening Balance Sheet is January 1, 2006 (the date of transition to IFRS according to IFRS 1).

According to IFRS 1, the first IFRS Consolidated Financial Statements must use recognition and measurement principles that are based on standards and interpretations that are mandatory at December 31, 2007, the date of first-time preparation of Consolidated Financial Statements according to IFRS, provided these have been published effective December 31, 2007, and adopted by the EU. These accounting and measurement principles must be applied retrospectively to the date of transition to IFRS and for all periods presented within the first IFRS Consolidated Financial Statements.

Any resulting differences between the carrying amounts of assets and liabilities according to IFRS as of January 1, 2006, compared with those presented in the U.S. GAAP Consolidated Balance Sheet as of December 31, 2005, were recognized in equity within the IFRS opening balance sheet.

F-93 As provided for by IFRS 1, E.ON has applied the mandatory exceptions as well as certain optional exemptions described in the following text to the retrospective application of IFRS.

Explanation of the IFRS 1 Exemptions Applied by E.ON In the IFRS Consolidated Opening Balance Sheet as of January 1, 2006, the carrying amounts of assets and liabilities from the U.S. GAAP balance sheet as of December 31, 2005, are generally recognized and measured according to those IFRS regulations in effect on December 31, 2007. For certain individual cases, however, IFRS 1 provides for optional exemptions to the general principle of retrospective application of IFRS. The following discussion describes the exemptions that E.ON has made use of in preparing its IFRS Consolidated Opening Balance Sheet.

Business Combinations E.ON has elected to utilize the option under IFRS 1 not to apply the provisions of IFRS 3 retrospectively to business combinations that took place prior to the transition to IFRS. The presentation of these business combinations according to U.S. GAAP was maintained. In general, all of those assets and liabilities that were acquired in a business combination and that fulfill the IFRS recognition criteria must be recognized in the IFRS consolidated opening balance sheet. Furthermore assets and liabilities that were not recognized under U.S. GAAP but are subject to recognition under IFRS are recognized in the IFRS opening balance sheet. Any resulting adjustment amounts are recognized in retained earnings with no effect on net income unless they pertain to intangible assets whereby an adjustment of the goodwill determined under U.S. GAAP would be required. As no adjustment for intangible assets was required relating to such business combinations, the goodwill previously reported under U.S. GAAP was maintained in E.ON’s opening balance sheet under IFRS.

Goodwill must be tested for impairment at the time of transition to IFRS. No impairment was determined by E.ON at the time of transition.

Cumulative Translation Differences E.ON has elected to utilize the exemption provided for under IFRS 1 whereby the unrealized cumulative translation differences resulting from the translation of financial statements into the reporting currency of E.ON and previously reported within other comprehensive income may be recognized in full within equity at the time of transition to IFRS.

In a subsequent disposal of an enterprise, only those foreign currency translation differences that were recognized in equity after the preparation of the opening balance sheet are recognized in the gain or loss on disposal.

Significant Effects of Transition from U.S. GAAP to IFRS The following reconciliations and their associated explanatory notes provide an overview of the effects of transition to IFRS. The adjustments are presented in the following sections: • Equity as of January 1, 2006 • Equity as of December 31, 2006 • Net income for the fiscal year from January 1, 2006, through December 31, 2006

F-94 Reconciliation of Equity Reconciliation of Equity

December 31, January 1, € in millions Reference 2006 2006 Equity under U.S. GAAP ...... 47,845 44,484 Changes in the presentation of minority interests ...... a 4,917 4,734 Equity under U.S. GAAP, including minority interests ...... 52,762 49,218 Effects of IAS 32 ...... b (2,780) (3,249) Inventories ...... c 348 134 Pensions and similar obligations ...... d (81) (1,391) Miscellaneous provisions ...... e (129) (43) Derivatives ...... f 226 (566) Valuation of available-for-sale financial instruments ...... g 370 377 U.S. regulation ...... h 279 403 Income taxes ...... i 223 800 Other ...... j 27 286 Total adjustments ...... (1,517) (3,249) Equity under IFRS ...... 51,245 45,969

a) Changes in the Presentation of Minority Interests Under IFRS, minority interests of third parties in the Group are reported as part of equity. Under U.S. GAAP, minority interests are reported separately from shareholders’ equity.

b) Effects of IAS 32 Put Options on Minority Interests Financial instruments for which a right of repayment exists for the investor do not constitute equity instruments under the IFRS definition of equity. E.ON has made conditional and unconditional commitments to certain minority shareholders to acquire the outstanding shares. As a result, a liability in the amount of the present value of the future exercise price must be reported. This reclassification from equity is irrespective of the probability of exercise and is reported separately within minority interests.

Under U.S. GAAP, these potential commitments are generally reported similar to derivatives at fair value.

Minority Interests in German Partnerships Under German corporate law, shareholders of a German partnership have a statutory, non-excludable right of termination. Under IAS 32, this right of termination causes the minority interests in the Group to be considered repayable. Accordingly, a corresponding liability at the present value of the expected settlement amount must be reclassified from equity, irrespective of the probability of exercise. The reclassification is reported separately within minority interests.

Under U.S. GAAP, these partnership interests are shown under minority interests.

In total, these effects resulted in a reduction in equity of €3,249 million within the opening balance sheet (December 31, 2006: –€2,780 million).

F-95 c) Inventories Under U.S. GAAP, gas inventories were generally measured at LIFO. Under IAS 2, “Inventories” (“IAS 2”), this measurement method is not allowed. The adjustment to average-cost measurement of gas inventories resulted in an increase in equity of €134 million within the opening balance sheet (December 31, 2006: €348 million).

d) Pensions and Similar Obligations Both U.S. GAAP and IFRS require the formation of provisions for pension obligations. Differences in the opening balance sheet in the values recognized under IAS 19, and SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS 87”), resulted in particular from the election to recognize all cumulative actuarial gains and losses in equity under IFRS. As part of the transition, the intangible pension asset and the prepaid pension asset as well as the additional minimum liability were eliminated. As a result, equity decreased by €1,391 million within the opening balance sheet (December 31, 2006: –€81 million). The further decline by December 31, 2006, is predominantly due to the first-time application of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”), which also requires recognition of actuarial gains and losses within equity.

e) Miscellaneous Provisions Under IFRS, long-term provisions must generally be discounted at the market interest rate applicable as of the respective balance sheet date if the effect resulting from discounting (the difference between present value and repayment amount) is material. In contrast, U.S. GAAP sets more stringent requirements with regard to discountability, with the result that under IFRS, more provisions are recognized at their lower present values.

A further difference exists with regard to the subsequent measurement of provisions for asset retirement obligations. Under both U.S. GAAP and IFRS, the acquisition or production costs of property, plant and equipment must be increased to include future asset retirement cost. The increased amount is amortized over the useful life of the corresponding asset. Each subsequent remeasurement of the provision under IFRS leads to an increase or a reduction of the entire cost of the asset to be decommissioned, while a remeasurement under U.S. GAAP leads to an increase or a reduction of only the asset retirement cost. Remeasurements of this type only affect the income statement if a reduction of the provision causes the carrying amount of the corresponding asset (or, under U.S. GAAP, the asset retirement cost portion) to be reduced to zero; in this case, each further reduction of the provision is recognized in income. As a consequence of the different definitions of the corresponding asset items, remeasurements of asset retirement obligations are less frequently recognized within the income statement under IFRS than under U.S. GAAP.

A further reduction in equity resulted from the different treatment of the bonus features (“Aufstockungsbeträge”) of early retirement arrangements under IFRS.

In total, the differences in the accounting for other provisions resulted in a reduction in equity of €43 million within the opening balance sheet (December 31, 2006: –€129 million).

f) Derivatives Further differences exist with regard to the definition of a derivative. Under U.S. GAAP, there are industry- specific exceptions for power-plant-specific supply contracts that are unknown under IFRS. This means that the definition of a derivative encompasses more contracts under IFRS.

In the case of embedded derivatives in certain supply and sale contracts, IFRS provides for the possibility of measuring only the embedded derivative, while reporting the non-derivative portion as a pending transaction. This is an exception for own-use contracts. Under U.S. GAAP, the existence of an embedded derivative in these

F-96 contracts gives rise to fair value reporting through income for the contract as a whole. Further effects arise from differences in the definition of a derivative with regard to future settlement and market liquidity.

In total, these effects resulted in a reduction in equity of €566 million within the opening balance sheet (December 31, 2006: increase of €226 million).

g) Valuation of Available-for-Sale Financial Instruments Under U.S. GAAP, non-marketable equity instruments are accounted for at cost. Under IFRS, all equity instruments must be reported at fair value to the extent that the fair value can be reliably determined. This applies even if an exchange quotation or another publicly available market price does not exist. Unrealized gains and losses from available-for-sale financial instruments, with the exception of impairment charges are reported in equity and reclassified when realized. The fair value measurement of available-for-sale equity instruments resulted in an increase in equity of €377 million within the opening balance sheet (December 31, 2006: €370 million).

h) U.S. Regulation Accounting for E.ON’s regulated utility businesses, Louisville Gas and Electric Company, Louisville, Kentucky, U.S., and Kentucky Utilities Company, Lexington, Kentucky, U.S., of the U.S. Midwest market unit, conforms to U.S. generally accepted principles as applied to regulated public utilities in the United States of America. These entities are subject to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”), under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery of such costs from customers in future rates approved by the relevant regulator. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory provisions. The current or expected recovery by the entities of deferred costs and the expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The regulatory assets and liabilities under U.S. GAAP do not fulfill the recognition criteria for assets and liabilities under IFRS. As a result, these regulatory assets and liabilities were offset against equity and resulted in an increase in equity of €403 million within the opening balance sheet (December 31, 2006: €279 million).

i) Income Taxes The adjustments described above result in changes in temporary differences between IFRS carrying amounts and tax-basis values and, accordingly, to changes in deferred taxes, that are different from those under U.S. GAAP.

Furthermore, under IAS 12, deferred taxes arising from investments in subsidiaries and associates (outside basis differences) are not recognized to the extent that the investor is able to control the timing of the reversal of the temporary difference and to the extent that it is probable that the temporary differences will not reverse in the foreseeable future.

In total, these effects resulted in an increase in equity within the opening balance sheet of €800 million (December 31, 2006: €223 million).

j) Other Leasing In a manner analogous to EITF 01-8, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-8”), IFRIC 4 provides for the reporting of embedded leases. IFRIC 4 requires retrospective application whereas the equivalent provisions of EITF 01-8 under U.S. GAAP had to be applied prospectively as of May 28, 2003. The positive effect of this application on equity amounted to €90 million within the opening balance sheet (December 31, 2006: €125 million).

F-97 Change in Scope of Consolidation One gas storage company in the Pan-European Gas market unit must be additionally consolidated under IFRS. The obligation to consolidate arises from SIC Interpretation 12, “Consolidation—Special Purpose Entities” (“SIC 12”), since E.ON has a right to obtain the majority of this company’s benefits and is thereby exposed to the majority of its business risks. The U.S. GAAP criterion of asymmetric distribution of opportunities and risks under Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 46 (revised December 2003), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN 46R”), is not met. Moreover, there are significant protective rights for minority shareholders, meaning that control in the context of U.S. GAAP is not present. The consolidation of the gas storage company resulted in an increase in equity of €81 million in the opening balance sheet (December 31, 2006: €70 million).

Impairment Under U.S. GAAP, the first step in the impairment testing of property, plant and equipment and intangible assets is to determine whether the carrying amount of the asset or group of assets being tested may not be recoverable. The carrying amount is not recoverable if it exceeds the estimated future undiscounted cash flows arising from the use of the asset or group of assets tested. In such a case, the second step is to recognize an impairment charge in the amount of the difference between the previous carrying amount and the lower fair value. Under IFRS no two-step approach exists. The carrying amount of the asset being tested is compared with its recoverable amount, which is the higher of an asset’s value in use and its fair value less costs to sell. If the carrying amount exceeds the corresponding recoverable amount, an impairment charge is recognized in the amount of the difference. In the fourth quarter of 2006, impairment charges in the amount of €186 million were recognized in accordance with IFRS on property, plant and equipment and intangible assets at the U.K. market unit. No impairment was necessary under U.S. GAAP because the undiscounted cash flows exceeded the carrying amounts of the assets. As of December 31, 2006, this resulted in a decrease in equity under IFRS of €186 million.

Degussa Furthermore, the conversion to IFRS of E.ON’s interest in Degussa within the opening balance sheet, as well as the subsequent related impacts during 2006 from the application of the equity method and the accounting for the disposal of Degussa under IFRS, resulted in a reduction in equity of –€31 million (December 31, 2006: –€142 million).

Reconciliation of Net Income Reconciliation of Net Income

€ in millions Reference 2006 Net income under U.S. GAAP ...... 5,057 Changes in the presentation of minority interests ...... a 526 Net income under U.S. GAAP, including minority interests ...... 5,583 Effects of IAS 32 ...... b (121) Inventories ...... c 214 Pensions and similar obligations ...... d 118 Miscellaneous provisions ...... e (78) Derivatives ...... f 791 Valuation of available-for-sale financial instruments ...... g (55) U.S. regulation ...... h 9 Income taxes ...... i (363) Other ...... j (16) Total adjustments ...... 499 Net income under IFRS ...... 6,082

F-98 a) Changes in the Presentation of Minority Interests Consistent with the change in presentation within the balance sheet, minority interests are reported directly in equity under IFRS as part of the allocation of earnings. Under U.S. GAAP, minority interests in earnings are reported within the calculation of net income.

b) Effects of IAS 32 Put Options on Minority Interests Financial instruments for which a right of repayment exists do not constitute equity instruments under the IFRS definition of equity. E.ON has made conditional and unconditional repurchase offers to certain minority shareholders to acquire the outstanding shares. Correspondingly, a liability in the amount of the present value of the future exercise price must be reported, irrespective of the probability of exercise. The accretion expense for the liability is shown in interest income. The minority interest remains part of the earnings allocation reported directly within equity under IFRS.

Under U.S. GAAP, these potential commitments are generally reported at fair value similar to derivatives. Minority interests are included in the calculation of net income.

Minority Interests in German Partnerships Under German corporate law, shareholders of a German partnership have a statutory, non-excludable right of termination. Under IAS 32, this right of termination causes the minority interests in the Group to be considered repayable. Accordingly, a corresponding liability in the present value of the expected settlement amount must be reclassified from minority interests. The shares in earnings to which the minority shareholders are entitled as well as the accretion expense for the liability must be shown as interest expense. Other changes in the value of the liability are reported as other operating income and expenses.

Under U.S. GAAP, these partnership interests are shown under minority interests. The share in earnings to which these minority shareholders are entitled is still shown as minority interests in earnings and included in the calculation of net income.

These effects resulted in a decrease of net income by €121 million for the year ended December 31, 2006.

c) Inventories The adjustment from LIFO measurement of gas inventories as was generally applied under U.S. GAAP to average-cost measurement under IFRS resulted in an increase in net income of €214 million for the year ended December 31, 2006.

d) Pensions and Similar Obligations E.ON has elected the option under IAS 19 to recognize all actuarial gains and losses within equity with no further amortization through net income as required under U.S. GAAP.

As a result, net income increased by €118 million for the year ended December 31, 2006.

e) Miscellaneous Provisions The differences in the accounting treatment miscellaneous of provisions described in connection with the reconciliation of equity resulted in a reduction in net income of €78 million for the 2006 fiscal year. The increased charge as of the end of the fiscal year is primarily due to early retirement agreements at the Central Europe market unit.

F-99 f) Derivatives Under U.S. GAAP, there are industry-specific exceptions for power-plant-related supply contracts that are unknown under IFRS. This means that the definition of a derivative encompasses more contracts under IFRS.

In the case of embedded derivatives in certain supply and sale contracts, IFRS provides for the possibility of measuring only the embedded derivative, while reporting the non-derivative portion as a pending transaction. Under U.S. GAAP, the existence of an embedded derivative in these contracts gives rise to fair value reporting through income for the contract as a whole. Further effects arise from the definition of a derivative with regard to net settlement and market liquidity.

The total increase in net income for the year ended December 31, 2006, attributable to these circumstances was €791 million.

g) Valuation of Available-for-Sale Financial Instruments Under IFRS, the foreign currency translation effects from monetary financial instruments classified as available-for-sale are recognized in income to the extent to which they are related to acquisition costs. Under U.S. GAAP, these effects are classified as other comprehensive income, along with all other changes in fair value. For the year ended December 31, 2006, this resulted in a decrease in net income of €55 million.

h) U.S. Regulation The regulatory assets and liabilities under U.S. GAAP do not fulfill the recognition criteria for assets and liabilities under IFRS. Immediate recognition in the income statement of the resulting income and expenses resulted in an increase in net income of €9 million for the year ended December 31, 2006.

i) Income Taxes During the 2006 fiscal year, the above deviations in income, particularly with respect to pensions, resulted in changes of deferred taxes that reduced net income.

Furthermore, under IAS 12, deferred taxes arising from investments in subsidiaries and associates (outside basis differences) are not recognized to the extent that the investor is able to control the timing of the reversal of the temporary difference and to the extent that it is probable that the temporary differences will not reverse in the foreseeable future. In comparison with U.S. GAAP, this resulted in an increase in net income under IFRS.

Overall the changes in income taxes resulted in a reduction of net income during the year ended December 31, 2006, of €363 million.

j) Other A further difference results from the conversion to IFRS of E.ON’s interest in Degussa both with respect to the equity results as well as the book gain calculated upon disposal in 2006. The conversion led to an increase in net income of €205 million for the year ended December 31, 2006. This was offset by an impairment charge of €186 million at the U.K. market unit recognized only under IFRS in the fourth quarter 2006.

Cash Flow Adjustments As a result of the conversion to IFRS, E.ON’s 2006 cash flows from operating, investing and financing activities were adjusted from their U.S. GAAP amounts by –€33 million, +€44 million and –€11 million, respectively. These minor adjustments result from differences in the scope of consolidation and the accounting treatment of lease arrangements in accordance with IFRIC 4.

F-100 To the best of our knowledge, and in accordance with applicable financial reporting principles, the Consolidated Financial Statements give a true and fair view of the assets, liabilities, financial position and profit or loss of the Group, and the Group Management Report, which has been combined with the management report for E.ON AG, provides a fair review of the development and performance of the business and the position of the E.ON Group, together with a description of the principal opportunities and risks associated with the expected development of the Group.

Düsseldorf, February 19, 2008

The Board of Management

Bernotat Bergmann Dänzer-Vanotti

Feldmann Schenck Teyssen

F-101 REGISTERED OFFICE OF THE ISSUER

E.ON International Finance B.V. Capelseweg 400 3068 AX Rotterdam The Netherlands

REGISTERED OFFICE OF THE GUARANTOR

E.ON AG E.ON-Platz 1 D-40479 Düsseldorf Germany

LEGAL ADVISERS TO THE ISSUER AND THE GUARANTOR

As to U.S. and German law As to Dutch law

Shearman & Sterling LLP Clifford Chance LLP Broadgate West Breite Straße 69 Droogbak 1A 9 Appold Street D-40213 1013 GE, Amsterdam London EC2A 2AP Düsseldorf The Netherlands United Kingdom Germany

LEGAL ADVISERS TO THE INITIAL PURCHASERS

As to U.S. and German law

Cleary Gottlieb Steen & Hamilton LLP Via San Paolo 7 Neue Mainzer Strasse 52 20121 Milan 60311 Frankfurt am Main Italy Germany

INDEPENDENT AUDITORS OF THE GUARANTOR

PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprüfungsgesellschaft Moskauer Straße 19 40227 Düsseldorf Germany

FISCAL AGENT, PAYING AGENT, TRANSFER AGENT AND REGISTRAR

HSBC Bank USA, N.A. 10 East 40th Street New York, NY 10016 United States [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK]

E.ON International Finance B.V.

Amsterdam, The Netherlands

U.S.$3,000,000,000

consisting of

U.S.$2,000,000,000 5.80% Notes Due 2018 U.S.$1,000,000,000 6.65% Notes Due 2038

With an unconditional and irrevocable guarantee as to payment of principal and interest from

E.ON AG

Offering Memorandum

April 15, 2008

Joint Book-Running Managers

Banc of America Securities LLC Deutsche Bank Securities Goldman, Sachs & Co. JPMorgan

Co-Managers

Lehman Brothers Merrill Lynch & Co. RBS Greenwich Capital