Edgar Filing: E ON AG

e20vf

As filed with the Securities and Exchange Commission on March 9, 2006.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 20-F

(Mark One)


o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
		OR
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2005
		OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		OR
o		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report .

For the transition period from to

Commission file number: 1-14688

E.ON AG

(Exact name of Registrant as specified in its charter)

E.ON AG

(Translation of Registrant’s name into English)


Federal Republic of Germany		E.ON-Platz 1, D-40479 Düsseldorf, GERMANY
(Jurisdiction of Incorporation or Organization)		(Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

American Depositary Shares representing
Ordinary Shares with no par value		New York Stock Exchange
Ordinary Shares with no par value		New York Stock Exchange*

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

(Title of Class)

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

As of December 31, 2005, 659,153,552 outstanding Ordinary Shares with no par value.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes o No þ

Note — checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

Indicate by check mark which financial statement item the registrant has elected to follow. Item 17 o Item 18 þ

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ


*	Not for trading, but only in connection with the registration of American Depositary Shares.

As used in this annual report,


	•	“E.ON,” the “Company,” the “E.ON Group” or the “Group” refers to E.ON AG and its consolidated subsidiaries.

	•	“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, 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 (“E.ON Finland”) 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 LLC (“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, in which E.ON now owns a minority interest, and which collectively comprised E.ON’s former Degussa division.

	•	“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.

	•	“MEMC” refers to MEMC Electronic Materials, Inc. and its consolidated subsidiaries, which collectively comprised E.ON’s former silicon wafers division.

Unless otherwise indicated, all amounts in this annual report are expressed in European Union euros (“euros” or “EUR” or “€”), United States dollars (“U.S. dollars” or “dollars” or “$”), British pounds (“GBP”), Swedish krona (“SEK”) or Swedish öre (“öre”). Beginning in 1999, the reporting currency is the euro. Amounts formerly stated in German marks (“marks” or “DM”) have been translated into euro using the fixed rate of DM 1.95583 per €1.00. Amounts stated in dollars, unless otherwise indicated, have been translated from euros at an assumed rate solely for convenience and should not be construed as representations that the euro amounts actually represent such dollar amounts or could be converted into dollars at the rate indicated. Unless otherwise stated, such dollar amounts have been translated from euros at the noon buying rate in New York City for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York (the “Noon Buying Rate”) on December 30, 2005, which was $1.1842 per €1.00. Such rate may differ from the actual rates used in the preparation of the consolidated financial statements of E.ON as of December 31, 2005, 2004 and 2003, and for each of the years in the three-year period ended December 31, 2005, included in Item 18 of this annual report (the “Consolidated Financial Statements”), which are expressed in euros, and, accordingly, dollar amounts appearing in this annual report may differ from the actual dollar amounts that were

translated into euros in the preparation of such financial statements. For information regarding recent rates of exchange, see “Item 3. Key Information — Exchange Rates.”

Beginning in 2000, E.ON has prepared its financial statements in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). Formerly, the Company prepared its financial statements in accordance with generally accepted accounting principles in Germany as prescribed by the German Commercial Code (Handelsgesetzbuch, the “Commercial Code”) and the German Stock Corporation Act (Aktiengesetz, the “Stock Corporation Act”). Sales and adjusted EBIT presented in this annual report for each of E.ON’s segments are based on the consolidated accounts of the E.ON Group as shown in Note 31 (Segment Information) of the Notes to Consolidated Financial Statements under the captions “External sales” and “Adjusted EBIT” and are presented prior to the elimination of intersegment transactions. “Adjusted EBIT” is the measure pursuant to which the Group has evaluated the performance of its segments and allocated resources to them since 2004. 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 minority interests, excluding 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, 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. E.ON uses adjusted EBIT as its segment reporting measure in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS 131”). However, on a consolidated Group basis adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable GAAP measure. For a reconciliation of Group adjusted EBIT to net income for each of 2005, 2004 and 2003, see “Item 5. Operating and Financial Review and Prospects — Results of Operations — Business Segment Information.”

E.ON has calculated operating data for Group companies appearing in this annual report 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.

This annual report contains certain forward-looking statements and information relating to the E.ON Group 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 document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “project” and similar expressions, as they relate to the E.ON Group 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 the E.ON Group 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, changes in general economic and business conditions, changes in currency exchange rates and interest rates, introduction of competing products by other companies, lack of acceptance of new products or services by the Group’s targeted customers, changes in business strategy, lack of successful completion of planned acquisitions and dispositions and/or the realization of expected benefits and various other factors, both referenced and not referenced in this annual report. 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 annual report as anticipated, believed, estimated, expected, intended, planned or projected. E.ON does not intend, and does not assume any obligation, to update these forward-looking statements.

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TABLE OF CONTENTS


PART I
Item 1.	Identity of Directors, Senior Management and Advisers	1
Item 2.	Offer Statistics and Expected Timetable	1
Item 3.	Key Information	1
	SELECTED FINANCIAL DATA	1
	DIVIDENDS	2
	EXCHANGE RATES	3
	RISK FACTORS	4
Item 4.	Information on the Company	13
	HISTORY AND DEVELOPMENT OF THE COMPANY	13
	VEBA-VIAG MERGER	13
	POWERGEN GROUP ACQUISITION	13
	RUHRGAS ACQUISITION	14
	PROPOSED ENDESA ACQUISITION	16
	GROUP STRATEGY	17
	ON.TOP PROJECT	19
	OTHER SIGNIFICANT EVENTS	21
	CAPITAL EXPENDITURES	22
	BUSINESS OVERVIEW	22
	INTRODUCTION	22
	CENTRAL EUROPE	25
	PAN-EUROPEAN GAS	43
	U.K.	60
	NORDIC	70
	U.S. MIDWEST	83
	OTHER ACTIVITIES	89
	DISCONTINUED OPERATIONS	90
	REGULATORY ENVIRONMENT	92
	ENVIRONMENTAL MATTERS	108
	OPERATING ENVIRONMENT	114
	ECONOMIC BACKGROUND	114
	RISK MANAGEMENT	115
	ORGANIZATIONAL STRUCTURE	116
	PROPERTY, PLANTS AND EQUIPMENT	116
	GENERAL	116
	PRODUCTION FACILITIES	116
	INTERNAL CONTROLS	118
Item 4A.	Unresolved Staff Comments	118
Item 5.	Operating and Financial Review and Prospects	118
	OVERVIEW	118
	ACQUISITIONS AND DISPOSITIONS	120
	CRITICAL ACCOUNTING POLICIES	127
	NEW ACCOUNTING PRONOUNCEMENTS	130
	RESULTS OF OPERATIONS	130
	BUSINESS SEGMENT INFORMATION	131
	YEAR ENDED DECEMBER 31, 2005 COMPARED WITH YEAR ENDED DECEMBER 31, 2004	132
	YEAR ENDED DECEMBER 31, 2004 COMPARED WITH YEAR ENDED DECEMBER 31, 2003	144
	INFLATION	156
	EXCHANGE RATE EXPOSURE AND CURRENCY RISK MANAGEMENT	156
	LIQUIDITY AND CAPITAL RESOURCES	157


	RESEARCH AND DEVELOPMENT	163
	TREND INFORMATION	163
	PROCESS OF TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS	163
	OFF-BALANCE SHEET ARRANGEMENTS	164
	CONTRACTUAL OBLIGATIONS	166
Item 6.	Directors, Senior Management and Employees	167
Item 7.	Major Shareholders and Related Party Transactions	179
Item 8.	Financial Information	180
	CONSOLIDATED FINANCIAL STATEMENTS	180
	LEGAL PROCEEDINGS	180
	DIVIDEND POLICY	181
	SIGNIFICANT CHANGES	182
Item 9.	The Offer and Listing	182
Item 10.	Additional Information	184
	MEMORANDUM AND ARTICLES OF ASSOCIATION	184
	MATERIAL CONTRACTS	195
	EXCHANGE CONTROLS	195
	TAXATION	196
	DOCUMENTS ON DISPLAY	199
Item 11.	Quantitative and Qualitative Disclosures about Market Risk	199
Item 12.	Description of Securities Other than Equity Securities	205

PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	205
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	205
Item 15.	Controls and Procedures	205
Item 16A.	Audit Committee Financial Expert	205
Item 16B.	Code of Ethics	205
Item 16C.	Principal Accountant Fees and Services	206
Item 16D.	Exemptions from the Listing Standards for Audit Committees	207
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	208

PART III
Item 17.	Financial Statements	209
Item 18.	Financial Statements	209
Item 19.	Exhibits	209
English Translation of the Articles of Association
Sale & Purchase Agreement
Section 302 Certification of Chief Executive Officer
Section 302 Certification of Chief Financial Officer
Section 906 Certification of CEO and CFO

PART I


Item 1.	Identity of Directors, Senior Management and Advisers.

Not applicable.


Item 2.	Offer Statistics and Expected Timetable.

Not applicable.


Item 3.	Key Information.

SELECTED FINANCIAL DATA

The selected financial data presented below in accordance with U.S. GAAP as of and for each of the years in the five-year period ended December 31, 2005 have been excerpted from or are derived from the Consolidated Financial Statements of E.ON as of and for the period ended December 31, 2005, 2004, 2003, 2002 and 2001, respectively.

The selected financial data set forth below should be read in conjunction with, and are qualified in their entirety by reference to, the Consolidated Financial Statements and the Notes to Consolidated Financial Statements.


	Year Ended December 31,

	2005(1)		2005		2004		2003		2002			2001

	(in millions, except share amounts)
Statement of Income Data:
Sales	$	66,788		€56,399		€46,742		€44,109		€35,300			€36,041
Sales excluding electricity and natural gas taxes(2)		61,406		51,854		42,384		40,223		34,367			35,347
Income/(Loss) from continuing operations before income taxes		8,536		7,208		6,355		5,165		(947	)		2,502
Income/(Loss) from continuing operations after income taxes(3)		5,841		4,932		4,505		4,020		(276	)		2,403
Income/(Loss) from continuing operations		5,186		4,379		4,027		3,575		(901	)		1,950
Income/(Loss) from discontinued operations(4)		3,594		3,035		312		1,512		3,487			124
Net income		8,771		7,407		4,339		4,647		2,777			2,048
Basic earnings/(Loss) per share from continuing operations		7.87		6.64		6.13		5.47		(1.38	)		2.89
Basic earnings (Loss) per share from discontinued operations, net(4)		5.45		4.61		0.48		2.31		5.35			0.18
Basic earnings per share from net income(5)		13.31		11.24		6.61		7.11		4.26			3.03
Balance Sheet Data:
Total assets	$	149,875		€126,562		€114,062		€111,850		€113,503			€101,659
Long-term financial liabilities		12,499		10,555		13,540		14,884		17,576			9,308
Stockholders’ equity(6)		52,678		44,484		33,560		29,774		25,653			24,462
Number of authorized shares				692,000,000		692,000,000		692,000,000		692,000,000			692,000,000


(1)	Amounts in this column are unaudited and have been translated solely for the convenience of the reader at an exchange rate of $1.1842 = €1.00, the Noon Buying Rate on December 30, 2005.


(2)	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.

(3)	Before minority interest of €553 million for 2005, as compared with €478 million, €445 million, €625 million and €453 million for 2004, 2003, 2002 and 2001, respectively.

(4)	For more details, see “Item 5. Operating and Financial Review and Prospects — Acquisitions and Dispositions — Discontinued Operations” and Note 4 of the Notes to Consolidated Financial Statements.

(5)	Includes earnings per share from the first-time application of new U.S. GAAP standards of €(0.01), €0.00, €(0.67), €0.29 and €(0.04) for 2005, 2004, 2003, 2002 and 2001, respectively.

(6)	After minority interests.

DIVIDENDS

The following table sets forth the annual dividends paid per ordinary unit bearer share of E.ON AG (each, an “Ordinary Share”) in euros, and the dollar equivalent, for each of the years indicated. Prior to the introduction of the euro in 2002, dividends were declared and paid in marks. For convenience, the dividend amount for 2001 has been translated from marks into euros at the fixed rate of 1.95583. The table does not reflect the related tax credits available to German taxpayers who receive dividend payments. Owners of Ordinary Shares who are United States residents should be aware that they will be subject to German withholding tax on dividends received. See “Item 10. Additional Information — Taxation.”


	Dividends Paid
	per Ordinary
	Share with no
	par value

Year Ended December 31,	€		$(1)

2001		1.60		1.49
2002		1.75		1.96
2003		2.00		2.39
2004		2.35		3.04
2005(2)(3)		2.75		3.26


(1)	Translated into dollars at the Noon Buying Rate on the dividend payment date, which typically occurred during the second quarter of the following year, except for the 2005 amount, which has been translated at the Noon Buying Rate on December 30, 2005.

(2)	The dividend amount for the year ended December 31, 2005 is the amount proposed by E.ON’s Supervisory Board and Board of Management and has not yet been approved by its stockholders. Prior to the payment of the dividends, a resolution approving such amount must be passed by E.ON’s stockholders at the annual general meeting to be held on May 4, 2006.

(3)	E.ON’s Supervisory Board and Board of Management have also proposed an extra dividend for 2005 of €4.25 per Ordinary Share, resulting from the proceeds from the sale of E.ON’s remaining 42.9 percent stake in Degussa. For details on this transaction, see “Item 5. Operating and Financial Review and Prospects — Overview.” The extra dividend has not yet been approved by E.ON’s stockholders. Prior to the payment of this dividend, which will be made together with the regular dividend amount for the year ended December 31, 2005, a resolution approving such amount must be passed by E.ON’s stockholders at the annual general meeting to be held on May 4, 2006.

See also “Item 8. Financial Information — Dividend Policy.”

EXCHANGE RATES

Until December 31, 1998, the mark took part in the European Monetary System (“EMS”) exchange rate mechanism. Within the EMS, exchange rates could fluctuate within permitted margins, fixed by central bank intervention. Against currencies outside the EMS, the mark had, in theory, free floating exchange rates, although central banks sometimes tried to confine short-term exchange rate fluctuations by intervening in foreign exchange markets. As of December 31, 1998, the mark had a fixed value relative to the euro of 1.95583, and therefore was no longer traded on currency markets as an independent currency. As of January 1, 2002, the euro replaced the mark as legal tender in Germany.

Fluctuations in the exchange rate between the euro and the dollar will affect the dollar equivalent of the euro price of the Ordinary Shares traded on the German stock exchanges and, as a result, will affect the price of the Company’s American Depositary Receipts (“ADRs”) traded in the United States. Such fluctuations will also affect the dollar amounts received by holders of ADRs on the conversion into dollars of cash dividends paid in euros on the Ordinary Shares represented by the ADRs.

The following table sets forth, for the periods and dates indicated, the average, high, low and/or period-end Noon Buying Rates for euros expressed in $ per €1.00.


Period		Average(1)		High		Low		Period-End

2001			0.8909						0.8901
2002			0.9495						1.0485
2003			1.1411						1.2597
2004			1.2478						1.3538
2005			1.2400						1.1842
	September				1.2538		1.2011
	October				1.2148		1.1914
	November				1.2067		1.1667
	December				1.2041		1.1699
2006
	January				1.2287		1.1980
	February				1.2100		1.1860


(1)	The average of the Noon Buying Rates for the relevant period, calculated using the average of the Noon Buying Rates on the last business day of each month during the period.

On March 6, 2006, the Noon Buying Rate was $1.2002 per €1.00.

RISK FACTORS

On May 1, 1998, the German Control and Transparency in Business Act (Gesetz zur Kontrolle und Transparenz im Unternehmensbereich, or KonTraG), came into effect. The provisions of KonTraG include the requirement that the board of management of a German stock corporation establish a risk management system to identify material risks to the corporation at an early stage. As part of their audit, the auditors of a stock corporation assess whether the system meets the requirements of KonTraG. The audit requirement has been applicable to all fiscal years beginning after December 31, 1998, although the former VEBA underwent this audit voluntarily already in fiscal year 1998.

Even prior to the requirements introduced by KonTraG, the Company believes it had an effective risk management system which integrates risk management in its Group-wide business procedures. The system includes controlling processes, Group-wide guidelines, data processing systems and regular reports to the Board of Management and Supervisory Board. The reliability of the risk management system is reviewed regularly by the internal audit units of the Company as well as by the Company’s external independent auditors, based on requirements set forth in the Stock Corporation Act. The documentation and evaluation of the Company’s risks are updated quarterly throughout the Group in the following steps:


	•	Standardized documentation of risks and countermeasures;

	•	Evaluation of risks according to the degree of severity and the probability of occurrence, and an annual assessment of the effectiveness of existing countermeasures; and

	•	Analysis of the results and structured disclosure in a risk report.

The following discussion groups risks according to the categories of external, operational and financial risks, as used by the Company in its risk management system.

External

The Company faces the general risks of economic downturns experienced by all businesses. The following are specific external risks the Company faces:


	*The Company’s 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 602 terawatt hours (“TWh”) at the European Energy Exchange (EEX) spot and futures market in 2005. 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 the first such facilities come into operation. Although the Company intends to compete vigorously in the changed German electricity market, it cannot be certain that it will be able to develop its business as successfully as its competitors. For information about new regulatory changes that will affect the German electricity market, see the discussion on changes in laws and regulations below.

Outside Germany, the electricity markets in which the Company operates are also subject to strong competition. The Company has 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 the Company’s U.K. or Swedish market share in both the retail and wholesale sectors. In the United States, E.ON U.S., the Company’s primary U.S. subsidiary, is exposed to

wholesale price and fuel cost risks with respect to its non-regulated operations, whose rates are not set by governmental regulators, and which represent a minority of E.ON U.S.’s business. The Company cannot guarantee it will be able to compete successfully in the United Kingdom, the Nordic countries, the United States, Eastern Europe, Italy or other electricity markets where it is already present or in new electricity markets the Company may enter. E.ON Ruhrgas also faces risks associated with increased competition in the gas sector; see “Item 4. Information on the Company — Business Overview — Pan-European Gas — Competitive Environment” and “— Regulatory Environment — Germany: Gas.”

Changes in applicable laws and regulations could materially and adversely affect the Company’s financial condition and results of operations.

In each of its operations, the Company must comply with a number of laws and government regulations. For more information on laws and regulations affecting the Company’s core energy business, including additional details on each of the regulatory regimes discussed below, see “Item 4. Information on the Company — Regulatory Environment.” From time to time, changes or new laws and regulations may be introduced which may negatively affect the Company’s 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 is 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 access 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 network access in the electricity and gas industries in Germany. Although the new legislation has already come into force, the Company 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. The Company cannot be certain that the appointment of a regulator and changes to the current system of network access, as well as other changes introduced as part of the new regime, will not have a negative effect on its electricity and gas businesses in Germany, including the network charges E.ON Energie and E.ON Ruhrgas may charge for network access. In Sweden, new legislation was also adopted in order to comply with the requirements of the EU’s electricity and gas directives, and the Company cannot be certain that the new requirements will not have a negative effect on its Swedish operations.

The EU has also adopted a directive requiring member states to establish a greenhouse gas emissions allowance trading scheme, under which permits to emit a specified amount of carbon dioxide (“CO₂ emission certificates”) are to be allocated to affected power stations and other industrial installations. Most member states, including Germany, the Netherlands and Sweden, have already passed the required legislation and allocated the necessary CO₂ emission certificates free of charge, and the United Kingdom has also made an initial allocation of certificates (with a possibility that the U.K. government may appeal its CO₂ emissions allocation to try to claim additional allowances). Although the Company does not generally expect the introduction of the emissions trading scheme to have a negative impact on its operations, the fact that the directive has only recently been implemented in some EU member states and not yet implemented in others makes it impossible for the Company to predict how the trading of CO₂ emission certificates will develop or what long-term impact, if any, the new regime will have on its financial condition and results of operations. However, in 2005, companies of both the U.K. and Central Europe market units had to purchase additional CO₂ emission certificates on the market, with a resultant increase in operating costs. For more information, see “Item 4. Information on the Company — Regulatory Environment” and “Item 5. Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2005 Compared with Year Ended December 31, 2004.”

In Germany, the Company’s nuclear power plants are among its cheapest source of power, and, along with hydroelectric and lignite-based power plants, are used primarily to cover the Company’s base load power requirements. In June 2001, E.ON, together with the other German operators of nuclear power stations, reached

an agreement with the German federal government to phase out the generation of nuclear power in Germany; this agreement was reflected in an amendment of Germany’s nuclear energy law in April 2002. For more information about the planned phase-out of nuclear power stations in Germany, see “Item 4. Information on the Company — Business Overview — Central Europe.” The amended law provides that the delivery of spent nuclear fuel rods for reprocessing was allowed until June 30, 2005. Following this deadline, nuclear plant operators are required to store spent fuel elements on the premises of their nuclear plants. The Company is currently constructing five interim on-site storage facilities, of which two are expected to go into operation in the first quarter of 2006, with the remaining three scheduled to be ready between November 2006 and February 2007. In the interim, the relevant facilities are storing spent fuel elements in existing storage pools. The construction costs of these storage facilities are expected to be significant, and the Company may incur higher than anticipated costs in phasing out its nuclear energy operations.

In addition, in the summer of 2005 the Competition Directorate-General of the EU Commission launched a sector inquiry concerning the electricity and gas markets in the EU. It is possible that antitrust inspections of individual companies may be conducted in the context of this inquiry, and any such inspections could potentially result in the affected companies being required to make material changes to their operations. It also cannot be excluded that this inquiry could encourage or result in legislative initiatives (at the EU or national level) that would seek to increase the current level of competition in the EU energy market.

Regulatory actions can also affect the prices the Company may charge customers. For example,


	•	As described above, EU directives provide that the regulatory authority which was appointed in Germany should have the power to set or approve network access charges or, alternatively, the methodologies used for calculating them. This could lead to lower network fees for E.ON’s electricity and gas transportation and distribution businesses in Germany.

	•	In Germany, the state antitrust authorities in Bavaria, Thuringia, Schleswig-Holstein, Baden-Wuerttemberg and Lower Saxony, as well as the Federal Cartel Office, have launched investigations of certain utilities with allegedly high gas tariffs to determine whether these gas prices constitute market abuse. These investigations affect some utilities in which Thüga and E.ON Energie hold interests. As a result of ongoing discussions with the Federal Cartel Office, E.ON’s regional sales companies have agreed to enable their residential customers to switch gas suppliers as from April 1, 2006. Although a similar investigation by the Federal Cartel Office against subsidiaries of E.ON Energie has been closed without any charges being brought, that office has since opened an investigation of E.ON Energie and its competitor RWE with regard to possible abuses in the markets for electricity and/or CO₂ emission certificates. The Company cannot currently predict the outcome of any of the pending investigations.

	•	Electricity and gas prices and sales practices have also been the subject of periodic challenges by the German antitrust authorities, although to date E.ON has prevailed in such cases, sometimes on appeal after a negative ruling by a court of first instance. Currently, 54 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 and is expected to make an initial pronouncement in the spring of 2006. 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.

	•	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 that 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, although such increases remain the subject of continuing regulatory review and governmental inquiry.

For additional information on these developments, see “Item 4. Information on the Company — Regulatory Environment.” For all of its operations, adverse changes in price controls, rate structures or the level of competition could have an adverse effect on the Company’s financial condition and results of operations.

Rising fuel prices could materially and adversely affect the Company’s results of operations and financial condition.

A significant portion of the expenses of the Company’s 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 significantly in 2005 as a result of geopolitical factors, including, but not limited to, an increase in demand in China and India, the war and post-war insurgency in Iraq, increased instability in other parts of the Middle East and a further deterioration of the economic and political situation in Venezuela and Nigeria. The Company’s electricity operations do maintain some flexibility to shift power production among different types of fuel, and the Company is also partially hedged against rising fuel prices. However, increases in fuel costs could have an adverse effect on the Company’s operating results or financial condition if it is not able (or not permitted by regulatory authorities) to shift production to lower-cost fuel or to adjust its 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 the discussion on E.ON Ruhrgas’ long-term gas supply contracts below. The Company could also incur losses if its hedging strategies are not effective. For more information about the Company’s hedging policies and the instruments used, see “— Financial” below, “Item 5. Operating and Financial Review and Prospects — Exchange Rate Exposure and Currency Risk Management” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk.”

Recent events have heightened concerns about the reliability of Russian gas supplies, on which E.ON Ruhrgas depends.

E.ON Ruhrgas currently obtains nearly 30 percent of its total gas supply from Russia pursuant to long-term supply contracts it has entered into with OOO Gazexport, 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. 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. Although a political settlement was reached, the Ukrainian parliament has since rejected that settlement. In addition, historically cold temperatures in Russia have increased gas consumption, leading some Western European countries to report declines in pressure in gas pipelines and shortfalls in the volume of gas they receive from Russia, with some of those countries having announced plans to impose suggested or mandatory reductions on consumption. 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 OOO Gazexport deliver the contracted volumes of gas 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 OOO Gazexport 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.

The Company’s revenues and results of operations fluctuate by season and according to the weather, and management expects these fluctuations to continue.

The demand for electric power and natural gas is seasonal, with the Company’s 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 the Company’s 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, the Company’s 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 a secondary peak in the first and fourth quarters. Revenues and results of operations for all of the Company’s energy operations would be negatively affected by periods of unseasonably warm weather during the autumn and winter months. The Company’s Nordic operations could be negatively affected by a lack of precipitation (which would lead to a decline in hydroelectric generation) and its European energy operations could also be negatively affected by a summer with higher than average temperatures to the extent its plants were required to reduce or shut down operations due to a lack of water needed for cooling the plants. Management expects 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

The Company’s core energy businesses operate technologically complex production facilities and transmission systems. Operational failures or extended production downtimes could negatively impact the Company’s financial condition and results of operations. The Company’s businesses are also subject to risks in the ordinary course of business such as the loss of personnel or customers, and losses due to bad debts. The Company believes it has appropriate risk control measures in effect to counteract and address these types of risks. The following are additional operational risks the Company faces:

E.ON Ruhrgas’ long-term gas contracts expose it to volume and price risks, and the validity of its longer-term supply contracts has been challenged by the German antitrust authorities.

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 the gas supply contracts (for distributors and municipal utilities, which constitute the majority of E.ON Ruhrgas’ customers, the contracts generally have longer terms, while contracts for industrial customers usually have terms between one and five years), and, as described in more detail below, have been alleged to be unenforceable by the German Federal Cartel Office. 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 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 gas from other sources. The ministerial approval E.ON 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 to 80 percent of the contractually agreed amount over the period of the applicable gas sales contract, and E.ON Ruhrgas has recently voluntarily offered a similar volume reduction option to other customers, as described in more detail below. To date, most customers have decided not to exercise these options. For additional information on these developments, see “Item 4. Information on the Company — Business Overview — Pan-European Gas — Sales.” 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 in margins.

On January 13, 2006, the German Federal Cartel Office issued an order prohibiting E.ON Ruhrgas from enforcing its existing gas supply contracts with regional and local gas distributors and from entering into any new contracts that are identical or similar in nature. Such contracts have been customary in the German gas market since the industry’s inception, and E.ON Ruhrgas believes that the position of the Federal Cartel Office violates basic principles of German law (including those of freedom of contract and free competition), as well as threatening the long-term security of gas supplies in Germany. Given that such questions can only be definitively resolved by the courts, E.ON Ruhrgas has filed an emergency petition with the State Superior Court (Oberlandesgericht) in Düsseldorf in order to prevent the order from taking effect. In the context of negotiations with the Federal Cartel Office prior to the January 13 order, E.ON Ruhrgas had already voluntarily offered those of its German distribution customers and municipal utilities that are supplied with more than 50 percent of their total gas requirements by E.ON Ruhrgas the termination of their existing contracts by October 1, 2008 in conjunction with a right to reduce their contractual amounts to 50 percent of their total gas purchases by either October 1, 2006 or October 1, 2007. No assurance can be provided as to the outcome of E.ON Ruhrgas’ petition or any related proceedings, or as to any impact of these matters on E.ON’s results of operation and financial condition.

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 “Item 4. Information on the Company — Business Overview — Pan-European Gas — Sales.”

If the Company’s plans to make selective acquisitions and investments to enhance its core energy business are unsuccessful, the Company’s future earnings and share price could be materially and adversely affected.

The Company’s business strategy involves selective acquisitions and investments in its core business area of energy. This strategy depends in part on the Company’s ability to successfully identify and acquire companies that enhance its business on acceptable terms. In order to obtain the necessary approvals for acquisitions, the Company may be required to divest other parts of its business, or to make concessions or undertakings which materially affect its operations. For example, the Company’s efforts to obtain control of Ruhrgas through a series of purchases from the holders of Ruhrgas interests were initially blocked by the German Federal Cartel Office and then by a series of plaintiffs who succeeded in convincing the State Superior Court in Düsseldorf to issue a temporary injunction preventing the Company from completing the transaction. In order to receive the ministerial approval of the German Economics Ministry that overruled the initial decision of the Federal Cartel Office, the Company was 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, the Company agreed

to divest certain of its 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. For more information, see “Item 4. Information on the Company — History and Development of the Company — Ruhrgas Acquisition.” Each of these matters delayed completion of the Ruhrgas acquisition and had the effect of increasing the cost of the transaction to the Company.

In February 2006, E.ON announced that it would launch an all cash tender offer for 100 percent of the share capital of Endesa, S.A. (“Endesa”), the largest electric utility in Spain and Portugal, which also has significant operations in Latin American and Southern Europe. E.ON intends to finance the acquisition through a combination of its own resources and new financing in the form of a committed line of credit provided by a syndicate of international banks. The offer will be subject to a number of conditions, including that E.ON acquire at least 50.01 percent of Endesa’s capital stock and that Endesa’s shareholders enact several changes to Endesa’s Articles of Association removing corporate governance-related obstacles to E.ON’s acquisition of control. The offer will also be subject to the approval of the Spanish government, which holds a “golden share” in Endesa, as well as antitrust and other regulatory approvals. Endesa’s board of directors has not taken a formal position with regard to E.ON’s proposed offer (though it has indicated that it believes that Endesa is worth more than the €27.50 per share offer price currently being proposed), nor has the Spanish government issued any formal statement as to its position on the offer. No assurance can be given that E.ON will be able to complete the transaction successfully on the proposed terms or at all. For additional information, see “Item 4. Information on the Company — History and Development of the Company — Proposed Endesa Acquisition.”

In addition, there can be no assurances that the Company will be able to achieve the benefits it expects from any acquisition or investment. For example, the Company may fail to retain key employees, may be unable to successfully integrate new businesses with its 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, such as that of Ruhrgas, the purchase of which was completed in March 2003, or the proposed acquisition of Endesa, present particularly difficult challenges. Investments and acquisitions in new geographic areas or lines of business require the Company to become familiar with new markets and competitors and expose the Company to commercial and other risks, as well as additional regulatory regimes relating to the acquired businesses that may be stricter than the ones the Company is currently subject to. Because of the risks and uncertainty associated with acquisitions and investments, any acquired businesses or investments may not achieve the profitability expected by the Company.

The Company could be subject to environmental liability associated with its nuclear and conventional power operations that could materially and adversely affect its business.

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, the Company may still be subject to future environmental claims with respect to alleged historical environmental damage arising from certain of its 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. The Company may also be subject to environmental claims with respect to Degussa’s operations. If claims were to be asserted against the Company in relation to environmental damages and plaintiffs were successful in proving their claims, such claims could result in material losses to the Company.

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 the Company to liability under applicable Swedish law. The Company does not operate or have interests in nuclear power plants outside of Germany, Sweden and Switzerland, including in the United Kingdom, the

United States or the countries in Eastern Europe in which it operates. The Company takes extensive safety and risk management measures in the operation of its nuclear power operations, and has mandatory insurance with respect to its nuclear operations as described in “Item 4. Information on the Company — Environmental Matters — Germany: Electricity” and “— Nordic.” However, any claims against the Company arising in the case of a nuclear power accident could exceed the coverage of such insurance, and cause material losses to the Company.

The Company expects that it 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 (“NO_x”) emissions from electricity generating units. These regulations require E.ON U.S. to make significant additional capital expenditures in NO_x control equipment, which are currently estimated to total approximately $407 million through 2006, of which nearly all ($405 million) has been incurred through 2005. E.ON U.S. also expects to make additional capital expenditures to reduce sulphur dioxide (“SO₂”) emissions from generation units totaling $743 million through 2009. E.ON U.S. 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 is currently being discussed. The legislation is expected to require 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 recently 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 NO_x. This amendment requires both E.ON Energie and E.ON Ruhrgas to make investments in pollution control devices. In addition, in the United States, E.ON U.S. is also affected by a number of regional and industry-wide transmission market structure changes that have recently been introduced by the relevant authorities. Currently, none of E.ON’s market units can predict the extent to which their respective operations will be affected by the new or proposed 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 costs for the Company. Any such increase in costs that cannot be fully recovered from customers may adversely affect the Company’s operating results or financial condition.

Although environmental laws and regulations have an increasing impact on the Company’s activities in almost all the countries in which it operates, it is impossible to predict accurately the effect of future developments in such laws and regulations on the Company’s future earnings and operations. Some risk of environmental costs and liabilities is inherent in particular operations and products of the Company, 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 “Item 4. Information on the Company — Environmental Matters.”

If power outages involving the Company’s electricity operations occur, the Company’s business and results of operations could be negatively affected.

Each of Italy, Denmark, Sweden, London and large parts of the United States and Canada experienced major power outages during 2003. The reasons for these blackouts vary, although with the exception of London 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, the Company’s German or international electricity operations could experience unanticipated operating or other problems leading to a power failure. For example, in the case of the blackout which occurred in Denmark and southern Sweden on September 23, 2003, one of the causes was an unexpected

power failure at the Oskarshamn power plant (which is 54.5 percent owned by the Company’s majority-owned subsidiary E.ON Sverige), that occurred as the plant was being reconnected to the grid following regularly scheduled maintenance. In addition, 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 approximately €140 million. 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; this possible separation of a number of wind power plants from the grid may in turn increase the impact of the original power failure in the grid. The Company can give no assurances that power failures involving its operations will not occur in the future, or that any such power failure would not have a negative effect on the Company’s business and results of operations.

Financial

The Company is exposed to financial risks that could have a material effect on its financial condition.

During the normal course of its business, the Company is 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 the Company may incur losses if any of the variety of instruments and strategies it uses to hedge exposures are not effective. For more information about these risks and the Company’s hedging policies and instruments, see “Item 5. Operating and Financial Review and Prospects — Exchange Rate Exposure and Currency Risk Management” and “Item 11. 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.

The Company is also exposed to other financial risks. For example, it holds certain stock investments which may expose it 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 the Company’s outstanding debt bears interest at floating rates; the Company’s interest expense will therefore increase if the relevant base rates rise. The value of the Company’s investments in fixed rate bonds will be adversely affected by a rise in market interest rates.

The Company also faces risks arising from its energy trading operations. In general, the Company seeks 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 the Company is unable to hedge these risks, or enters into hedging contracts that fail to address its exposure or incorrectly anticipate market movements, it 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 the Company’s energy marketing, trading and treasury activities, where loss may result from the non-performance of contractual obligations by a counterparty. The Company maintains credit policies and control procedures with respect to counterparties to protect it against losses associated with such types of credit risk, although there can be no assurance that these policies and procedures will fully protect the Company. The marking to market of many of E.ON’s hedging instruments required by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), has also increased the volatility of the Company’s results of operations, though it has not had a material effect on E.ON’s overall risk exposure. For example, in 2005, unrealized gains from the marking to market of derivatives, principally at the U.K. market unit, contributed other non-operating earnings of approximately €1.2 billion. For more information about the Company’s energy trading operations, its hedging policies and the instruments used, see “Item 4. Information on the Company — Business Overview — Central Europe — Trading,” “— Pan-European Gas — Trading,” “— U.K. — Energy Wholesale — Energy Trading,” “— Nordic — Trading” and “— U.S. Midwest — Power Generation — Asset-Based Energy Marketing,” “Item 5. Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31,

2005 Compared with Year Ended December 31, 2004” and “— Exchange Rate Exposure and Currency Risk Management” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk.”


Item 4.	Information on the Company.

HISTORY AND DEVELOPMENT OF THE COMPANY

E.ON AG is a stock corporation organized under the laws of the Federal Republic 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 the Federal Republic of 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.

VEBA-VIAG MERGER

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 to form E.ON has created the second-largest industrial group in Germany, based on market capitalization at year-end 2005, with sales of €56.4 billion in 2005.

In order to effectuate the merger, VEBA and VIAG submitted an application to the Merger Task Force of the European Commission on December 14, 1999. The EU Commission examined the planned merger and, with its notification of June 13, 2000, declared it to be compatible with the common market. The EU Commission’s approval required VEBA and VIAG to commit to make certain divestments in their combined electricity and chemical operations, and to give undertakings to 1) waive transfer charges for cross-zone deliveries of electricity within Germany, 2) purchase a certain minimum amount of electricity from Vattenfall Europe (formerly VEAG Vereinigte Energiewerke Aktiengesellschaft (“VEAG”)), a utility primarily active in the eastern part of Germany, at market rates during the period ending on December 31, 2007, and 3) provide additional interconnector capacity on the border between Germany and Denmark.

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. On June 16, 2000, the merger was entered into the Commercial Register in Düsseldorf. Upon registration with the Commercial Register in Düsseldorf, the merger was completed and became effective for purposes of U.S. GAAP as of July 1, 2000. 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. For information about certain claims brought by former VIAG shareholders regarding the share exchange ratio used in the VEBA-VIAG merger, see “Item 8. Financial Information — Legal Proceedings.”

POWERGEN GROUP ACQUISITION

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. See “— Business Overview — U.S. Midwest.” 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 “— Business Overview — U.K.” and “— U.S. Midwest.”

RUHRGAS ACQUISITION

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.

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 stakes. 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 Economics Ministry, 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. In March 2002, E.ON agreed to acquire ThyssenKrupp AG’s interest in Ruhrgas.

In May 2002, E.ON 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. Under the arrangement, RAG acquired a majority shareholding in Degussa in two steps. In the first step, in June 2002, RAG made a cash tender offer to Degussa’s shareholders at a price of €38 per share. The parties’ definitive agreement provided that after completion of the tender offer RAG and E.ON would hold equal shareholdings of Degussa and would manage Degussa jointly. In the second step, E.ON sold 3.6 percent of Degussa’s shares to RAG at the above price to give RAG a 50.1 percent interest in Degussa effective June 1, 2004.

On July 3, 2002, E.ON reached agreements to acquire the 40 percent interest in Ruhrgas held indirectly by Esso Deutschland GmbH, Deutsche Shell GmbH, and TUI AG, which would make E.ON the sole owner of Ruhrgas.

On July 5, 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 75 billion kilowatt hours (“kWh”) of natural gas to its competitors and to legally unbundle its transmission system from its other operations. In addition, E.ON and Ruhrgas were required to divest several shareholdings. On the same day, E.ON 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. In addition, the court prohibited the Company from exercising its shareholders’ rights with respect to the Ruhrgas stake it had acquired from BP, Vodafone and ThyssenKrupp AG until the takeover was approved. E.ON

continued to maintain that the reasons given by the court in the summary proceedings leading to these orders did not justify its decision.

Following the issuance of the temporary injunction, on September 18, 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 Bayerngas GmbH (“Bayerngas”) and swb AG (“swb”), and all of the companies required to be disposed of were granted special rights to terminate their existing purchase agreements with E.ON and Ruhrgas on a staggered basis. In addition, customers purchasing more than 50 percent of their gas requirements from Ruhrgas were granted the right, as of October 2003, to reduce the volume of gas purchased from Ruhrgas to 80 percent of the contracted amount. Finally, 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.

On December 17, 2002, the State Superior Court decided not to lift the temporary injunction, and formal proceedings (Hauptverfahren) regarding the injunction started 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 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. With effect from June 1, 2004, E.ON sold a further 3.6 percent of Degussa stock to RAG, 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. The purchase price is expected to total approximately €2.8 billion, equal to €31.50 per Degussa share. The transaction is expected to be completed by July 1, 2006.

In accordance with the obligations set out in the ministerial approvals mandating the sale of an aggregate amount of 200 billion kWh of baseload gas, on July 30, 2003, E.ON Ruhrgas offered approximately 33 billion kWh of natural gas from its portfolio of long-term supply contracts in the first of six internet-based annual auctions. 15 billion kWh of this gas was sold. On May 19, 2004, E.ON Ruhrgas offered approximately 39 billion kWh of gas under its long-term supply contracts in the second auction. The offered volume included one third of the volumes (approximately 6 billion kWh) left unsold in the first auction. In the 2004 auction, seven bidders purchased an aggregate volume of approximately 35 billion kWh of gas. On May 18, 2005, E.ON Ruhrgas offered approximately 39 billion kWh of gas under its long-term supply contracts in a third auction, which again included one-third of the volumes (approximately 6 billion kWh) not sold in the first auction. In the 2005 auction, seven bidders purchased the total volume of gas offered. The prices E.ON Ruhrgas obtained in the first two auctions were in line with the minimum prices set by the German Federal Ministry for Economics and Labor (now renamed the Federal Ministry for Economics and Technology) (Bundesministerium für Wirtschaft und Technologie). In the auction conducted in 2005, the quantities on offer were sold at a premium to the minimum

price. E.ON Ruhrgas is required to hold three more annual gas auctions. The remaining third of the volumes not sold in the first auction (approximately 6 billion kWh) will be offered in 2006.

In connection with its acquisition of Ruhrgas, E.ON seeks to achieve the following potential synergies in its market units:


	•	In the Pan-European Gas market unit, E.ON intends to leverage its increased gas operations to improve its negotiating position with producers of natural gas, and to take advantage of pan-European gas arbitrage opportunities. For information about E.ON’s planned capital investment in E.ON Ruhrgas, see “Item 5. Operating and Financial Review and Prospects — Liquidity and Capital Resources.”

	•	In the Central Europe market unit, E.ON expects to benefit from joint market management with regional energy companies, the integration of continental European gas trading activities and the sharing of technical expertise among the power and gas businesses. In order to integrate the Company’s continental European gas trading activities conducted by D-Gas B.V. (“D-Gas”), E.ON Energie transferred their gas trading operations to E.ON Ruhrgas in 2004.

	•	In the U.K. market unit, E.ON intends to use the Pan-European Gas market unit to enhance E.ON UK’s gas supply and gas storage options, as well as support its trading activities. An important first step was the conclusion of a 10-year gas supply contract between E.ON Ruhrgas and E.ON UK. E.ON Ruhrgas started supplying E.ON UK with gas in October 2004.

	•	In the Nordic market unit, E.ON also intends to use the Pan-European Gas market unit to enhance E.ON Sverige’s gas supply options and expects to be able to use a joint approach for future gas infrastructure development. E.ON Ruhrgas and E.ON Sverige have also entered into a gas supply contract, pursuant to which E.ON Ruhrgas started to supply E.ON Sverige with natural gas in autumn 2005.

In addition, E.ON has identified a number of areas in which it expects to achieve cost savings through the integration of E.ON Ruhrgas and other E.ON Group companies. Major areas of potential cost savings include the reduction of procurement costs through process optimization and joint purchasing power, the integration of gas trading activities in central Europe and savings in overhead costs.

For more information on E.ON Ruhrgas, see “— Business Overview — Pan-European Gas.” For more information on the impact of this transaction on E.ON’s financial condition, see “Item 5. Operating and Financial Review and Prospects — Overview.” In addition, in connection with E.ON’s on.top project, E.ON Energie transferred a number of shareholdings to E.ON Ruhrgas or to E.ON AG, and E.ON Ruhrgas transferred a number of shareholdings to E.ON Energie. These transfers, which generally took place in December 2003, or in 2004 or 2005, are described in more detail in “— On.top Project.”

PROPOSED ENDESA ACQUISITION

On February 21, 2006, E.ON announced that it had filed a takeover offer for 100 percent of the share capital of Endesa with the Spanish Securities Commission CNMV (“CNMV”). According to the documents Endesa has filed with the SEC, including its Annual Report on Form 20-F for the fiscal year ending December 31, 2004 and its Form 6-K dated January 19, 2006 reporting its audited financial results for 2005 (collectively, the “Endesa SEC Filings”), Endesa is a limited liability company organized under the laws of the Kingdom of Spain; its ordinary shares are traded on the Madrid, Barcelona, Bilbao and Valencia stock exchanges in Spain and the Santiago Off Shore Stock Exchange in Chile, and its American Depositary Shares (“ADSs”) are listed on the New York Stock Exchange.

E.ON’s proposed offer price is €27.50 per Endesa share and per Endesa ADS in an all cash offer, which would result in an aggregate purchase price of approximately €29.1 billion if all shares and ADSs were to be tendered. Should the offer be successful, E.ON would also expect to include Endesa’s net financial liabilities, provisions and minority interests equal to approximately €26.1 billion as of December 31, 2005 (according to the Endesa SEC Filings) in its financial statements, thus bringing the aggregate transaction value to approximately €55.2 billion. E.ON intends to finance the acquisition through a combination of its own resources and new financing in the form of a committed line of credit provided by a syndicate of international banks. If Endesa

shareholders are paid a dividend prior to the completion of the transaction, the offer price of €27.50 per share will be reduced by the amount of the per-share dividend.

The offer document is subject to prior review and approval of the CNMV before the offer will commence. E.ON expects to file a Schedule TO relating to the offer with the SEC once the CNMV has approved the Spanish offer document.

E.ON’s offer will be subject to a number of conditions, including that E.ON acquire at least 529,481,934 Endesa shares, equal to 50.01 percent of Endesa’s capital stock, and that Endesa’s shareholders must enact several changes to Endesa’s Articles of Association removing corporate governance-related obstacles to E.ON’s acquisition of control. The takeover will also be subject to the approval of the Spanish government, which holds a “golden share” in Endesa, to the approval of the Spanish Energy Commission (CNE), and to EU antitrust approval. Endesa’s board of directors has not taken a formal position with regard to E.ON’s proposed offer, though it has indicated that it believes that Endesa is worth more than the €27.50 per share offer price currently being proposed, nor has the Spanish government issued any formal statement as to its position on the offer. No assurance can be given that E.ON will be able to complete the transaction successfully on the proposed terms or at all. See also “Item 3. Key Information — Risk Factors.”

The following information about Endesa is taken from the Endesa SEC Filings. E.ON has not independently verified such information and therefore does not accept any responsibility for its accuracy or completeness. Endesa is the largest electricity company in Spain and Portugal in terms of installed capacity and market share in generation and distribution, with a significant presence in the Southern European electricity market, in particular in Italy, and one of the largest private-sector multinational electricity companies in Latin America. The company’s core business is energy. It is also involved in other activities related to its core energy business such as renewable energies and co-generation and the distribution and supply of natural gas. In addition, Endesa holds interests in other businesses such as telecommunications.

At December 31, 2004, Endesa had a total installed capacity of 46,439 MW, and in 2004, the company generated 184,951 gigawatt hours (“GWh”) of electricity and sold 192,519 GWh, supplying electricity to approximately 22.2 million customers in 12 countries. At that date, Endesa had 27,918 employees, 51 percent of whom were located outside Spain.

Based on Endesa’s financial results for the year ended December 31, 2005, Endesa recorded net sales of €17,508 million and net income of €3,182 million in accordance with International Financial Reporting Standards (“IFRS”), which differ from U.S. GAAP, the basis on which E.ON prepares its consolidated financial statements.

GROUP STRATEGY


	*E.ON’s Business Model After On.top*

E.ON’s strategy is grounded in an integrated business model that is based on the following key points:


	•	An Integrated Power and Gas Business. E.ON intends to follow a long-term strategy with a clear focus on integrated power and gas operations that enjoy leading positions in their respective markets. In doing so, it seeks to develop positions throughout the energy value chain, including positions in infrastructure where they are seen as enhancing E.ON’s access to markets and customers.

	•	A Clear Geographic Focus. E.ON seeks to strengthen its leading positions and performance in its existing markets (Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest), while taking focused steps in new markets such as Italy, Russia and — through the proposed acquisition of Endesa — also Spain.

	•	Clear Strategic Priorities. E.ON’s first priority is to strengthen and grow its position in European markets while maintaining a strong and diversified generation portfolio and enhancing its gas supply position through investments in “equity gas” produced from fields in which E.ON holds an interest, as well as the potential development of liquefied natural gas (“LNG”) as an alternative form of gas delivery. E.ON currently views the United States as an opportunity for more long-term growth.


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


	*Strategy*

Building on this model, E.ON’s corporate strategy is to maximize the value of its portfolio of focused energy businesses through:


	•	Creating value from the 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, E.ON will be able to supply its retail gas business in the United Kingdom from its Pan-European Gas supply business);

	•	Creating value from vertical integration (i.e., establishing a presence in all portions 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 E.ON with opportunities to realize economies of scale in servicing costs while increasing customer loyalty, thus reducing its customer “churn rate”;

	•	Enhancing operational performance through identifying and transferring best practice for common activities throughout the Group’s different market units (e.g., effective programs for enhancing E.ON’s electricity generation, distribution and retailing businesses);

	•	Improving the Group’s competitive position in its target markets, both through organic growth and through pursuing selective investments which contribute to these objectives or provide stand alone value creation opportunities, as described below;

	•	Creation of a common corporate culture under the OneE.ON project, which seeks to enhance integration of all market units and their subsidiaries under the E.ON banner so as to help the E.ON Group realize its vision and strategic goals, while maintaining its commitment to corporate social responsibilities; and

	•	Tapping value-enhancing growth potential in new markets such as Italy, Russia and Spain.

In addition, E.ON has set a number of specific objectives for its market units in implementing its corporate strategy within each of its target markets, namely:


	•	Central Europe — Fortifying strong market positions and developing new growth potential through:


	•	consolidation of distribution and sales activities and capitalizing on opportunities from power-gas convergence;

	•	re-investing in power generation to maintain the strong market position;

	•	hedging exposure to price risks through vertical integration of generation and sales operations;

	•	participating in the privatization of power and downstream gas companies in eastern Central Europe, as well as selective investments in power generation; and

	•	continued growth in the new market of Italy, i.e. in power generation.


	•	Pan-European Gas — Strengthening and diversifying E.ON Ruhrgas’ current position through:


	•	selective equity investments in gas production in the North Sea and Russia;

	•	evaluation of LNG options (including upstream positions) to ensure long-term supply diversification;

	•	participation in infrastructure projects to enhance gas supply position in Europe; and

	•	selective acquisitions of mid- and downstream companies in Europe.


	•	U.K. — Enhancing profitability of the U.K. businesses through:


	•	investing in flexible generation assets and low carbon intensive generating technologies, such as Combined Cycle Gas Turbine (“CCGT”), to maintain a low cost hedge for changes in retail electricity demand;

	•	investing in the generation of power from renewable resources to capture value from the U.K. government’s renewable obligation mandate; and

	•	investing in gas storage assets to hedge against potentially volatile gas price movements as the United Kingdom starts to become a net importer of gas.


	•	Nordic — Strengthening E.ON’s position through:


	•	expanding its presence in power generation;

	•	enhancing scale through synergistic acquisitions in distribution and district heating; and

	•	continued participation in gas supply and infrastructure developments.


	•	U.S. Midwest — Focusing on optimizing E.ON U.S.’s current operations in Kentucky and delivering additional performance improvements. This could include investments in generation capacity if the demand for electricity grows and the U.S. regulatory authorities enable the Company to earn a return on investment that meets its stringent criteria.

As it focuses on energy, E.ON will seek to maximize the value of its remaining non-core businesses by divesting them at an appropriate time and allocating the proceeds to strategic investments. As part of its strategy to focus on its core energy business, E.ON completed its disposal of Viterra and Ruhrgas Industries GmbH (“Ruhrgas Industries”) in 2005 and is actively pursuing the disposal of its remaining minority interest in Degussa, which is expected to be completed during 2006. For information on Degussa, see “— Business Overview — Other Activities.”

The transformation of the Company into a focused energy business has entailed further divestment and acquisition activities in recent years. For more detailed information on the principal activities in implementing the transformation, see “— Powergen Group Acquisition,” “— Ruhrgas Acquisition” and the respective market unit descriptions in “— Business Overview.”

ON.TOP PROJECT

Started in 2003, the “on.top” project resulted in a reorganization of E.ON’s core energy business into five new market units. These market units, each focusing on a region in which management believes E.ON has a strong competitive position, are:


	•	Central Europe, led by E.ON Energie AG;

	•	Pan-European Gas, led by E.ON Ruhrgas AG;

	•	U.K., led by E.ON UK plc;

	•	Nordic, led by E.ON Nordic AB; and

	•	U.S. Midwest, led by E.ON U.S. LLC (formerly LG&E Energy).

The activities of the Central Europe, Nordic, U.K. and U.S. Midwest market units include the generation, transmission, distribution and sale of energy to customers in each regional market. While focusing on electricity, these activities also include or will include distribution and sales of natural gas to retail customers. The Pan-European Gas unit focuses on the supply, transmission, storage and sale of natural gas to distributors and industrial customers in Europe, and also engages in trading and gas exploration and production activities. In addition, the market unit has primarily minority interests in a large number of German and other European municipal and regional energy distribution companies.

The lead companies of each market unit report directly to E.ON AG. E.ON AG serves as the Group’s corporate center and is responsible for the design and implementation of strategies and policies with the goal of optimizing the Group’s results across the energy markets in which it is active, the pursuit of operational excellence at each of the market units through the transfer of best practice, as well as a strong role in regulatory affairs that may affect several market units at the same time. E.ON AG also has direct responsibility for strategic acquisitions throughout the Group. Human resources management and career development for 200 top executives currently working across the Group have also been centralized at the Corporate Center.

E.ON’s financial reporting mirrors the E.ON group 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. The results of E.ON’s minority interest in Degussa continue to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which is reported as a separate segment. The primary measure by which management evaluates the performance of each segment in accordance with SFAS 131 is adjusted EBIT. E.ON defines this measure as an adjusted figure 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. 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, 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. Management believes that this measure 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.

As part of the implementation of the new structure, E.ON completed intra-Group transfers of shareholdings in a number of its companies in December 2003, in 2004 and in 2005. These transactions include:


	•	The transfer by E.ON Energie to E.ON Ruhrgas of its:


	•	67.7 percent interest in Thüga;

	•	29.95 percent interest of its 40.0 percent interest in the Austrian company RAG Beteiligungs-Aktiengesellschaft, which owns a 75.0 percent share in the Austrian exploration and production company Rohöl-Aufsuchungs Aktiengesellschaft; the remaining 10.05 percent interest was swapped with the Austrian company EVN AG for its 31.23 percent shareholding in the Hungarian gas distribution company Közép-dunántúli Gázszolgáltató Rt. (“KÖGÁZ”) in April 2005;

	•	18.8 percent interest in the Latvian gas supplier JSC Latvijas Gaze;

	•	14.3 percent interest in the Lithuanian gas distributor AB Lietuvos Dujos; and its

	•	gas trading company D-Gas.


	•	The transfer by E.ON Ruhrgas to E.ON Energie of its downstream gas activities in the Czech Republic and Hungary, including its:


	•	4.45 percent interest in the Czech gas distribution company Jihomoravská plynárenská a.s. (“JMP”);

	•	27.6 percent interest in the Czech gas distribution company Západoceská plynárenská a.s. (“ZCP”);

	•	24.0 percent interest in the Czech gas distribution company Prazská plynárenská Holding a.s. (“PPH”);

	•	0.05 percent interest in the Czech gas distribution company Prazská plynárenská a.s. (“PP”);

	•	14.3 percent interest in the Czech gas distribution company Stredoceska plynárenská a.s. (“STP”);

	•	9.57 percent interest in the Czech gas distribution company Severomoravská plynárenská a.s. (“SMP”);

	•	16.52 percent interest in the Czech gas distribution company Východoceská plynárenská a.s. (“VCP”);

	•	49.8 percent interest in the Hungarian gas distribution company Déldunántuli Gázszolgáltató Részvenytársaság (“DDGÁZ”); and its


	•	16.3 percent interest in the Hungarian gas distribution company Fövárosi Gázmüvek Részvénytársaság (“FÖGÁZ”).


	•	The transfer by E.ON Energie to E.ON AG of its 100 percent interest in E.ON Scandinavia (which has since been renamed E.ON Nordic), including its:


	•	55.2 percent interest in Sydkraft (which has since been renamed E.ON Sverige), including its interest in Graninge AB (“Graninge”) and its interest in the Baltic Cable; and a

	•	65.6 percent interest in E.ON Finland.

The on.top project also included the definition of mid-term performance targets for the Group. Management’s principal goal in guiding strategic and investment decisions is to realize a significant improvement in E.ON’s return on capital while growing earnings through 2006.

OTHER SIGNIFICANT EVENTS

In November 2004, E.ON Ruhrgas International AG (“ERI”) signed an agreement for the acquisition of 75.0 percent minus one share each of the gas trading and gas storage businesses of the Hungarian oil and gas company MOL RT. (“MOL”) and its 50.0 percent interest in the gas importer Panrusgáz Rt. (“Panrusgáz”). In addition, MOL received a put option to sell to ERI up to 75.0 percent minus one share of its gas transmission business and put options to sell to ERI the remaining 25.0 percent plus one share in the MOL gas trading and gas storage businesses. As a condition of antitrust approval by the EU Commission, MOL is obliged to sell the remaining 25.0 percent plus one share of the gas trading and storage business as well. As a result, ERI signed an agreement for the acquisition of the remaining 25.0 percent plus one share of each of these two companies. These transactions are expected to be completed at the end of March 2006.

In February 2005, E.ON Energie acquired 67.0 percent stakes in each of the two northeastern Bulgarian electricity distribution companies Elektrorazpredelenie Varna AD (“Varna”) and Elektrorazpredelenie Gorna Oryahovitza AD (“Gorna Oryahovitza”).

In May 2005, E.ON disposed of Viterra to Deutsche Annington GmbH (“Deutsche Annington”). The transaction received antitrust approval in early August 2005. Under U.S. GAAP, Viterra was accounted for as discontinued operations since its disposal.

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 transaction received antitrust approval and was closed in September 2005. Under U.S. GAAP, Ruhrgas Industries was accounted for as discontinued operations since June 2005.

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”).

In September 2005, Sydkraft was renamed E.ON Sverige.

In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution company Electrica Moldova S.A. (“Electrica Moldova”) — now 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 September 2005, Gazprom, BASF AG (“BASF”) and E.ON AG signed a basic agreement on the construction of the North European Gas Pipeline (“NEGP”) through the Baltic Sea from Vyborg on Russia’s Baltic coast to Germany’s Baltic coast. The parties to the agreement intend to set up the North European Gas Pipeline Company as a joint German-Russian venture, with Gazprom holding 51.0 percent and BASF’s subsidiary Wintershall Aktiengesellschaft (“Wintershall”) and E.ON Ruhrgas each holding 24.5 percent.

In October 2005, E.ON sold a portion (1.6 TWh) of the generation capacity that E.ON Sverige had acquired as part of the Graninge acquisition to E.ON Sverige’s minority shareholder, the Norwegian energy company Statkraft (“Statkraft” refers to Statkraft SF and its consolidated subsidiaries).

In November 2005, E.ON Ruhrgas acquired 100 percent of the U.K. gas production company Caledonia Oil and Gas Ltd. (“Caledonia”).

In December 2005, LG&E Energy was renamed E.ON U.S.

In December 2005, E.ON AG and RAG signed a framework agreement on the sale of E.ON’s remaining 42.9 percent stake in Degussa to RAG. The transaction is expected to be completed by July 1, 2006.

In February 2006, E.ON Nordic and Fortum Power and Heat Oy (“Fortum”) signed an agreement, whereby Fortum will acquire E.ON Nordic’s 65.6 percent stake in E.ON Finland. The sale is subject to the approval of the Finnish competition authorities.

In February 2006, E.ON filed a takeover offer for 100 percent of the share capital of Endesa.

See also “— Proposed Endesa Acquisition,” the respective market unit descriptions in “— Business Overview” and the descriptions in “Item 5. Operating and Financial Review and Prospects — Acquisitions and Dispositions” and “— Liquidity and Capital Resources.”

CAPITAL EXPENDITURES

E.ON’s aggregate capital expenditures for property, plant and equipment were €2.9 billion in 2005 (2004: €2.5 billion, 2003: €2.5 billion). For a detailed description of these capital expenditures, as well as E.ON’s expected capital expenditures for the period beginning in 2006, see “Item 5. Operating and Financial Review and Prospects — Liquidity and Capital Resources.”

BUSINESS OVERVIEW

INTRODUCTION

E.ON is the second-largest industrial group in Germany, measured on the basis of market capitalization at year-end 2005. In 2005, the Group’s core energy business was organized into the following separate market units: Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest, as well as the Corporate Center. Outside its core energy business, E.ON holds a 42.9 percent interest in Degussa, which is not consolidated, but rather accounted for using the equity method.

Core Energy Business

Central Europe. 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, with revenues of €24.3 billion (which included €1.0 billion of electricity taxes that were remitted to the tax authorities) in 2005. E.ON Energie’s core business consists of the ownership and operation of power generation facilities and the transmission, distribution and sale of electric power, gas and heat in Germany and continental Europe. The Central Europe market unit owns interests in and operates power stations with a total installed capacity of approximately 36,400 megawatts (“MW”), of which Central Europe’s attributable share is approximately 27,800 MW (not including mothballed, shutdown and reduced power plants). Through its own operations, as well as through distribution companies, in most of which it owns a majority interest, E.ON Energie also distributes electricity, heat and gas to regional and municipal utilities, commercial and industrial customers and residential customers. In 2005, E.ON Energie supplied approximately 18 percent of the electricity consumed by end users in Germany. The Central Europe market unit contributed 43.1 percent of E.ON’s revenues and recorded adjusted EBIT of €3.9 billion in 2005.

Pan-European Gas. E.ON Ruhrgas is the lead company of the Pan-European Gas market unit. 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, with 690.2 billion kWh of gas sold in 2005. E.ON Ruhrgas’ principal business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas imports gas from Russia, Norway, the Netherlands, the United Kingdom and Denmark, and also purchases gas from domestic sources. E.ON Ruhrgas sells this gas to regional and supraregional 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 11,000 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 small shareholding in Gazprom, Russia’s main natural gas exploration, production, transportation and marketing company. In 2005, the Pan-European Gas market unit recorded revenues of €17.9 billion (which included €3.1 billion in natural gas and electricity taxes that were remitted, directly or indirectly, to the tax authorities) and adjusted EBIT of €1.5 billion. The Pan-European Gas market unit contributed 31.8 percent of E.ON’s revenues in 2005.

U.K. E.ON UK is the lead company of the U.K. market unit. E.ON UK is an integrated energy company with its principal operations focused in the United Kingdom. E.ON UK and its associated companies are actively involved in the ownership and operation of power generation facilities, as well as in the distribution of electricity and supply of electric power and gas and in energy trading. E.ON UK owns interests in and operates power stations with a total installed capacity of approximately 10,762 MW, of which its attributable share is approximately 10,547 MW. E.ON UK served approximately 8.6 million electricity and gas customer accounts at December 31, 2005 and its Central Networks business served 4.9 million customer connections. In 2005, E.ON UK recorded revenues of €10.2 billion or 18.0 percent of E.ON’s revenues, and adjusted EBIT of €963 million.

Nordic. E.ON Nordic is the lead company of the Nordic market unit. It currently operates through the two integrated energy companies in which it holds majority stakes, E.ON Sverige and E.ON Finland. E.ON Nordic and its associated companies are actively involved in the ownership and operation of power generation facilities, as well as the distribution and supply of electric power, gas and heat, primarily in Sweden and Finland. Through E.ON Sverige and E.ON Finland, E.ON Nordic owns interests in power stations with a total installed capacity of approximately 14,982 MW, of which its attributable share is approximately 7,570 MW (not including mothballed and shutdown power plants). In February 2006, E.ON Nordic and Fortum signed an agreement, whereby Fortum will acquire E.ON Nordic’s 65.6 percent stake in E.ON Finland. The sale is subject to the approval of the Finnish competition authorities. In 2005, E.ON Nordic recorded revenues of €3.5 billion (including €402 million of electricity and natural gas taxes that were remitted to the tax authorities) or 6.2 percent of E.ON’s revenues, and adjusted EBIT of €806 million.

U.S. Midwest. 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 off-system sales. 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. E.ON U.S. owns interests in and operates power stations with a total installed capacity of approximately 8,300 MW, of which its attributable share is approximately 7,700 MW (not including mothballed and shutdown power plants). In 2005, the U.S. Midwest market unit recorded revenues of €2.0 billion or 3.6 percent of E.ON’s revenues, and adjusted EBIT of €365 million.

Corporate Center. The Corporate Center consists of E.ON AG itself, equity interests managed directly by E.ON AG, including its remaining telecommunications interests, and consolidation effects at the Group level, including the elimination of intersegment sales.

Other Activities

Degussa. Degussa is one of the major specialty chemical companies in the world. As of February 2003, following the first step of the RAG/ Degussa transaction described in “— History and Development of the Company — Ruhrgas Acquisition,” E.ON held a 46.5 percent interest in Degussa and operated Degussa under joint control with RAG, which also held a 46.5 percent interest. E.ON has accounted for Degussa using the equity method since February 1, 2003. Effective June 1, 2004, E.ON sold a further 3.6 percent of Degussa stock to RAG. For all periods from February 1, 2003 until May 31, 2004, E.ON recorded 46.5 percent of Degussa’s after-tax earnings in its financial earnings. From June 1, 2004, E.ON has recorded 42.9 percent of Degussa’s after-tax earnings in its financial earnings. In December 2005, E.ON AG and RAG signed a framework agreement on the

sale of E.ON’s remaining 42.9 percent stake in Degussa to RAG. In 2005, Degussa contributed adjusted EBIT of €132 million.

For information on E.ON’s discontinued operations, including its former oil, aluminum and silicon wafer divisions, as well as its real estate subsidiary Viterra and certain activities of the Central Europe, Pan-European Gas and U.S. Midwest market units, see “— Discontinued Operations.”

As a result of E.ON’s on.top strategic review launched in 2003, the core energy business has been reorganized into five new regional market units, plus the Corporate Center. Beginning in 2004, E.ON’s financial reporting mirrors the new 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. The results of E.ON’s minority interest in Degussa continue to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which is reported as a separate segment. As part of the implementation of the new structure, E.ON completed intra-Group transfers of shareholdings in a number of its companies in December 2003, in 2004 and in 2005. None of these transfers had any impact on E.ON’s financial results on a consolidated basis. To facilitate comparison, the table below includes reclassified revenues for 2003 according to the new market unit structure. For information about the transfer of shareholdings in connection with E.ON’s on.top project, see “— History and Development of the Company — On.top Project.” For additional information on the presentation of segment information for 2005, 2004 and 2003, see “Item 5. Operating and Financial Review and Prospects — Business Segment Information.”

The following table sets forth the revenues of E.ON by market unit for 2005, 2004 and 2003:


		2005						2004						2003

		(€ in						(€ in						(€ in
		millions)			%			millions)			%			millions)			%

Central Europe(1)(2)			24,295			43.1			20,752			44.4			19,253			43.6
Pan-European Gas(2)(3)			17,914			31.8			13,227			28.3			11,919			27.0
U.K.			10,176			18.0			8,490			18.2			7,923			18.0
Nordic(4)			3,471			6.2			3,347			7.1			2,824			6.4
U.S. Midwest(2)			2,045			3.6			1,718			3.7			1,771			4.0
Corporate Center(2)(5)			(1,502	)		(2.7	)		(792	)		(1.7	)		(575	)		(1.3	)

	Core Energy Business		56,399			100.0			46,742			100.0			43,115			97.7
	Other Activities(2)(6)		0			0			0			0			994			2.3

Total Revenues(7)			56,399			100.0			46,742			100.0			44,109			100.0


(1)	Includes electricity taxes of €1,049 million in 2005, €1,051 million in 2004 and €1,015 million in 2003.

(2)	Excludes the sales of certain activities now accounted for as discontinued operations. For more details, see “Item 5. Operating and Financial Review and Prospects — Acquisitions and Dispositions — Discontinued Operations” and Note 4 of the Notes to Consolidated Financial Statements.

(3)	Includes the sales of the former Ruhrgas activities from the date of consolidation on February 1, 2003. Sales include natural gas and electricity taxes of €3,110 million in 2005, €2,923 million in 2004 and €2,555 million in 2003.

(4)	Sales include electricity and natural gas taxes of €402 million in 2005, €395 million in 2004 and €324 million in 2003.

(5)	Includes primarily the parent company and effects from consolidation, as well as the results of its remaining telecommunications interests, as explained above.

(6)	Includes sales of Degussa until January 2003, prior to its deconsolidation. For more details, see “— Other Activities — Degussa,” “Item 5. Operating and Financial Review and Prospects — Overview” and Note 4 of the Notes to Consolidated Financial Statements.

(7)	Excludes intercompany sales.

Most of E.ON’s operations are in Germany. German operations produced 65.0 percent of E.ON’s revenues (measured by location of operation) in 2005 (2004: 64.2 percent; 2003: 64.6 percent). E.ON also has a significant presence outside Germany representing 35.0 percent of revenues by location of operation for 2005 (2004: 35.8 percent; 2003: 35.4 percent). In 2005, approximately 59.5 percent (2004: 61.2 percent; 2003: 61.5 percent) of E.ON’s revenues were derived from customers in Germany and 40.5 percent (2004: 38.8 percent; 2003: 38.5 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 2005, 2004 and 2003, see Note 31 of the Notes to Consolidated Financial Statements. At December 31, 2005, E.ON had 79,947 employees, approximately 43 percent of whom were employed in Germany. For more information about employees, see “Item 6. Directors, Senior Management and Employees — Employees.”

E.ON believes that as of December 31, 2005, it had close to 478,000 shareholders worldwide. E.ON’s shares, all of which are Ordinary Shares, are listed on all seven German stock exchanges. They are also actively traded over the counter in London. E.ON’s ADSs are listed on the New York Stock Exchange (“NYSE”). Until March 28, 2005, one ADS represented one Ordinary Share. Since March 29, 2005, three ADSs represent one Ordinary Share.

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 €24.3 billion (which included €1.0 billion of electricity taxes that were remitted to the tax authorities), €20.7 billion of which in Germany, and adjusted EBIT of €3.9 billion in 2005. 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.

In connection with E.ON’s acquisition of E.ON Ruhrgas, E.ON Energie was required to divest certain shareholdings. For more information about the required divestments, see “Item 5. Operating and Financial Review and Prospects — Acquisitions and Dispositions.”

In order to further focus its energy business in Germany and in continental Europe, E.ON Energie entered into the following transactions in 2005 and the beginning of 2006:


	•	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. In 2005, the company sold an aggregate of approximately 8.3 TWh of gas to 0.3 million customers.

	•	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 companies operate in northeastern Bulgaria. In 2005, the companies sold an aggregate of approximately 4.9 TWh of electricity to 1.1 million customers.

	•	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 interests in GVT totaling 43.9 percent to TEB. Consequently, GVT was merged into TEAG and the merged entity was renamed E.ON Thüringer Energie AG (“ETE”). Following this reorganization, E.ON Energie holds an 81.5 percent interest in TEB and TEB holds a 76.8 percent interest in ETE.

	•	In July 2005, E.ON Energie acquired an additional 0.9 percent interest in Contigas Deutsche Energie AG (“Contigas”) through a public offer. In June 2005, the general meeting of Contigas passed a resolution authorizing E.ON Energie to use a squeeze-out procedure to acquire the remaining Contigas stock held by minority shareholders. Following the completion of the squeeze-out in November 2005, E.ON Energie acquired the remaining 0.2 percent and now owns 100 percent of Contigas.


	•	In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution company Electrica Moldova — now renamed E.ON Moldova — and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. In 2004, the company sold approximately 4.3 TWh of electricity to 1.3 million customers.

	•	In September 2005, E.ON Benelux acquired 100.0 percent of the Dutch power and gas company NRE Energie b.v. (“NRE”). In 2004, the company supplied approximately 1.6 TWh of electricity and approximately 4.8 TWh of gas to approximately 0.3 million electricity and gas customers in the Netherlands.

	•	In 2005, E.ON Energie decided to invest in new power plants in Germany in Irsching (530 MW natural gas) and Datteln (1,100 MW hard coal). Additionally, E.ON Energie plans to build a new Italian power plant at Livorno Ferraris (800 MW natural gas). For more information, see “Item 5. Operating and Financial Review and Prospects — Liquidity and Capital Resources — Expected Investment Activity.”

	•	In February 2006, E.ON Energie and RWE signed agreements to swap certain shareholdings in the Czech Republic and Hungary. These transactions are subject to regulatory and corporate approvals and are expected to be completed in 2006.

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 and sale and trading. The following chart shows the major subsidiaries of the Central Europe market unit as of December 31, 2005, 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.


	*Western Europe*

Conventional Power Plants

E.ON Kraftwerke GmbH (100%)


•	Power generation by conventional power plants.
•	Waste incineration.
•	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.

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, Sale and Trading of Electricity, Gas and Heat

E.ON Sales & Trading GmbH (100%)


•	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.
•	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 distributors across Germany
(shareholding percentages range from 62.8 to 100.0 percent)


•	Distribution and sale of electricity, gas, heat and water to retail customers.
•	Energy support services.
•	Waste incineration.

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 sale of electricity and gas in Hungary through its group companies.

E.ON Czech Holding AG (100%)


•	Generation, distribution and sale of electricity in the Czech Republic through its group companies.

E.ON Moldova S.A. (51%)


•	Distribution and sale of electricity in Romania.

E.ON Bulgaria EAD (100%)


•	Distribution and sale of electricity in Bulgaria through its group companies.

Západoslovenská energetika a.s. (49.0% held at equity)


•	Distribution and sale of electricity in Slovakia.

Consulting and Support Services

E.ON Engineering GmbH (57.0%) (1)


•	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, renewable, cogeneration and nuclear power generation and pipeline business.

E.ON IS GmbH (60.0%) (2)


•	Provision of information technology services to companies within the Group and third parties.

E.ON Facility Management GmbH (100%)


•	Infrastructure services.


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

(2)	The remaining 40.0 percent is held by E.ON AG and E.ON Ruhrgas.

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, nuclear and hydroelectric generation businesses, transmission, 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 other 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 and Sale:		the transfer and sale of electricity from the interregional power grid and its delivery, across local distribution systems, 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.

The following table sets forth the sources of E.ON Energie’s electric power in kWh in 2005 and 2004:

2005

2004

million

Sources of Power

kWh

Change

Own production

129,063

131,278

-1.7

Purchased power

142,215

123,035

+15.6

from power stations in which E.ON Energie has an interest of 50 percent or less

12,019

11,223

+7.1

from other suppliers

130,196

111,812

+16.4

Total power procured(1)

271,278

254,313

+6.7

Power used for operating purposes, network losses and pump storage

(12,735

)

(10,239

)

+24.4

Total

258,543

244,074

+5.9


(1)	Excluding physically-settled electricity trading activities at E.ON Sales & Trading GmbH (“EST”). EST’s physically-settled electricity trading activities amounted to 113,666 million kWh and 110,914 million kWh in 2005 and 2004, respectively.

In 2005, E.ON Energie procured a total of 271.3 billion kWh of electricity, including 12.7 billion kWh used for operating purposes, network losses and pumped storage. E.ON Energie purchased a total of 12.0 billion kWh of power from power stations in which it has an interest of 50 percent or less. In addition, E.ON Energie purchased 130.2 billion kWh of electricity from other utilities, 23.5 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 32.7 billion kWh. The increase in purchased power compared to 2004 primarily reflects the purchase of significantly higher volumes of renewable source electricity which is regulated under Germany’s Renewable Energy Law as well as first-time consolidation effects (mainly in Bulgaria and Romania). Furthermore, short- and mid-term trading volumes increased. The increase in power used for operating purposes, network losses and pump storage is largely due to higher technical and non-technical network losses at the newly included subsidiaries in Bulgaria and Romania.

Following the abolition of separate geographic operating areas for utilities under the Energy Law (as defined in “— Regulatory Environment”) in 1998, E.ON Energie began to supply power nationwide and to broaden its activities in neighboring countries. E.ON Energie has thus significantly expanded beyond its traditional home markets, which include parts or all of the German states of Schleswig-Holstein, Lower Saxony, Hesse, North Rhine-Westphalia, Mecklenburg-Western Pomerania, Brandenburg, Saxony-Anhalt, Thuringia and Bavaria. E.ON Energie supplied approximately 18 percent of the electricity consumed by end users in Germany in 2005. Electricity accounted for 77.8 percent of E.ON Energie’s 2005 sales (2004: 78.8 percent), gas revenues represented 15.3 percent (2004: 14.4 percent), district heating 1.9 percent (2004: 2.0 percent) and other activities 5.0 percent (2004: 4.8 percent).

The following table sets forth data on the sales of E.ON Energie’s electric power in 2005 and 2004:

Total

2005

2004

million

Change in

Sale of Power(1) to

kWh

Total

Non-consolidated interregional, regional and municipal utilities

138,425

130,862

+5.8

Industrial and commercial customers

77,175

72,077

+7.1

Residential and small commercial customers

42,943

41,135

+4.4

Total

258,543

244,074

+5.9


(1)	Excluding physically-settled electricity trading activities at EST. EST’s physically-settled electricity trading activities amounted to 113,666 million KWh and 110,914 million kWh in 2005 and 2004, respectively.

The increase in the total sale of power primarily reflects higher sales of renewable source electricity which is regulated under Germany’s Renewable Energy Law as well as first time consolidation effects (mainly in Bulgaria and Romania). For further information, see “Item 5. Operating and Financial Review and Prospects — Results of Operations.” E.ON Energie’s total gas sales volume amounted to 112.3 billion kWh in 2005, a 9.1 percent increase from 102.9 billion kWh in 2004. The increase primarily reflects the first time consolidation of KÖGÁZ and DDGÁZ in Hungary and of NRE in the Netherlands. Additionally, the merger of TEAG and GVT resulted in higher sales volumes. Excluding the sales volumes from the newly included companies, gas sales decreased by 7.2 TWh. The decrease in sales volume was primarily weather-related (reflecting higher temperatures in winter 2005), as well as a result of increased competition in the business customer and the non-consolidated interregional, regional and municipal utilities segment.

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 34,000 MW, its attributable share of which is approximately 25,600 MW (not including mothballed, shutdown or reduced power plants). The German power generation business is subdivided into three units according to fuels used: E.ON Kraftwerke GmbH owns and operates the power stations using fossil fuel energy sources, as well as waste incineration plants and renewable generation facilities, E.ON Kernkraft GmbH (“E.ON Kernkraft”) owns and operates the nuclear power stations and E.ON Wasserkraft GmbH owns and operates the hydroelectric power 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 2005, it had a total installed generation capacity of approximately 1,870 MW.

Based on the consolidation principles under U.S. GAAP, 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 are accounted for by the equity method. Power generation capacity in jointly owned plants is generally reported based on E.ON’s ownership percentage.

The following table sets forth E.ON Energie’s major electric power generation facilities (including cogeneration plants) in Germany and the Netherlands, the total capacity and the capacity attributable to E.ON Energie for each facility as of December 31, 2005, and their start-up dates.

E.ON ENERGIE’S ELECTRIC POWER STATIONS IN GERMANY AND THE NETHERLANDS


				Capacity
				Attributable to
		Total		E.ON Energie
		Capacity						Start-up
Power Plants		Net MW		%(1)		MW		Date

Nuclear
Brokdorf			1,370		80.0		1,096		1986
Brunsbüttel			771		33.3		257		1976
Emsland			1,329		12.5		166		1988
Grafenrheinfeld			1,275		100.0		1,275		1981
Grohnde			1,360		83.3		1,133		1984
Gundremmingen B			1,284		25.0		321		1984
Gundremmingen C			1,288		25.0		322		1984
Isar 1			878		100.0		878		1977
Isar 2			1,400		75.0		1,050		1988
Krümmel			1,260		50.0		630		1983
Unterweser			1,345		100.0		1,345		1978

	Total		13,560				8,473

Lignite
Buschhaus			350		100.0		350		1985
Kassel			33		50.0		17		1988
Lippendorf S			891		50.0		446		1999
Schkopau			900		55.6		500		1995

	Total		2,174				1,313

Hard Coal
Bexbach 1			714		8.3		59		1983
Buer (CHP)			70		100.0		70		1985
Datteln 1			95		100.0		95		1964
Datteln 2			95		100.0		95		1964
Datteln 3			113		100.0		113		1969
Farge			345		100.0		345		1969
GKW Weser/ Veltheim 2			93		67.0		62		1965
GKW Weser/ Veltheim 3			303		67.0		203		1970
Heyden			865		100.0		865		1987
Kiel			323		50.0		162		1970
Knepper C			345		100.0		345		1971
Maasvlakte 1 (NL)(2)			532		100.0		532		1988
Maasvlakte 2 (NL)(2)			520		100.0		520		1987
Mehrum C			690		50.0		345		1979
Rostock			508		50.4		256		1994
Scholven B			345		100.0		345		1968


				Capacity
				Attributable to
		Total		E.ON Energie
		Capacity						Start-up
Power Plants		Net MW		%(1)		MW		Date

Hard Coal (continued)
Scholven C			345		100.0		345		1969
Scholven D			345		100.0		345		1970
Scholven E			345		100.0		345		1971
Scholven F			676		100.0		676		1979
Shamrock			132		100.0		132		1957
Staudinger 1			249		100.0		249		1965
Staudinger 3			293		100.0		293		1970
Staudinger 5			510		100.0		510		1992
Wilhelmshaven			747		100.0		747		1976
Zolling			449		100.0		449		1986

	Total		10,047				8,503

Natural Gas
Burghausen			120		100.0		120		2001
Emden GT			52		100.0		52		1972
Erfurt			80		27.8		22		—
Franken I/1			383		100.0		383		1973
Franken I/2			440		100.0		440		1976
Galileistraat (NL)			209		100.0		209		1988
Gendorf			40		50.0		20		2002
GKW Weser/ Veltheim 4 GT			400		74.0		296		1975
Grenzach-Wyhlen			40		69.9		28		2004
GT Ummeln			55		74.0		41		1973
Huntorf			290		100.0		290		1977
Irsching 3			415		100.0		415		1974
Jena-Süd			199		62.6		125		1996
Kirchlengern			180		62.9		113		1980
Kirchmöser			178		100.0		178		1994
Leiden (NL)			83		100.0		83		1986
Maasvlakte UCML (NL)			78		100.0		78		2004
Obernburg			100		50.0		50		1995
Robert Frank 4			487		100.0		487		1973
RoCa 3 (NL)(2)			220		100.0		220		1996
Staudinger 4			622		100.0		622		1977
The Hague (NL)			78		100.0		78		1982
Other (<40 MW installed capacity)			283		n/a		253		n/a

	Total		5,032				4,603

Fuel Oil
Audorf			87		100.0		87		1973
Hausham GT 1			25		100.0		25		1982
Hausham GT 2			25		100.0		25		1982


				Capacity
				Attributable to
		Total		E.ON Energie
		Capacity						Start-up
Power Plants		Net MW		%(1)		MW		Date

Fuel Oil (continued)
Hausham GT 3			25		100.0		25		1982
Hausham GT 4			25		100.0		25		1982
Ingolstadt 3			386		100.0		386		1973
Ingolstadt 4			386		100.0		386		1974
Itzehoe			88		100.0		88		1972
Wilhelmshaven			56		100.0		56		1973
Zolling GT 1			25		100.0		25		1976
Zolling GT 2			25		100.0		25		1976

	Total		1,153				1,153

Hydroelectric
Aufkirchen			27		100.0		27		1924
Bittenbrunn			20		100.0		20		1969
Bergheim			24		100.0		24		1970
Braunau-Simbach			100		50.0		50		1953
Egglfing			81		100.0		81		1944
Eitting			26		100.0		26		1925
Ering			73		100.0		73		1942
Erzhausen			220		100.0		220		1964
Feldkirchen			38		100.0		38		1970
Gars			25		100.0		25		1938
Geisling			25		100.0		25		1985
Happurg			160		100.0		160		1958
Hemfurth			20		100.0		20		1915
Jochenstein			132		50.0		66		1955
Kachlet			54		100.0		54		1927
Langenprozelten			164		100.0		164		1975
Neuötting			26		100.0		26		1951
Nußdorf			48		76.5		37		1982
Oberaudorf-Ebbs			60		50.0		30		1992
Passau-Ingling			86		50.0		43		1965
Pfrombach			22		100.0		22		1929
Reisach			105		100.0		105		1955
Rosenheim			35		100.0		35		1960
Roßhaupten			46		100.0		46		1954
Schärding-Neuhaus			96		50.0		48		1961
Stammham			23		100.0		23		1955
Straubing			22		100.0		22		1994
Tanzmühle			28		100.0		28		1959
Teufelsbruck			25		100.0		25		1938
Töging			85		100.0		85		1924
Vohburg			23		100.0		23		1992


				Capacity
				Attributable to
		Total		E.ON Energie
		Capacity						Start-up
Power Plants		Net MW		%(1)		MW		Date

Hydroelectric (continued)
Walchensee			124		100.0		124		1924
Waldeck 1			120		100.0		120		1931
Waldeck 2			440		100.0		440		1975
Wasserburg			24		100.0		24		1938
Other run-of-river, pump storage and storage			781		n/a		734		n/a

	Total		3,408				3,113

Others			537				333

Total			35,911				27.491

Mothballed/ Shutdown/ Reduced
Arzberg 5(3)			104		100.0		104		1966
Arzberg 6(3)			252		100.0		252		1974
Arzberg 7(3)			121		100.0		121		1979
Aschaffenburg 21(3)			150		100.0		150		1963
Aschaffenburg 31(3)			143		100.0		143		1971
Emden 4(4)			433		100.0		433		1972
Franken II/1(3)			206		100.0		206		1966
Franken II/2(3)			206		100.0		206		1967
Irsching 1			151		100.0		151		1969
Irsching 2			312		100.0		312		1972
Offleben(3)			280		100.0		280		1988
Pleinting 1			292		100.0		292		1968
Pleinting 2			402		100.0		402		1976
Rauxel 2(3)			164		100.0		164		1967
Scholven G(3)			672		50.0		336		1974
Scholven H(3)			672		50.0		336		1975
Schwandorf B(3)			99		100.0		99		1959
Schwandorf C(3)			99		100.0		99		1961
Schwandorf D(3)			292		100.0		292		1972
Stade(3)			640		66.7		417		1972
Staudinger 2			249		100.0		249		1965
Westerholt 1(3)			138		100.0		138		1959
Westerholt 2(3)			138		100.0		138		1961

	Total		6,215				5,320


(1)	Percentage of total capacity attributable to E.ON Energie.

(2)	Power station operated by E.ON Benelux under long-term cross-border leasing arrangement.

(3)	Dismantling in process or finished, respectively.

(4)	Recommissioned in January 2006.

(CHP) Combined Heat and Power Generation.

(NL) Located in the Netherlands.

For more information about E.ON Energie’s power generation facilities in eastern Europe, see “— Eastern Europe.”

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: Electricity”). Until June 30, 2005, E.ON Energie’s nuclear power plants delivered spent nuclear fuel elements to Cogema SA (“Cogema”) in France and British Nuclear Group Sellafield Ltd (“BNGS,” formerly British Nuclear Fuels plc. (“BNFL”)) in the United Kingdom for the reprocessing of their nuclear waste. Since June 30, 2005, German law has prohibited the delivery of spent nuclear fuel rods for reprocessing. Instead, operators must store spent fuel rods in interim facilities on the premises of the nuclear plants. For more details, see the description below under “Termination of Fuel Reprocessing.” Under German law, the Federal Republic of Germany is responsible for the final storage of all domestic nuclear waste at the expense of the generator.

Operators of nuclear power plants are required under German law to establish sufficient financial provisions for future obligations that arise from the use of nuclear power. The three required provisions are for: (1) management of spent nuclear fuel rods, (2) disposal of contaminated operating waste and (3) the eventual decommissioning of nuclear plants. At year-end 2005, E.ON Energie had a total of approximately €13.0 billion provided for these purposes in respect of nuclear power plants included in its consolidated accounts, consisting of €4.2 billion for management of spent nuclear fuel rods, €0.4 billion for disposal of operational waste and €8.4 billion for decommissioning costs. These provisions are stated net of advance payments of €0.9 billion. In determining its pro rata share of these provisions, provisions attributed to minority interests included in E.ON Energie’s consolidated accounts have been deducted and provisions for nuclear plants in which E.ON Energie has a minority interest are added. At year-end 2005, on such a pro rata basis, E.ON Energie’s provisions for these purposes totaled €13.5 billion, as compared to €13.6 billion at year-end 2004.

In June 2004, German legislators passed an amendment to Germany’s Ordinance on Advance Payments for the Establishment of Federal Facilities for Safe Custody and Final Storage for Radioactive Wastes (Endlager-Vorausleistungsverordnung). Under the amended ordinance, construction costs for the final nuclear waste storage facilities, located in Gorleben and Konrad, Germany, are now shared by the nuclear plant operators and other users, such as research institutes, in line with their expected actual usage of the storage facilities. Overall, this lowers E.ON’s share of the costs and has led to a reduction of the Company’s provisions for nuclear waste management. Partially offsetting this reduction, the post-operation phase at nuclear power stations that use MOX fuel elements, which are fuel elements containing plutonium produced in the reprocessing process, was extended beginning in 2004 as a result of a change in the delivery schedule for MOX fuel elements.

E.ON Kernkraft purchases uranium and fuel elements for its nuclear power plants from independent 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 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. E.ON Energie received the approval for decommissioning/dismantling in September 2005. Stade was shut

down in November 2003, and E.ON Energie expects its decommissioning to last approximately 10 to 12 years. E.ON Energie has established a provision of €1.9 billion for the decommissioning of Würgassen and Stade, including the management of spent nuclear fuel rods and the dismantling of the plants.

After the German Social Democratic Party and the German Green Party (Bündnis 90/ Die Grünen) (together, the “Coalition”) were elected to lead the German federal government in 1998, the Coalition agreed to phase out the generation of nuclear energy in Germany. The Coalition also agreed to hold “consensus-forming” discussions with operators of nuclear power plants in order to find a solution to various issues in the area of nuclear energy agreeable to all parties. The discussions began in January 1999 and resulted in an agreement on nuclear power in June 2001 and in an amendment of the German Nuclear Power Regulations Act (Atomgesetz, or “AtG”), which was passed by the German parliament in December 2001 and took effect in April 2002.

Among other things, the amendment 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 allotted kWh among themselves. This means that if one nuclear plant closes before it has produced the allotted 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. The Company is currently constructing five interim on-site storage facilities, of which two are expected to go into operation in the first quarter of 2006, with the remaining three scheduled to be ready between November 2006 and February 2007. For the period from July 2005 until storage can begin in the interim storage facilities, the Company is storing the spent fuel elements at the plants in so-called in-plant fuel pools. The Company expects the capacity of these fuel pools to be sufficient to store the spent fuel elements until the storage facilities go into operation. E.ON has delivered all spent fuel elements under its reprocessing contracts with Cogema and BNGS.

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.

In March 1999, the German parliament passed the Tax Relief Act 1999/2000/2002 (Steuerentlastungsgesetz 1999/2000/2002, the “Tax Relief Act”). The Tax Relief Act contains new rules for the tax treatment of nuclear provisions. Furthermore, the German tax authorities have adopted a more stringent interpretation of the previous law with respect to the years before 1999. The changes to the tax status of the provisions include the following:


	•	The accrual period for decommissioning costs has been extended from 19 to 25 years. This requires E.ON Energie to release a portion of the provisions it had previously established for tax purposes based on the shorter accrual period.

	•	Certain parts of the provisions concerning MOX fuel elements have to be reversed. The costs must be capitalized as incurred instead.

	•	Those portions of the provisions that have been established in past years relating to the financing and operational costs for final storage of nuclear waste have been disallowed. The costs of these items will now be tax-deductible when they are actually expensed.

	•	In accordance with the new general rule for long-term provisions, all types of provisions for nuclear power must now be discounted. The Tax Relief Act sets the discount rate at 5.5 percent. This also applies


		to provisions that have previously been established, which must be released to the extent they do not reflect this discounting.

The Tax Relief Act provides that the tax payments resulting from the reversal of provisions necessitated by the extension of the accrual period, the disallowance of portions of the provisions related to costs of final storage of waste and the discounting of the provisions are spread over a period of ten years beginning in 1999.

In 2002, the Company concluded its general discussions with the tax authorities regarding the treatment of the years prior to 1999, and the tax calculations for these years have been agreed in principle. All of the resulting tax has already been paid and the Company has established a provision to cover the remaining amounts. The years from 1999 onwards are still under review.

None of the changes to the tax treatment of nuclear provisions described above cause any changes to the financial statements the Company prepares for other purposes. Due to the recognition of a related deferred tax asset generated by temporary differences between the balance sheet prepared for financial reporting purposes and the balance sheet for tax purposes, the changes in the tax status of the provisions for nuclear waste disposal had no material adverse effect on the Company’s consolidated net income in 1999. However, the Tax Reduction Act (Steuersenkungsgesetz), which was enacted in October 2000, included a lowering of the corporate income tax from 40 percent to 25 percent, which has resulted in a reduction of the deferred tax asset relating to the provisions.

Hard Coal. In 2005, approximately 40 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 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. In 2005, incinerated waste volumes totaled approximately 2.1 million tons. The power plants have a total capacity of 193 MW of electricity, of which 133 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 (for example, in 2005 the breakdown of generators in the non-nuclear part of the Unterweser power plant and in the coal-fired Heyden power plant resulted in the plants being out of service for 12 and 8 weeks, respectively). In addition, the summer heat wave in Europe in 2003 reduced the availability of electric generating facilities dependent on using river water for cooling purposes. 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 system length of over 42,000 km and a coverage area of nearly 200,000 km². It is located in the German states of Schleswig-Holstein, Lower Saxony, Mecklenburg-Western Pomerania, Brandenburg, North Rhine-Westphalia, Saxony-Anhalt, Hesse, Thuringia and Bavaria, and reaches from the Scandinavian border to the Alps. The grid is interconnected with the western European power grid with links to the Netherlands, Austria, Denmark and Eastern Europe. The system is mainly operated by E.ON Netz GmbH (“E.ON Netz”). The network of E.ON Netz allows long-distance power transport at low transmission losses and covers more than 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 Karlsfeld near Munich, and from several regional control and service units at decentralized locations within the E.ON Netz grid area.

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, see “— Regulatory Environment — Germany: Electricity.”

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

Distribution and Sale

In Germany E.ON Energie supplies electricity, gas and heat, mainly through the regional electricity distribution companies in which it holds majority interests. In addition to the trading business described below, EST supplies electricity to these regional electricity distribution companies as well as to large municipal distributors and very large national and international industrial customers.

Electricity. The German utilities historically established defined supply areas which were coextensive with their distribution grids. See “— Operations.” The following map shows E.ON Energie’s current supply area in Germany through its majority shareholdings in regional electricity distribution companies:

E.ON Energie’s customers are interregional, regional and municipal utilities, traders, industrial and commercial customers and, only through regional distributors, residential and small commercial customers predominantly in those parts of Germany highlighted on the above map. E.ON Energie supplied approximately 18 percent of the electricity consumed by end users in Germany in 2005. In compliance with the EU Commission’s conditions upon approving the VEBA-VIAG merger, E.ON Energie’s majority-owned regional distributors E.ON EDIS and ETE in eastern Germany purchase power from E.ON Energie’s competitor Vattenfall Europe. E.ON Energie’s majority-owned distributor E.ON Avacon likewise purchases its power primarily from Vattenfall Europe for those of its customers situated in the eastern German state of Saxony-Anhalt.

The following table sets forth the sale of E.ON Energie’s electric power (excluding that used in physically settling its trading activities) in Germany in 2005 and 2004:

Germany

2005

2004

million

Change

Sale of Power to

kWh

in Total

Non-consolidated interregional, regional and municipal utilities(1)

116,654

112,575

+3.6

Industrial and commercial customers(2)(3)

59,134

56,274

+5.1

Residential and small commercial customers

29,978

30,352

-1.2

Total(3)

205,766

199,201

+3.3


(1)	The sale of power to non-consolidated interregional, regional and municipal utilities increased in 2005 compared with 2004, reflecting increased sales of electricity produced from renewable resources.

(2)	The sale of power to industrial and commercial customers increased in 2005 compared with 2004, primarily due to additional customers acquired.

(3)	The sale of power includes sales of EST in other European countries.

In order to offer optimized services to major customers and to equalize supply and demand at all times with respect to the costs of procurement, E.ON Energie has integrated its trading and wholesale operations into EST. EST focuses on the national and international wholesale business for regional utilities, large municipal utilities and major industrial customers, and is also responsible for E.ON Energie’s trading operations. The regional distribution companies manage the main part of E.ON Energie’s retail business, which is the supply of power to municipal utilities, industrial and commercial customers, as well as residential and small commercial customers. The following chart sets forth the principal supply structure of E.ON Energie’s electricity sales.

The supply contracts under which E.ON Energie’s regional distributors (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. Long-term concession contracts permit municipal utilities and regional distributors to supply electricity to residential customers within a municipality.

Gas. E.ON Energie’s distribution subsidiaries supply natural gas to households, small businesses and industrial customers in many parts of Germany. E.ON Energie’s gas sales volume in Germany in 2005 amounted to 100.5 billion kWh compared with 102.9 billion kWh in 2004. Due to the acquisition of NRE, E.ON Energie also had a gas sales volume of 1.7 billion kWh in the Netherlands in 2005.

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 distributors are also involved in district heat and steam delivery. E.ON Energie’s total district heat deliveries in Western Europe in 2005 remained essentially stable at 13.0 billion kWh, of which 10.4 billion kWh were supplied in Germany. The remaining amount is mainly supplied through E.ON Benelux.

Water. Following the sale of its interest in Gelsenwasser AG (“Gelsenwasser”) in 2003, E.ON’s remaining regional water business is conducted through certain of its distribution companies, particularly E.ON Hanse, E.ON Avacon AG and E.ON Westfalen Weser.

Customers. Through its subsidiaries and companies in which it has shareholdings, E.ON Energie serves approximately 9.4 million electricity customers in Germany. E.ON Energie’s German operations also supply approximately 1.8 million customers with gas and more than 0.4 million customers with water.

In the Netherlands, E.ON Benelux acquired the Dutch power and gas company NRE in 2005. In 2004, the company supplied approximately 1.6 TWh of electricity and approximately 4.8 TWh of gas to approximately 0.3 million electricity and gas customers in the Netherlands.

In Italy, the sales activities of E.ON Energie are operated by its subsidiary E.ON Italia. E.ON Italia focuses on industrial customers and local utilities. Its sales volume amounted to approximately 995 million kWh in 2005.

Trading

E.ON Energie has integrated its trading and wholesale operations into EST. An international team of traders buys and sells electricity on the spot and forward markets. E.ON Energie’s trading operations offer customized and standard products that are traded on a bilateral basis, as well as trading in standard exchange-traded instruments. EST’s trading focuses on Germany and continental Europe, including the following European power exchanges: European Energy Exchange in Leipzig, the Amsterdam Power Exchange in the Netherlands, Powernext in France, Energy Exchange Austria, the Italian Power Exchange and Operátor trhu s elektrinou (OTE) in the Czech Republic. EST also supplies cross border trading and risk management processes for optimizing international power procurement to E.ON Energie’s operations in Eastern Europe and is the sole procurer for E.ON Energie’s operations in Italy. As the central trading desk of the E.ON Energie group, EST began CO₂ emissions trading activities in 2005. For information on CO₂ emissions trading, see “— Regulatory Environment — EU/ Germany: General Aspects (Electricity and Gas) — Greenhouse Gas Emissions Trading.” The volume of CO₂ emission certificates traded by EST amounted to 8.7 million tons in 2005.

E.ON Energie believes that its trading activities provide valuable market insight and have strengthened its competitive position in the European electricity market. E.ON Energie’s trading activities are focused on asset-backed trading in order to optimize the value of its generation portfolio, though E.ON Energie also engages in a limited amount of proprietary trading within its established risk limits.

E.ON Energie’s trading business has incorporated a complete and systematic risk management system in compliance with legal and regulatory requirements of the German Federal Supervisory Office for Banking, including the minimum requirements for trading activities of credit institutions. An important aspect of the system is that the trading activities are monitored by a board independent from the trading operations. For more detailed information on E.ON Energie’s management of the risks related to its trading activities, see “Item 11. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk Management.”

The volume of EST’s energy trading activities increased in 2005, reflecting higher price volatility in the power markets. See “Item 5. Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 — Central Europe.” The following table sets forth the total volume of EST’s traded electric power in 2005 and 2004.

2005

2004

million

Change

Trading of Power

kWh

in Total

Power sold

164,109

146,755

+11.8

Power purchased

168,734

162,671

+3.7

Total

332,843

309,426

+7.6

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 and managerial support to promote the efficient use of electricity and gas. E.ON Facility

Management GmbH (“E.ON Facility Management”) provides technical, commercial and infrastructural facility management services, mainly for E.ON Energie group companies. In November 2005, E.ON Energie acquired an additional 49.0 percent stake in E.ON Facility Management, which is now wholly-owned, from HSG Technischer Service GmbH. 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. The E.ON Group acquired the remaining 25.2 percent shareholding as of January 1, 2005. Since then, E.ON IS has been consolidated in the Group, with E.ON Energie holding a 60.0 percent stake, E.ON AG holding a 26.0 percent stake and E.ON Ruhrgas holding the remaining 14.0 percent stake.

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 (“BKW”), an integrated Swiss utility that owns important hydropower 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 which it has already built up a portfolio of activities. National holding companies such as E.ON Hungária Energetikai ZRt. (“E.ON Hungária”), E.ON Czech Holding AG and E.ON Bulgaria EAD coordinate E.ON Energie’s activities.

In Hungary, E.ON Energie holds all of the shares (except for a “golden share” held by the Hungarian government) of the regional electricity distributors E.ON Dél-dunántúli Áramszolgáltató Rt., E.ON Észak-dunántúli Áramszolgáltató Rt. (“ÉDÁSZ”) and E.ON Tiszántúli Áramszolgáltató Rt. In 2005, these companies provided 2.4 million customers with approximately 14.4 TWh of electricity. In January 2003, E.ON Hungária founded E.ON Energiakereskedö Kft., an electricity and gas sales company, to serve the liberalized Hungarian electricity market. E.ON Energie also holds a 100.0 percent stake in the natural gas power generation company Debreceni Kombinált Ciklusú Erömü Kft. (95 MW). In the gas sector, E.ON Energie holds a 98.1 percent stake in the gas distribution and supply company KÖGÁZ, a 50.01 percent stake in the gas distributor DDGÁZ and a 16.3 percent stake in the gas company FÖGÁZ. KÖGÁZ and DDGÁZ have been fully consolidated since April 2005. In 2005, the two companies provided approximately 0.6 million customers with approximately 17.3 TWh of gas. In February 2006, E.ON Energie and RWE signed an agreement to swap certain of their respective shareholdings in Hungary and the Czech Republic, subject to antitrust and other regulatory approvals. Under the proposed swap, E.ON Energie would acquire almost all of the remaining shares of DDGÁZ and RWE would acquire E.ON Energie’s interest in FÖGÁZ.

In the Czech Republic, E.ON Energie controls significant participations in the energy sector. As of January 1, 2005, E.ON Energie re-organized its former subsidiaries Jihomoravská energetika a.s. (“JME”) and Jihoceská energetika a.s (“JCE”) and fulfilled legal unbundling requirements by creating three new wholly-owned subsidiaries, E.ON Ceská republika, a.s., E.ON Distribuce, a.s. and E.ON Energie, a.s., and transferring the businesses of JME and JCE to these subsidiaries. On a combined basis, these companies provided approximately 1.4 million customers with approximately 12.2 TWh of electricity in 2005. In the gas sector, E.ON Energie owns minority shareholdings in the distributors JMP, Jihoceska plynárenska a.s. (“JCP”), PP, STP, SMP, ZCP and VCP. Under the proposed swap of shareholdings with RWE noted above, E.ON Energie would increase its interest in JCP to 59.8 percent and acquire additional shares in PP. RWE would acquire E.ON Energie’s interests in STP, SMP, ZCP and VCP.

In February 2005, E.ON Energie acquired 67.0 percent stakes in each of the two northeastern Bulgarian electricity distribution companies Varna and Gorna Oryahovitza. The companies had combined sales of approximately 4.9 TWh and served approximately 1.1 million customers in 2005.

In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution company Electrica Moldova — now renamed E.ON Moldova — and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. In 2004, the company sold approximately 4.3 TWh of electricity to approximately 1.3 million customers.

In 2002, E.ON Energie entered the Slovakian energy market by acquiring a 49.0 percent interest in the Slovakian electricity supplier Západoslovenská energetika a.s. (“ZSE”), which provided approximately 1.0 million customers with approximately 7.1 TWh of electricity in 2004.

In the Baltic region, following the re-organization of the Lithuanian energy industry, E.ON Energie now owns a 20.3 percent interest in Rytu Skirstomieji Tinklai (“RST”), the eastern Lithuanian electricity distribution company. E.ON Energie has an agreement with the Lithuanian government to sell its interest in RST to the new majority shareholder should RST be completely privatized.

In addition, as of December 31, 2005 E.ON Energie held a number of shareholdings in small generation assets, primarily in Hungary and the Czech Republic.

E.ON Energie does not have interests in companies operating nuclear power plants other than those in Germany and Switzerland.

Competitive Environment

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 2005 (602 TWh at the European Energy Exchange’s Spot and Futures Market compared with 397 TWh in 2004). 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 Electricity Association, VDEW, in 2005 prices paid by household customers were about 9 percent higher than in the liberalization year 1998, while prices (including electricity tax) paid by industrial customers were still about 5 percent lower than in 1998. In 2005, wholesale electricity prices in Germany rose sharply due to rising CO₂ emission certificate prices and a dry and hot summer. Some industrial customers were affected by the high wholesale prices, but others had already procured a lower price in 2004 or earlier. For this reason, the wholesale price increase did not affect the industrial customer segment to the same degree as household customers.

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 Law and Co-Generation Protection Law, as well as higher costs incurred in procuring balancing power to cover

fluctuations in the availability of electricity from renewable resources such as wind. As most distributors have tried to pass these increases through to their customers, electricity prices have risen more rapidly than the associated margins for generators in recent years. Taxes and duties accounted for approximately 40 percent of German electricity prices for household customers in 2005, 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 21 percent in 2005. In view of recent developments in the commodity and fuel markets, E.ON Energie expects electricity prices in Germany to further increase in 2006. E.ON Energie cannot exclude further price hikes for end customers in 2006, which in most cases have to be approved by the relevant authorities. However, these price changes for end customers depend on the wholesale market prices for electricity. For information about court proceedings on price increases affecting some of E.ON Energie’s majority-owned regional distribution companies, see “Item 3. Key Information — Risk Factors — External.”

High environmental and nuclear safety standards, as well as high investments in new lignite power plants, taxes on electricity, the requirements of the Co-Generation Protection Law and the Renewable Energy Law’s requirement 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. Any of these or other factors could materially and adversely affect E.ON’s financial condition and results of operations. See also “Item 3. Key Information — Risk Factors.”

Outside Germany, the energy markets in which E.ON Energie operates are also subject to strong competition. E.ON Energie cannot guarantee it will be able to compete successfully in electricity markets where it already is present or in new electricity 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 2005, the Pan-European Gas market unit recorded revenues of €17.9 billion (which included €3.1 billion in natural gas and electricity taxes that were remitted, directly or indirectly, to the German tax authorities) and adjusted EBIT of €1.5 billion. €14.2 billion of the Pan-European Gas market unit’s 2005 revenues were generated in Germany and €3.7 billion was generated abroad (measured by location of customer).

In 2005, E.ON Ruhrgas entered into the following significant transactions:


	•	In November 2004, ERI signed an agreement for the acquisition of 75.0 percent minus one share each of the gas trading and gas storage businesses of the Hungarian oil and gas company MOL and its 50.0 percent interest in the gas import subsidiary Panrusgáz. In addition, MOL received a put option to sell to ERI up to 75.0 percent minus one share of its gas transmission business and put options to sell to ERI the remaining 25.0 percent plus one share in the MOL gas trading and gas storage businesses. As a condition of antitrust approval by the EU commission, MOL is obliged to sell the remaining 25.0 percent plus one share of the gas trading and storage businesses as well. As a result, ERI signed an agreement for the acquisition of the remaining 25.0 percent plus one share of each of the two companies. These transactions are expected to be completed at the end of March 2006.

	•	In June 2005, after clearance was obtained from the relevant authorities, E.ON Ruhrgas acquired a 51.0 percent stake in the Romanian gas supplier Distrigaz Nord from the Romanian government. Distrigaz Nord is active in gas distribution and supply in northern Romania.


	•	In June 2005, E.ON Ruhrgas signed an agreement for the sale of Ruhrgas Industries to CVC Capital Partners.

	•	In September 2005, E.ON Ruhrgas Norge AS (“E.ON Ruhrgas Norge”) acquired an additional 15.0 percent stake in the Njord oil and gas field from the British oil and gas company Paladin Resources plc. and now owns a 30.0 percent stake in this field.

	•	In September 2005, Gazprom, BASF and E.ON signed a “basic agreement” on the construction of the NEGP.

	•	In November 2005, E.ON Ruhrgas acquired Caledonia, a U.K. gas production company with interests in a total of 15 gas fields in the U.K. southern North Sea, from First Reserve, CSFB Private Equity Funds and others. Apart from its stakes in gas fields, Caledonia wholly owns Caledonia Energy Trading Limited (“CETL”) and has interests in two pipeline systems near the gas fields for transporting gas to the United Kingdom.

	•	In the course of 2005, E.ON Ruhrgas UK Exploration and Production Limited (“E.ON Ruhrgas UK”) acquired a further 13.59 percent stake in Interconnector (U.K.) Limited (“Interconnector”) from BP plc. (“BP”) (4.0 percent), International Power plc (“International Power”) (3.38 percent) and Amerada Hess Corporation (“Amerada Hess”) (6.21 percent). E.ON Ruhrgas UK now holds a total interest of 23.59 percent in this company.

For information about additional transactions in the downstream business, see “— Downstream Shareholdings.”

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, in a limited amount of trading activities;

Transmission:		The transmission of gas within Germany via a network of approximately 11,000 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 regional and supraregional distributors, municipal utilities and industrial customers, as well as the delivery of gas 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 ERI and Thüga. ERI holds primarily minority shareholdings in European integrated and regional gas distribution companies and in German regional gas distribution companies, while Thüga holds primarily minority shareholdings in about 100 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 and one Italian municipal utility.

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.

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 2005 and 2004. The difference between gas supplies and gas sales in any given period is due to storage and metering differences and occurs routinely.


		Total 2005				Total 2004
Purchases		billion kWh		%		billion kWh		%

Imports			580.0		84.5		537.4		83.2
German sources			106.1		15.5		108.6		16.8

	Total		686.1		100.0		646.0		100.0


Sales

Domestic distributors		323.7	46.9	328.7	51.2
Domestic municipal utilities		160.9	23.3	156.1	24.3
Domestic industrial customers		70.4	10.2	69.0	10.8
Sales abroad		135.2	19.6	87.6	13.7

	Total	690.2	100.0	641.4	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 2005 is mainly attributable to an increase in sales abroad, especially to customers in the United Kingdom (including E.ON UK); the sales increase was reflected in an increase in imports. For more information on E.ON Ruhrgas’ gas supply contract with E.ON UK, see “— History and Development of the Company — Ruhrgas Acquisition” and “— U.K. — Energy Wholesale — Energy Trading.”

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 2005, E.ON Ruhrgas purchased a total of 686.1 billion kWh of gas, of which approximately 84.5 percent was imported and approximately 15.5 percent was purchased from German producers. E.ON Ruhrgas was the largest gas purchaser in Germany in 2005, acquiring more than half of the total volume of gas purchased for the German market. Of the 686.1 billion kWh of gas purchased in 2005, E.ON Ruhrgas bought approximately 28.2 percent from Russia and approximately 27.5 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 2005 and 2004:


		Total 2005				Total 2004
Sources of Gas		billion kWh		%		billion kWh		%

Germany			106.1		15.5		108.6		16.8
Russia			193.5		28.2		201.3		31.2
Norway			188.4		27.5		169.6		26.3
The Netherlands			139.0		20.2		124.1		19.2
United Kingdom			34.1		5.0		22.8		3.5
Denmark			23.7		3.4		19.3		3.0
Others(1)			1.3		0.2		0.3		0.0

	Total		686.1		100.0		646.0		100.0


(1)	Italy and France.

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 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 2005; 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 2006 to 2029 (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 10 trillion kWh of natural gas over the period to 2029. 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 2005. 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 “Item 5. 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. The economic significance of such contracts has been acknowledged by the German government and, in principle, by the EU Commission, and E.ON Ruhrgas seeks to balance its purchase and sale obligations so as to minimize risk. For information about risks relating to long-term gas supply contracts, see “Item 3. Key Information — Risk Factors.”

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

Russia. In 2005, E.ON Ruhrgas purchased 193.5 billion kWh of gas, or 28.2 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, 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 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 5.6 trillion kWh of gas in 2005. 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. E.ON Ruhrgas and Gazprom may enter into new gas supply contracts in the future which will provide a contractual basis for this arrangement. 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 signed a basic agreement on the construction of the NEGP in September 2005. For details, see “— Transmission and Storage — Pipelines.”

In addition, E.ON Ruhrgas is a member of a consortium that holds a minority interest in Slovenský plynárenský priemysel a.s. (“SPP”), the operator of the gas transmission system in Slovakia through which most Russian gas bound for western Europe is transported.

Norway. In 2005, E.ON Ruhrgas purchased 188.4 billion kWh, or 27.5 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 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 2005, E.ON Ruhrgas purchased 139.0 billion kWh, or 20.2 percent of its total gas purchased, pursuant to a single long-term supply contract with N.V. Nederlandse Gasunie. 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 of E.ON Ruhrgas’ imports, 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 2005, E.ON Ruhrgas purchased 106.1 billion kWh, or 15.5 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 former BEB), Shell Erdgas Marketing GmbH & Co. KG (50 percent of former BEB), Gaz de France Produktion Exploration Deutschland GmbH (formerly Preussag Energie GmbH) and RWE Dea AG. A number 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 2005, E.ON Ruhrgas purchased 34.1 billion kWh, or 5.0 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, which has interests in U.K. gas fields and infrastructure. See “— Trading — 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 partly at Zeebrugge in Belgium. Gas from the U.K. gas fields is transported to Belgium through the undersea gas pipeline run by the project company Interconnector. During 2005, E.ON Ruhrgas UK acquired a further 13.59 percent stake in Interconnector and now holds a total interest of 23.59 percent. In order to transport the gas to Germany, E.ON Ruhrgas has long-term transportation contracts for the transmission of the gas through the Belgian pipeline system to the gas import point at Raeren near Aachen on the German-Belgian border.

Denmark. In 2005, E.ON Ruhrgas purchased 23.7 billion kWh, or 3.4 percent of its total gas purchased, from the Danish supplier DONG Naturgas 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.

Trading

In order to optimize and manage price risks of its long-term gas portfolio, E.ON Ruhrgas engages 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 and at the Title Transfer Facility in the Netherlands, and are mainly handled via brokers participating in open markets. Financial, oil and coal trading activities are undertaken mainly for hedging purposes. Proprietary trading is marginal compared to asset-based trading.

E.ON Ruhrgas’ total traded gas volume for 2005 was 5.9 percent of total E.ON Ruhrgas sales, as compared with 4.9 percent in 2004, 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 “Item 11. 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 holds mainly minority interests in a number of gas production fields, exploration blocks and pipelines in the British North Sea. In November 2005, E.ON Ruhrgas completed the acquisition of Caledonia, which owns interests in 15 gas fields and two pipeline systems (as well as a trading business). Caledonia was renamed E.ON Ruhrgas UK North Sea Limited (“E.ON Ruhrgas North Sea”) in November 2005.

In 2005, E.ON Ruhrgas UK produced 4.5 billion kWh (406 million cubic meters (“m³”)) of gas, compared with 4.0 billion kWh (353 million m³) of gas in 2004. In 2005, this gas came from the Elgin/ Franklin fields, in which E.ON Ruhrgas UK holds a 5.2 percent interest, and from the Scoter field, in which E.ON Ruhrgas UK holds a 12.0 percent interest and which had its first year of full production in 2005. In addition, E.ON Ruhrgas UK produced 2.5 million barrels of liquids (oil and condensate) in 2005, which were sold on the market. Start of production from the Elgin/ Franklin satellite fields Glenelg and West Franklin (in which E.ON Ruhrgas UK holds interests of 18.57 percent and 5.2 percent, respectively) has been deferred to 2006 and 2007, respectively. In the last two months of 2005, E.ON Ruhrgas North Sea produced an aggregate of 0.8 billion kWh of gas (73 million m³) from the former Caledonia gas fields Johnston (interest 50.107 percent), Ravenspurn North (interest 28.75 percent), Caister (interest 40.0 percent) and Schooner (interest 4.83 percent).

Norway. E.ON Ruhrgas operates in Norway through its subsidiary E.ON Ruhrgas Norge. E.ON Ruhrgas Norge completed the acquisition of a further 15.0 percent stake in the Njord oil and gas field in the Norwegian Shelf area of the North Sea in September 2005 and now owns 30.0 percent of this field. Currently, gas from this field is being re-injected to increase the rate of oil recovery. E.ON Ruhrgas Norge obtained 2.3 million barrels of oil as a result of its stake in 2005 which were sold on the market. The field is currently expected to begin producing gas for sale in 2007.

Russia. In July 2004, E.ON and Gazprom signed a Memorandum of Understanding for a deepened strategic cooperation between the parties, including gas production in Russia.

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. E.ON is currently conducting a feasibility study on the construction of an LNG unloading and regasification terminal in Wilhelmshaven which would be Germany’s first such facility. E.ON Ruhrgas has a majority shareholding in Deutsche Flüssigerdgas Terminal Gesellschaft mbH, which owns property to build the terminal in Wilhelmshaven, which, if built, could handle upon completion as much as 5 billion m³ of natural gas per year and would have the flexibility to handle another 5 billion m³ if required. According to initial calculations, the investments required would total

approximately €500 million. No decision to build the terminal has yet been made, though its construction would be in line with E.ON’s strategy of expanding its sources of natural gas with the goal of enhancing the security of its supply.

Transmission and Storage

E.ON Ruhrgas’ technical infrastructure 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, those co-owned directly by E.ON Ruhrgas and other gas companies, and those owned by project companies in which E.ON Ruhrgas holds an interest.

Project companies are entities E.ON Ruhrgas 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 share in each of its German project companies as of December 31, 2005:


	E.ON
	Ruhrgas Share
Project Company	%

DEUDAN (DEUDAN — Deutsch/ Dänische Erdgastransport-Gesellschaft mbH & Co. KG)		25.0
EGL (Etzel Gas-Lager GmbH & Co. KG)		74.8
GHG (GHG-Gasspeicher Hannover Gesellschaft mbH)		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 underground storage facilities are operated by E.ON Ruhrgas as storage system operator. The E.ON Ruhrgas transmission system is operated by E.ON Ruhrgas Transport, a wholly-owned subsidiary of E.ON Ruhrgas, as transmission system operator. The underground storage facilities and the transmission system are monitored and maintained largely by E.ON Ruhrgas. 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 fulfillment of one of the requirements of the ministerial approval authorizing E.ON’s acquisition of Ruhrgas and in accordance with Germany’s new energy law, the transmission system has been leased out to E.ON Ruhrgas Transport together with all transmission rights and rights of beneficial use that E.ON Ruhrgas possesses in respect of third party transmission systems in Germany. For more information on Germany’s new energy law, see “— Regulatory Environment — EU/ Germany: General Aspects (Electricity and Gas).” For more information on E.ON Ruhrgas Transport, see “— E.ON Ruhrgas Transport” 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’ technical infrastructure:

E.ON Ruhrgas Technical Infrastructure

As shown in the map above, the E.ON Ruhrgas 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 2005, E.ON Ruhrgas owned gas pipelines totaling 6,449 km and co-owned gas pipelines totaling 1,550 km with other companies. In addition, German project companies in which E.ON Ruhrgas holds an interest owned gas pipelines totaling 3,274 km at the end of 2005.

The following table provides more information on E.ON Ruhrgas’ pipelines in Germany as of December 31, 2005:


				Maintained
		Total		by E.ON Ruhrgas
Pipelines		km		km

Owned by E.ON Ruhrgas			6,449		6,177
Co-owned pipelines			1,550		604
DEUDAN (PC)			110		0
EGL (PC)			67		67
MEGAL (PC)			1,080		1,080
METG (PC)			425		425
NETG (PC)			285		144
NETRA (PC)			341		106
TENP (PC)			966		966
Companies in which E.ON Ruhrgas holds a stake through its subsidiaries ERI and Thüga			—		2,046
Owned by third parties			—		1,075

	Total in Germany		11,273		12,690


(PC)	project company

E.ON Ruhrgas’ 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’ interest in the pipeline. E.ON Ruhrgas’ 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 2,021 km of pipelines with a diameter of less than or equal to 300 millimeters, 3,030 km of pipelines with a diameter of more than 300 and less than or equal to 600 millimeters, 2,917 km of pipelines with a diameter of more than 600 and less than or equal to 900 millimeters, and 3,305 km of pipelines with a diameter of more than 900 and less than or equal to 1,200 millimeters.

In 2005, E.ON Ruhrgas maintained 6,177 km of its own pipelines, 604 km of co-owned pipelines, 1,075 km of pipelines owned by third parties and 2,046 km of pipelines owned by companies in which E.ON Ruhrgas holds a stake through its subsidiaries ERI and Thüga, as well as 2,788 km of pipelines owned by project companies in which E.ON Ruhrgas holds an interest. In total, E.ON Ruhrgas maintained (including providing local monitoring) 12,690 km of pipelines in 2005. For information on pipeline monitoring and maintenance, see “— Monitoring and Maintenance” below.

In addition to its 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 112 MW) and a compressor station at Zeebrugge (two units with a total installed capacity of approximately 70 MW).

In July 2004, E.ON Ruhrgas acquired a 20.0 percent interest in BBL Company V.O.F., a Dutch project company founded in July 2004, which is building a second undersea transmission system between continental Europe and the United Kingdom. Construction on this transmission system, which is expected to link Balgzand in the Netherlands to Bacton in the United Kingdom, began in December 2004.

E.ON Ruhrgas also owns a 3.0 percent interest in the Swiss project company Transitgas AG, which owns the Transitgas transmission system, running through Switzerland from Wallbach on the Swiss-German border and Rodersdorf on the French-Swiss border to Griespass on the Swiss-Italian border. The Transitgas system comprises pipelines totaling 293 km and one transport compressor station at Ruswil (four units with a total installed capacity of approximately 60 MW).

In September 2005, E.ON, Gazprom and BASF signed a “basic agreement” on the construction of the NEGP, which is currently planned to connect Vyborg on Russia’s Baltic coast with Germany’s Baltic coast, thereby providing an alternative undersea route for the supply of Russian natural gas to Germany, as compared with the current land routes through Ukraine and Poland. As a first step, the three joint venture partners have formed a Swiss company, in which Gazprom holds a 51.0 percent interest and E.ON Ruhrgas and BASF’s subsidiary Wintershall each hold 24.5 percent stakes. Although work has started on connecting the current Russian gas infrastructure to the proposed landing site in Vyborg, no decision to build the pipeline has been taken and it is not expected that the pipeline could be completed before 2010 at the earliest. Gazprom is expected to decide to build the pipeline. E.ON Ruhrgas and Wintershall have only committed to join the feasibility study and have a right to step back and not join the construction depending on the result of the feasibility study. E.ON Ruhrgas’ initial investment in the joint-venture company was only CHF 245,000 (€158,900). However, current estimates put E.ON Ruhrgas’s share of the expected cost of the complete project, if built, at approximately €1 billion.

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 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 holds an interest own an additional 17 transport compressor stations with a total installed capacity of 537 MW and two storage compressor stations with a total installed capacity of 17 MW. In 2005, E.ON Ruhrgas provided monitoring and maintenance services under service contracts for the nine transport compressor stations leased out to E.ON Ruhrgas Transport and 13 transport compressor stations of the project companies. E.ON Ruhrgas 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 totals 853 MW.

The following table provides more information about E.ON Ruhrgas’ and its project companies’ gas compressor stations in Germany as of December 31, 2005:


										Installed Capacity
										of Compressor Units
								Compressor Units		Monitored and
						Total Installed		Monitored and		Maintained
		Compressor		Compressor		Capacity		Maintained by		by E.ON Ruhrgas
Owned by		Stations		Units		MW		E.ON Ruhrgas		MW

E.ON Ruhrgas (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		17		179		17		179
METG (PC) (transportation)			2		9		99		9		99
NETG (PC) (transportation)			2		5		50		2		20
NETRA (PC) (transportation)			2		5		42		3		20
TENP (PC) (transportation)			4		15		151		15		151

	Total in Germany		34		104		938		90		853


(PC)	project company

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 had sufficient pipeline capacity in prior years and booked sufficient pipeline capacity in 2005. E.ON Ruhrgas 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 gas sent out by E.ON Ruhrgas 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 injects gas into storage facilities during warm weather periods and withdraws it in cold weather periods to cope with peak demand. E.ON Ruhrgas 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 2005, E.ON Ruhrgas 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 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 5.1 billion m³ was available to E.ON Ruhrgas in 2005. 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 had sufficient storage capacity available both in 2005 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’ gas supply and delivery situation and further gas sales potential in the United Kingdom, E.ON Ruhrgas intends to increase working gas capacity by enlarging existing storage facilities, building new facilities and by leasing additional gas storage capacity in the future. For information about risks related to the reliability of gas supplies, see also “Item 3. Key Information —

Risk factors.” The following table provides more information about E.ON Ruhrgas’ underground gas storage facilities, all of which are situated in Germany, as of December 31, 2005:


					E.ON Ruhrgas’			E.ON Ruhrgas’
		E.ON Ruhrgas’			Share in			Share in
		Share in			Maximum			Storage Facility
		Working			Withdrawal			or in the			Operated by
		Capacity			Rate (thousand			Project Company			E.ON
Underground Storage Facilities		(million m³)			m³/hour)		Owned by	%			Ruhrgas

Bierwang(P)			1,300			1,200	E.ON Ruhrgas		100.0			Yes
Empelde(C)			18			39	GHG-Gasspeicher Hannover
							Gesellschaft mbH(PC)		13.2			—
Epe(C)			1,657			2,450	E.ON Ruhrgas		100.0			Yes
Eschenfelden(P)			48			87	E.ON Ruhrgas/N-ERGIE AG		66.7			Yes
Etzel(C)			383			987	Etzel Gas-Lager GmbH &
							Co. KG(PC)		74.8			—
Hähnlein(P)			80			100	E.ON Ruhrgas		100.0			Yes
Krummhörn(C)(1)			0			0	E.ON Ruhrgas		100.0			Yes
Sandhausen(P)			15			23	E.ON Ruhrgas/Gasversorgung
							Süddeutschland GmbH		50.0			Yes
Stockstadt(P)			135			135	E.ON Ruhrgas		100.0			Yes
Breitbrunn(P)			970	(2)		520	RWE Dea AG/ExxonMobil
							Gasspeicher Deutschland
							GmbH(3)/ E.ON Ruhrgas (4)		Leased	(3)		Yes	(4)
Inzenham-West(P)			500			300	RWE Dea AG		Leased			—

	Total		5,106			5,841


(C)	salt cavern


(P)		porous rock


(PC)	project company


(1)	Currently out of service for repairs/adjustments.

(2)	965 million m³ was contractually guaranteed in 2004/05; 970 million m³ is the current working gas capacity available to E.ON Ruhrgas.

(3)	Underground section.


(4)	Above ground part, particularly the storage compressor station.

Monitoring and Maintenance. In 2005, E.ON Ruhrgas carried out for itself and under service contracts for E.ON Ruhrgas Transport and some of the project companies E.ON Ruhrgas holds an interest in, monitoring and maintenance services for almost all of the E.ON Ruhrgas transmission system and its underground storage facilities.

Transmission system and underground storage monitoring operations are centered at E.ON Ruhrgas’ dispatching facility 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 2005, E.ON Ruhrgas performed this kind of system monitoring for about 12,600 km of pipelines, 22 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 field stations and facilities located along the network. E.ON Ruhrgas 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’ 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). 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 Ruhrgas Transport. On January 1, 2004, in fulfillment of one of the requirements of the ministerial approval authorizing E.ON’s acquisition of Ruhrgas, E.ON Ruhrgas transferred its gas transmission business to a new subsidiary, E.ON Ruhrgas Transport. E.ON Ruhrgas Transport has sole responsibility for the gas transmission business, including technical responsibility for the transmission system, and functions independently of E.ON Ruhrgas’ sales business, which is a customer of E.ON Ruhrgas Transport. As the transmission system operator, E.ON Ruhrgas Transport operates and controls the E.ON Ruhrgas transmission system and handles all major functions needed for an independent gas transmission business: transmission management, transportation contracts (including access fees), shipper relations, planning, controlling and billing. E.ON Ruhrgas Transport obtains certain support services from E.ON Ruhrgas AG under service agreements. In connection with the Energy Law of 2005, the scope of support services was reduced as follows during 2005: (1) as from September 1, 2005, E.ON Ruhrgas Transport’s employees handled all capacity planning and capacity allocation and (2) as from December 1, 2005, they handled the commercial transport operations.

On November 1, 2004, E.ON Ruhrgas Transport introduced an entry/exit system called ENTRIX for access to the E.ON Ruhrgas gas transmission system as a result of an agreement reached with the Competition Directorate-General of the European Commission (the “Competition Directorate”) 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 Ruhrgas Transport. The fee structure is simple and applies to five zones into which the transmission system of E.ON Ruhrgas has been divided. The level of transmission fees is determined by reference to European markets and pipeline and transport competition in Germany. Customers also benefit from the introduction of local exit zones within which they can use capacities flexibly. According to the agreement reached with the Competition Directorate, E.ON Ruhrgas has to reduce the number of fee zones to four in 2006, unless the company is able to demonstrate that technical, qualitative, economic or other reasons make such reduction of zones impossible.

In order to comply with requirements of the Energy Law of 2005 (described in “— Regulatory Environment”), further improvements of the E.ON Ruhrgas Transport 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 five zones of the E.ON Ruhrgas transmission network, so 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 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.

Sales

Germany. E.ON Ruhrgas was the largest distributor of natural gas in Germany in 2005, selling a total volume of 555 billion kWh of gas. E.ON Ruhrgas also sold 135.2 billion kWh of gas outside of Germany in 2005. The following map illustrates the sales area of E.ON Ruhrgas in Germany:

E.ON Ruhrgas sells gas to regional and supraregional distributors, municipal utilities and industrial customers. The following table sets forth information on the sale of gas by E.ON Ruhrgas’ sales business in Germany for the periods presented:


		Total 2005				Total 2004
Sale of Gas to:		billion kWh		%		billion kWh		%

Distributors			323.7		58.3		328.7		59.3
Municipal utilities			160.9		29.0		156.1		28.2
Industrial customers			70.4		12.7		69.0		12.5

	Total		555.0		100.0		553.8		100.0

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.

E.ON Ruhrgas’ sales contracts vary depending on the type of customer. The majority of E.ON Ruhrgas’ customers are distributors and municipal utilities. Most of these contracts are long-term contracts. In many cases, especially concerning municipal utilities, E.ON Ruhrgas has offered rights to reduce the contractual amounts by October 1, 2006 or 2007 combined with an early termination by October 1, 2008 (see “— Competitive Environment”). Price terms in all types of supply 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.

Two requirements of the ministerial approval approving E.ON’s acquisition of E.ON Ruhrgas related to gas sales contracts. The option of reducing the volume of gas that was granted to most distributors and municipal utilities for the remaining term of the relevant contract was in most cases not exercised for the gas years ending September 30, 2005 or 2006. Exercising this option will remain possible until these contracts end. The second requirement of the ministerial approval, obliging E.ON Ruhrgas to grant two larger regional distributor customers in which E.ON Ruhrgas previously held an interest the right to a staged termination of their contracts, has become obsolete as these companies have signed new contracts with E.ON Ruhrgas.

In 2005, gas prices in Germany continued to rise, due primarily to the rise in the price of oil. E.ON Ruhrgas has in certain cases responded to competitive pressure by re-negotiating the terms of sales contracts with major customers. See also “— Competitive Environment.”

International. In 2005, E.ON Ruhrgas delivered 135.2 billion kWh of gas to customers in other European countries, or 19.6 percent of the total volume of gas sold by E.ON Ruhrgas, compared with 87.6 billion kWh or 13.7 percent in the period from January to December 2004. The destinations for E.ON Ruhrgas’ external sales are the United Kingdom, Switzerland, the Benelux countries, Austria, Hungary, Luxembourg, Italy, France, Denmark, Sweden, Poland and Liechtenstein. The 54.3 percent increase in international sales in 2005 was largely attributable to long-term supply contracts with E.ON UK (starting in October 2004) and E.ON Sverige (starting in October 2005). However, E.ON Ruhrgas’ sales to other international customers are increasingly made on the basis of short-term contracts. Limitations on available gas transportation capacity across the relevant borders may restrict E.ON Ruhrgas’ ability to expand its external sales business to certain countries. See also “— U.K. — Energy Wholesale — Energy Trading” and “— Nordic — Gas Distribution.”

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 primarily minority shareholdings in European integrated and regional gas distribution companies and in German regional gas distribution companies, while Thüga holds primarily minority shareholdings in about 100 regional and municipal utilities in Germany. In addition, Thüga’s main international shareholdings, most of which are held through its wholly owned Italian subsidiary Thüga Italia S.r.l. (“Thüga Italia”), are its majority shareholdings in five Italian gas distribution companies and one sales company, as well as two minority shareholdings in other Italian energy companies, including one municipal utility.

ERI: As of December 31, 2005, ERI’s portfolio of shareholdings included primarily minority stakes in three domestic and 17 foreign companies. In 2005, ERI (including its fully consolidated shareholdings) contributed sales of €891.9 million (approximately 6.0 percent of E.ON Ruhrgas’ total sales, excluding natural gas and electricity taxes) and had sales volumes of 46.5 billion kWh in 2005 (2004: 30.1 billion kWh).

In March 2006, ERI expects to acquire shareholdings in certain businesses of the Hungarian gas company MOL. For details, see “— Overview.”

Germany. As of December 31, 2005, ERI held interests in the following regional gas distribution companies:


	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.

International. As of December 31, 2005, ERI held interests in the following operating companies in countries outside of Germany, primarily in central Europe and the Nordic region:


	Share held
	by ERI
Shareholding	%

Gasnor AS, Norway		14.00
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
therminvest Sp.z o.o., Poland(1)		100.00
Inwestycyjna Spolka Energetyczna Sp.z o.o. (IRB), Poland		50.00
Szczencinska Energetyka Cieplna Sp.z o.o. (SECS), Poland(1)		32.13
EUROPGAS a.s., Czech Republic(2)		50.00
Colonia-Cluj-Napoca-Energie S.R.L. (CCNE), Romania		33.33
E.ON Ruhrgas Mittel- und Osteuropa GmbH(3)		100.00
Nafta a.s., Slovakia		40.27
S.C. Congaz S.A., Romania		28.59
Ekopur d.o.o., Slovenia(4)		100.00
SOTEG — Société de Transport de Gaz S.A., Luxembourg		20.00
Holdigaz SA, Switzerland		2.21


(1)	The shareholdings in these companies are expected to be transferred to E.DIS energia sp.z o.o. of the Central Europe market unit in 2006.

(2)	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.

(3)	E.ON Ruhrgas Mittel- und Osteuropa GmbH has an indirect interest of 24.50 percent in SPP, Slovakia.

(4)	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: Thüga holds primarily minority shareholdings in about 100 regional and municipal utilities in Germany. In addition, Thüga’s main international shareholdings, most of which are held through its wholly owned Italian subsidiary Thüga Italia, are its majority shareholdings in five Italian gas distribution companies and one sales company, as well as two minority shareholdings in other Italian energy companies, including one

municipal utility. Through its majority and minority shareholdings in Italian gas distribution and sales companies, Thüga supplied natural gas to approximately 750,000 end customers in Italy in 2005, primarily in the regions of Lombardy, Emilia Romagna, Veneto, Friuli Venezia-Giulia and Piedmont. With respect to its minority shareholdings, Thüga is an active shareholder, offering operational competence as well as other services. In 2005, Thüga contributed sales of €956.1 million (approximately 6.5 percent of E.ON Ruhrgas’ total sales, excluding natural gas and electricity taxes). Thüga increased its gas sales volumes by 7.7 percent to 22.5 billion kWh in 2005 from 20.9 billion kWh in 2004, primarily as a result of changes in the scope of consolidation of the Italian business.

As of December 31, 2005, E.ON Ruhrgas Thüga Holding GmbH held 81.1 percent of Thüga and E.ON Energie, through its subsidiary Contigas, held the remaining 18.9 percent.

Among other acquisitions in 2005, in July Thüga acquired an additional 21.2 percent of HEAG Südhessische Energie AG (HSE) from ERI.

Germany. As of December 31, 2005, Thüga held interests in operating companies which are primarily municipal utilities. The top ten shareholdings in terms of total sales in 2005 are as follows:


	Share held
	by Thüga
Shareholding	%

Stadtwerke Hannover Aktiengesellschaft		24.00
N-ERGIE Aktiengesellschaft		39.80
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. As of December 31, 2005, Thüga held 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 20 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 to a more limited extent, 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 2005, approximately 48 percent of German homes were heated using gas, making gas the leading energy source for this market. In 2005, gas was chosen as the heating method for approximately 75 percent of new homes under construction.

The German gas market has always been characterized by competition. Approximately 15 independent companies are active in the regional and supraregional distribution of gas. Competition has increased since the early 1990s, when Wingas entered the gas transmission market by building its own pipeline infrastructure. Wingas’ pipeline network currently has a length of more than 2,000 km, compared with the E.ON Ruhrgas pipeline network length of over 11,000 km. The market entry of Wingas has led to increased price competition not only in areas close to the Wingas system, but all over Germany. Since 2000, when the first association agreement was signed, third party access has developed dynamically. Since July 2005, access to German gas networks has been governed by a new legal framework which is set forth in the Energy Law of 2005. For information on this new legal framework, see “— Regulatory Environment.”

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, Shell and ExxonMobil as successors of the former BEB sales division, Verbundnetz Gas AG (“VNG”) and Wingas, while foreign competitors include Gaz de France, BP Energie, Econgas, Ecoswitch, Essent and Nuon. E.ON Ruhrgas currently enjoys a strong market position, supplying approximately 56 percent of all gas consumed in Germany in 2005. Nevertheless, E.ON Ruhrgas considers competition in the German gas market to be vigorous, 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 2005 by remaining flexible in its contract and price negotiations and by offering attractive terms and services to its established and potential customers. Due to likely increasing competition in the transmission business in Germany, however, E.ON Ruhrgas Transport may not be able to renew some of its existing transportation contracts when they expire, or to gain new contracts. This may have the effect of leaving E.ON Ruhrgas Transport with excess transmission capacity.

Gas prices in gas supply contracts are mostly linked to the price of competing fuels, primarily gas oil or heavy fuel oil. The prices for end consumers fluctuate according to oil price developments as well, thereby maintaining competitive prices compared to oil products independent of oil price level. 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. In 2005, global energy prices rose significantly, though natural gas prices rose less steeply than oil prices. Like other gas companies, E.ON Ruhrgas adjusted its sales prices in 2005 to reflect the higher price levels. In addition, rising oil prices led to further gas price increases as of the beginning of 2006, and more increases are expected in 2006 due to the price linkage between oil and gas. Recently there have been massive consumer complaints on rising gas prices. For information on investigations of gas prices charged by some German utilities, including utilities in which E.ON Ruhrgas and E.ON Energie hold interests, see “Item 3. Key Information — Risk Factors.”

In the context of the debate on long-term contracts, which the Federal Cartel Office (Bundeskartellamt) considers to be an obstacle to competition, E.ON Ruhrgas has offered those of its German distribution customers and municipal utilities that are supplied with more than 50 percent of their total gas requirements by E.ON Ruhrgas the termination of the existing contracts by October 1, 2008 in conjunction with a right to reduce their contractual amounts to 50 percent of their total gas purchases by either October 1, 2006 or October 1, 2007. Currently there is no indication as to how many customers will accept this offer. Sales contracts with distribution companies, where E.ON Ruhrgas supplies less than 50 percent of their total gas purchases, and with industrial customers are not affected. In connection with an agreement reached with the Competition Directorate-General of the European Commission, E.ON Ruhrgas also introduced an entry/exit system for third party access to its gas transmission system in November 2004. For details, see “— Transmission and Storage — E.ON Ruhrgas Transport.” In E.ON Ruhrgas’ opinion, these actions have had a considerable influence on the competitive environment in Germany. In addition, the Second Gas Directive and the Energy Law of 2005 are expected to further change competition in the gas industry. See “— Regulatory Environment.” E.ON Ruhrgas cannot

currently predict the form and extent of such changes, or whether these changes will have a negative effect on E.ON Ruhrgas’ ability to compete and results of operations. See also “Item 3. Key Information — Risk Factors.”

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, 2005, E.ON UK owned or through joint ventures had an attributable interest in 10,547 MW of generation capacity, including 577 MW of CHP plants and 233 MW of operational wind and hydroelectric generation capacity. E.ON UK served approximately 8.6 million electricity and gas customer accounts at December 31, 2005 and its Central Networks business served 4.9 million customer connections. The U.K. market unit recorded sales of €10.2 billion in 2005 and adjusted EBIT of €963 million.

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 businesses and engages in gas trading. The company served approximately 8.6 million customer accounts at December 31, 2005, including approximately 5.6 million electricity customer accounts, 2.8 million gas customer accounts and 0.1 million industrial and commercial electricity and gas customer accounts. With effect from July 2006, 0.1 million fixed line telephone customer accounts previously serviced by Powergen are expected to be sold to Telstra, which already manages these accounts. E.ON UK’s Central Networks distribution business served 4.9 million customer connections as of the end of 2005.

In the first half of 2005, E.ON UK acquired, in two tranches, 100 percent of the equity of Enfield Energy Centre Ltd. (“Enfield”) from NRG, El Paso and Indeck. Enfield operates a gas-fired power station near London. With an installed capacity of 392 MW, the power station can generate enough electricity for 300,000 homes. In July 2005, E.ON UK acquired Holford Gas Storage Limited (“HGSL”) from Scottish Power Energy Management Limited. HGSL was formed to develop one of the U.K.’s largest underground gas storage facilities in Cheshire in northwest England, a project for which it has already received planning approval.

The U.K. market unit comprises the non-regulated business, including energy wholesale (generation and energy trading) and retail, the regulated distribution business, and other activities, such as certain non-distribution assets and the E.ON UK corporate center. In 2005, electricity accounted for approximately 68 percent of E.ON UK’s sales, gas revenues accounted for approximately 32 percent and other activities accounted for less than 1 percent.

The following table sets forth the sources and sales channels of electric power in E.ON UK’s operations during each of 2005 and 2004:


		Total	Total
		2005	2004	%
Sources of Power		million kWh	million kWh	Change

Own production(1)		37,255	34,916	+6.7
Purchased power from power stations in which E.ON UK has an interest of 50 percent or less		627	2,047	-69.4
Power purchased from other suppliers(2)		39,224	47,087	-16.7
Power used for operating purposes, network losses and pump storage		(2,114)	(1,976)	+7.0

	Net power supplied(3)	74,992	82,074	-8.6


Sales of Power

Mass market sales (residential customers and small and medium sized enterprises)		37,314	36,189	+3.1
Industrial and commercial sales(4)		22,301	26,528	-15.9
Market sales(2)		15,377	19,357	-20.6

	Net power sold(3)	74,992	82,074	-8.6


(1)	The increase in own production in 2005 was primarily attributable to the fact that the Killingholme power plant was returned to service and the Enfield power station was acquired in 2005.

(2)	Power purchased from other suppliers and market sales decreased in 2005 compared with 2004 primarily due to lower sales to industrial and commercial customers and optimization decisions associated with E.ON UK’s hedging strategy.

(3)	Excluding proprietary trading volumes. For information on proprietary trading volumes, see “— Energy Wholesale — Energy Trading.”

(4)	During 2005, the industrial and commercial sales business continued to focus on securing profitable customers, which resulted in lower sales volumes in 2005 compared with 2004.

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	Total
		2005	2004	%
Sources of Gas		million kWh	million kWh	Change

Long-term gas supply contracts		48,431	49,494	-2.1
Market purchases		134,041	126,400	+6.0

	Total gas supplied(1)	182,472	175,894	+3.7


Sale and Use of Gas

Gas used for own generation		40,318	39,023	+3.3
Sales to industrial and commercial customers(2)		32,590	35,946	-9.3
Sales to retail mass market customers		67,671	66,221	+2.2
Market sales		41,893	34,704	+20.7

	Total gas used and sold(1)	182,472	175,894	+3.7


(1)	Excluding proprietary trading volumes. For information on proprietary trading volumes, see “— Energy Wholesale — Energy Trading.”


(2)	During 2005, the industrial and commercial sales business continued to focus on securing profitable customers, which resulted in lower sales volumes in 2005 compared with 2004.

Market Environment

E.ON UK primarily operates in the electricity generation, gas shipping, 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 between 1 to 2 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 following BETTA’s introduction which represents approximately 10 percent of the electricity market in Great Britain as a whole.

The combined pressure of overcapacity, an increasingly fragmented generation market and the introduction of NETA led to significant downward pressure on wholesale electricity prices in the period from 1999 through 2002, creating difficult trading conditions for many companies. The largest electricity generator in the United Kingdom, British Energy, required a government loan to continue operating and a number of generators were placed into administration.

However, since April 2003, increasing generation fuel costs, security of supply concerns and expected future environmental costs (including the introduction of CO₂ emission certificates) have combined to push up wholesale electricity prices for forward delivery substantially. Baseload prices for 2006 delivery increased from approximately GBP29 per MWh in January 2005 up to GBP52 per MWh in December 2005. Short-term electricity prices exhibited significant volatility during 2005 due mainly to volatile fuel input prices. In response to these increases in wholesale prices, U.K. suppliers, including E.ON UK, increased their retail electricity prices a number of times during 2005, as explained in more detail in “Retail” below.

Natural Gas. Wholesale gas prices in the United Kingdom increased in absolute terms and were more volatile during 2005, driven by higher oil prices and supply and demand imbalances in the United Kingdom and continental Europe. Annual prices for 2006 delivery increased from approximately 32 pence per therm in January 2005 to 62 pence per therm in December 2005. Although E.ON UK purchases gas on both U.K. and international trading markets, management partially mitigated these price increases by secured forward purchases to cover most of its requirements in 2005, switched fuel sources used by certain of its generating assets and increased retail prices. As noted above, E.ON UK and all of its main competitors either increased or announced increases in retail customer prices during 2005.

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 17.8 million customer accounts. E.ON UK is the second largest energy retailer with approximately 8.6 million accounts, followed by Scottish and Southern Electricity with approximately 6.4 million accounts. The market is characterized by substantial levels of customers switching suppliers in any given year; approximately half of the customers in the United Kingdom have now switched either their gas or electricity supplier since market liberalization. However, churn levels, which measure the percentage of customers switching suppliers, have fallen since 2002 as the market has matured. E.ON UK reduced its annual churn rate from 15.4 percent in 2004 to 14.7 percent in 2005.

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 required 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, 2005 until March 31, 2006, the renewables obligation is equal to 5.5 percent, rising to a figure of 15.4 percent by 2015/2016, at which point it is to remain stable until 2026/27. 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 United Kingdom implemented the EU Emissions Trading Directive at the beginning of 2005. The scheme requires companies to have CO₂ emission certificates in an amount equal to the CO₂ emissions made by their fossil fuel-fired power plants with a thermal input of more than 20 MW. During 2005, the U.K. government made an initial allocation of certificates for the first phase of the scheme (2005 to 2007) to owners of generating facilities, with the total number of certificates being issued equal to less than 90 percent of emissions levels in recent years. As a result, E.ON UK had to buy 4.7 million tons of additional allowances in 2005.

	•	The application in the United Kingdom of the EU Large Combustion Plant Directive may prevent coal- and oil-powered generation facilities that have not been fitted with specified sulphur oxide and nitrous oxide 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.”

Non-regulated Business

Energy Wholesale

During 2004, E.ON UK’s power generation and energy trading businesses were merged into a single business called “Energy Wholesale.” This change was 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 the fuel burned in power stations that are managed by the generation business. The energy trading business also decides whether E.ON UK should generate or purchase electricity to cover its retail obligations, depending upon the prevailing market price of electricity. However, 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, 2005, E.ON UK owned either wholly, or through joint ventures, power stations in the United Kingdom with an attributable registered generating capacity of 10,547 MW, including 577 MW of CHP plants and 50 MW of hydroelectric plant, while its

attributable portfolio of operational wind capacity stood at 183 MW. The increase in E.ON UK’s generation capacity during the year reflected the return to service of the Killingholme plant and the purchase of the Enfield plant, offset in part by the return of the Speke CHP plant to the former client at the end of the contract as described below. Despite the increase, E.ON UK’s share of the generation market in Great Britain remained relatively stable in 2005, at approximately 10 percent.

E.ON UK generates electricity from a diverse portfolio of fuel sources. In 2005, approximately 56 percent of E.ON UK’s electricity output was fuelled by coal and approximately 42 percent by gas, of which approximately eight percent was from CHP schemes, with the remaining two 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. This flexibility was demonstrated during 2005, when E.ON UK shut down two oil-fired units at Grain for the summer, and then returned these two units for winter use later in the year. Both CCGT modules at Killingholme were also returned to service at full capacity during 2005, the first time a CCGT plant had been returned to service after being mothballed in the U.K. Both actions were in response to increasing market prices which made the resumed operation of both plants economically attractive.

The following table sets forth details about E.ON UK’s electric power generation facilities in the United Kingdom, including their total capacity, the stake held by E.ON UK and the capacity attributable to E.ON UK for each facility as of December 31, 2005, as well as their start-up dates:

E.ON UK ELECTRIC POWER STATIONS


				E.ON UK’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Hard Coal
Ironbridge U1(1)			485		100.0		485		1970
Ironbridge U2(1)			485		100.0		485		1970
Kingsnorth U1(1)			485		100.0		485		1970
Kingsnorth U2(1)			485		100.0		485		1971
Kingsnorth U3(1)			485		100.0		485		1972
Kingsnorth U4(1)			485		100.0		485		1973
Ratcliffe U1(1)(2)			500		100.0		500		1968
Ratcliffe U2(1)(2)			500		100.0		500		1969
Ratcliffe U3(1)(2)			500		100.0		500		1969
Ratcliffe U4(1)(2)			500		100.0		500		1970

	Total		4,910				4,910

Natural Gas
Cottam Development Centre (CDC) Module			400		100.0		400		1999
Connahs Quay U1			345		100.0		345		1996
Connahs Quay U2			345		100.0		345		1996
Connahs Quay U3			345		100.0		345		1996
Connahs Quay U4			345		100.0		345		1996
Corby Module			401		50.0		200		1993
Enfield			392		100.0		392		2002
Killingholme Mod 1			450		100.0		450		1992
Killingholme Mod 2			450		100.0		450		1993

	Total		3,473				3,272

Oil
Grain U1			650		100.0		650		1982
Grain U4			650		100.0		650		1984

	Total		1,300				1,300


				E.ON UK’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Other (including hydroelectric and wind farms)
Grain Aux GT1			28		100.0		28		1979
Grain Aux GT4			27		100.0		27		1980
Kingsnorth Aux GT1			17		100.0		17		1967
Kingsnorth Aux GT4			17		100.0		17		1968
Ratcliffe Aux GT2			17		100.0		17		1967
Ratcliffe Aux GT4			17		100.0		17		1968
Taylors Lane GT2			68		100.0		68		1981
Taylors Lane GT3			64		100.0		64		1979
Hydroelectric			50		100.0		50		1962
Wind farms			197		various		183		various

	Total		502				488

CHP schemes			577		100.0		577		various

Total Capacity			10,762				10,547


(1)	Biomass material co-fired during 2005.

(2)	In June 2005, Ratcliffe-on-Soar power station successfully completed an 18-month trial to co-fire petcoke, a mixture of coal and gas. The trial was required by the U.K. Environmental Agency before permission could be given to move to commercial scale co-firing. A report on the trial has been submitted to the Environmental Agency, together with an application to move to commercial scale co-firing, and a decision is expected in 2006.

In addition, E.ON UK owns Edenderry Power Limited (“Edenderry”), which operates a 120 MW peat-fired plant in the Republic of Ireland. 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).

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’s wind generation projects are developed by E.ON UK Renewables Holdings Limited (“E.ON UK Renewables”). E.ON UK is already one of the leading developers and owner/operators of wind farms in the United Kingdom, with interests in 20 operational onshore and offshore wind farms with total capacity of 197 MW, of which 183 MW is attributable to E.ON UK.

During 2004, E.ON UK completed construction of a large offshore wind farm site with a capacity of approximately 60 MW at Scroby Sands off the coast of East Anglia. The Scroby Sands project builds on E.ON UK’s success in commissioning the U.K.’s first offshore wind farm at Blyth during 2001. Potential onshore and offshore projects with an aggregate capacity of approximately 1,100 MW are now in the development phase (compared with 770 MW in the development phase in 2004).

In addition to the planned expansion of its wind farm portfolio, E.ON UK increased its generation from biomass in 2005 by co-firing with coal at the Kingsnorth, Ironbridge and Ratcliffe power stations, generating a total of 230 GWh of renewable energy by this method during the year. Work has also commenced on the construction of a 44 MW wood-burning plant in Lockerbie, in southwest Scotland, which when built will be the United Kingdom’s largest dedicated biomass plant. The start of commercial operation of the plant is planned for December 2007.

During 2006, E.ON UK expects to develop its capability in marine generation (using tidal 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 ROC contracts and direct payment of any residual obligation into the buy-out fund. For the period from April 1, 2004 to March 31, 2005, E.ON UK achieved the 4.9 percent target under the renewables obligation scheme described above.

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, 2005 was 577 MW. Clients range across a number of sectors, including pharmaceuticals, chemicals, paper and oil refining. CHP capacity declined by 10 MW in 2005 due to the scheduled termination of the 10 year contract for the Speke CHP plant with Eli Lilly and Company Limited in November 2005. Under the terms of the contract, the asset was transferred back to the owner upon termination.

Energy Trading

E.ON UK’s energy trading unit engages in asset-based energy marketing 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 plays 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.

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);

	•	Trading of weather derivatives, which assist in hedging volume variability in E.ON UK’s retail business; 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 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 2005 and 2004:


	2005		2004		2005		2004
	Electricity		Electricity		Gas		Gas
Proprietary Trading Volumes	billion kWh(1)		billion kWh		billion kWh(1)		billion kWh

Energy bought		10.4		20.9		36.2		86.55
Energy sold		10.4		20.9		36.2		86.55

Gross volume		20.8		41.8		72.4		173.1


(1)	The reduction in traded gas and electricity volumes in 2005 was primarily attributable to higher market prices, which reduced the volume of trading E.ON UK could conduct within the risk limits established by the Corporate Center.

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 “Item 11. 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 “Item 5. 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, 2005, E.ON UK supplied approximately 8.6 million customer accounts, of which 7.9 million were residential customer accounts and 0.7 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 0.2 million as some customers switched suppliers in the wake of retail price increases described below. 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 7.9 million customer accounts as of December 31, 2005. Approximately 66 percent of E.ON UK’s residential customer accounts are electricity customers and 34 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 28.4 TWh of electricity and 54.1 TWh of gas in 2005, as compared with 29.2 TWh of electricity and 51.5 TWh of gas in 2004.

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 under its Powergen brand. E.ON UK also seeks to continue to exploit the high level of national awareness of its Powergen brand and has taken steps to enhance the strength of its brand, including the sponsorship of high profile, national sports competitions such as the Powergen Cups in Rugby Union and Rugby League. E.ON UK is also the main sponsor for Ipswich Town, a soccer team playing in the English Championship league.

In an environment of rising wholesale energy prices and increasing environmental costs, E.ON UK, like other suppliers, implemented a number of electricity and gas price increases affecting residential users in 2005 and the first quarter of 2006, though the precise level of increases varied by supplier. E.ON UK’s increases in 2005 amounted to 7.2 percent for electricity and 11.9 percent for gas, while those in the first quarter of 2006 amounted to 18.4 percent for electricity and 24.4 percent for gas. At the same time, E.ON UK has also implemented a package of measures to limit the effects of rising wholesale costs on its most vulnerable customers, including free cavity wall insulation for customers aged 60 or over and offering free energy saving

light bulbs to all its residential customers in 2005. These initiatives contribute to the requirements placed on suppliers in relation to the Energy Efficiency Obligations described in “— Regulatory Environment.”

Small and Medium-Sized Business and Industrial and Commercial Customers. The number of accounts in this sector totaled approximately 0.7 million at year-end 2005. In this sector, E.ON UK sold 31.3 TWh of electricity and 46.1 TWh of gas in 2005, as compared with 33.5 TWh of electricity and 50.6 TWh of gas in 2004. E.ON UK’s focus in this area remains on acquiring and retaining the most profitable contracts available.

In June 2005, E.ON UK acquired 100 percent of Economy Power Ltd., which supplies 45,000 small and medium-sized business customers with electricity.

Other

E.ON UK brought together three separate businesses, metering, new connections and home installation, during November 2005 to form E.ON Energy Services, 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. E.ON Energy Services employs more than 2,300 people and manages over 2,000 contractors. Each year, E.ON Energy Services staff is expected to visit more than 12 million households and carry out work in 600,000 homes. The new energy services business was a part of both Central Networks and Retail during 2005. This business will be reported within the non-regulated segment beginning in 2006.

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.”

E.ON UK’s Central Networks business manages the distribution businesses formerly operated by East Midlands Electricity Distribution plc (“EME”) and Midlands Electricity. 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 areas (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

2005

2004

Distribution of Power to

million kWh

Change

Large non-domestic customers

26,129

26,610

-1.8

Domestic and small non-domestic customers

31,287

30,583

+2.3

Total

57,416

57,193

+0.4

Distribution customers are billed on the basis of published tariffs, which are set by the company and adhere to Ofgem’s price control formulas. New 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 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 stake is a 31.0 percent interest in Trakya Electric Uretin ve Ticaret A.S., which owns and operates a 478 MW 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 E.ON Energy Services business, but has closed or sold the non-core parts of the contracting business.

NORDIC

Overview

E.ON Nordic’s principal business is the generation, distribution, marketing, sale and trading of electricity, gas and heat, mainly in Sweden and Finland. In 2005, it operated through the two integrated energy companies in which it held majority stakes, E.ON Sverige (formerly Sydkraft), the second-largest Swedish utility (on the basis of electricity sales and production capacity), and E.ON Finland. E.ON Nordic and its associated companies are actively involved in the ownership and operation of power generation facilities. As of December 31, 2005, E.ON Nordic owned, through E.ON Sverige and E.ON Finland, interests in power stations with a total installed capacity of approximately 14,982 MW, of which its attributable share was approximately 7,570 MW (not including mothballed and shutdown power plants). On February 2, 2006, E.ON agreed to sell its entire interest in E.ON Finland to the Finnish utility Fortum. See “E.ON Finland” below.

In 2005, electricity accounted for approximately 70 percent of E.ON Nordic’s sales, heat revenues accounted for approximately 15 percent, gas revenues accounted for approximately 7 percent and other activities accounted for approximately 8 percent. In 2005, E.ON Nordic had total sales of €3.5 billion (including €402 million of energy taxes) and adjusted EBIT of €806 million. E.ON Sverige accounted for €3.2 billion or approximately 92 percent of this sales total, while E.ON Finland accounted for the remaining €269 million or approximately 8 percent of E.ON Nordic’s sales.

E.ON Sverige. E.ON Nordic is the largest shareholder in E.ON Sverige with a 55.3 percent equity and a 56.7 percent voting interest. Statkraft, the other shareholder in E.ON Sverige, has a put option allowing it to sell any or all of its 44.6 percent equity interest in E.ON Sverige to E.ON Energie at any time through December 15, 2007.

E.ON Sverige is active in the generation, distribution, marketing and sale of electricity. In 2005, it had a total installed generation capacity of 7,374 MW and generated 33,272 million kWh of electricity. E.ON Sverige generated about 50 percent of its electric power at nuclear power plants and about 46 percent at hydroelectric plants in 2005. The remaining 4 percent was generated using fuel oil, biomass, natural gas, wind power and waste. E.ON Sverige also supplies gas, is active in the heat and waste business and conducts electricity trading activities. In 2005, E.ON Sverige had sales of €3.2 billion. Electricity contributed approximately 71 percent, heat 14 percent, gas 8 percent and other 7 percent of 2005 sales. Other sales are mainly attributable to the waste business, as well as the company’s other activities ElektroSandberg AB and E.ON Sverige Bredband AB. E.ON Sverige traded a total of approximately 73 TWh of electricity in 2005 (including both purchases and sales). E.ON Sverige is primarily active in Sweden. The company also operates to a minor degree in Finland, Denmark and Poland. In 2005, E.ON Sverige estimated that it supplied about 14 percent of the electricity consumed by end users in Sweden.

In 2003, E.ON Sverige acquired a majority stake in the Swedish utility Graninge. The stake was gradually increased to a 100 percent shareholding in the first half of 2004. As of the end of 2005, all of Graninge’s Swedish activities had been fully integrated into E.ON Sverige’s operations and are now carried out under the E.ON Sverige brand. This has resulted in cost savings net of integration costs in 2005. In September 2004, E.ON agreed further details regarding its agreement in principle with the Norwegian energy company Statkraft to sell a portion

(1.6 TWh) of the generation capacity that E.ON Sverige had acquired as part of the Graninge acquisition to its minority shareholder Statkraft. This corresponds to approximately 5 percent of E.ON Sverige’s annual electricity production, and approximately 50 percent of the capacity it acquired with the majority stake in Graninge. In July 2005, E.ON Sverige and Statkraft signed the corresponding agreement, whereby Statkraft would acquire a total of 24 hydroelectric power plants. In accordance with the agreement, Statkraft took ownership of the plants in October 2005.

On January 8 and 9, 2005, a severe storm hit Sweden and devastated large areas of forest in southern Sweden. This had a serious effect on the distribution grid, which in some areas was destroyed. Approximately 420,000 households in Sweden, including approximately 250,000 E.ON Sverige customers, were affected by power outages. Some customers, including E.ON Sverige customers, were left without electricity for several weeks. E.ON Sverige recorded related costs for rebuilding its distribution grid and compensating customers of approximately €140 million in 2005.

Sydkraft changed its legal name to E.ON Sverige on September 16, 2005. The Company believes that the rebranding to E.ON Sverige positively affects E.ON Nordic’s retail operations and that rebranding allows for more efficient Group brand management.

E.ON Finland. E.ON Nordic also holds a majority shareholding in E.ON Finland (formerly Espoon Sähkö Oyj). In 2005, E.ON Nordic was the largest shareholder in E.ON Finland with a 65.6 percent stake. The city of Espoo, the former majority shareholder in E.ON Finland, retains a 34.2 percent stake and the remaining 0.2 percent of E.ON Finland, which is listed on the Helsinki Stock Exchange, is held by other shareholders. In September 2001, when E.ON Nordic acquired its shareholding in E.ON Finland, E.ON Nordic and the city of Espoo entered into a shareholders’ agreement, which contains restrictions regarding the transfer of shares in E.ON Finland. In April 2002, E.ON Nordic entered into a call option agreement, in which Fortum was granted a call option in relation to E.ON Nordic’s entire shareholding in E.ON Finland; the call option was eligible for exercise in the first quarter of 2005, but any sale remained subject to certain legal restrictions pursuant to the shareholders’ agreement with the city of Espoo. In January 2005, E.ON Nordic received notice from Fortum that Fortum wished to exercise its call option. E.ON Nordic then notified Fortum that E.ON Nordic was not in a position to transfer its shares to Fortum due to statements of the city of Espoo based on the restrictions as contained in the shareholders’ agreement. In February 2005, Fortum filed a request for arbitration seeking to enforce its call option. On January 16, 2006, the city of Espoo decided to sell its shares in E.ON Finland to Fortum and to approve E.ON Nordic transferring its shares in E.ON Finland to Fortum. On February 2, 2006, E.ON Nordic and Fortum signed an agreement, whereby Fortum will acquire E.ON Nordic’s entire 65.6 percent stake in E.ON Finland for a price of €37.12 per share, corresponding to a total of approximately €380 million. E.ON Nordic currently expects to record an estimated book gain of approximately €25 million on the sale, which is subject to the approval of the Finnish competition authorities. When the transaction is formally completed, the companies will simultaneously terminate the arbitration proceedings related to the transfer of E.ON Finland shares. In conjunction with the acquisition, E.ON and Fortum agreed that Fortum will pay an additional amount of €16 million to E.ON.

E.ON Finland is active in the generation, distribution, marketing and sale of electricity and heat, as well as the supply of gas in Finland, primarily in the Espoo region near Helsinki and in the Joensuu region. In 2005, it had a total installed generation capacity of 196 MW and generated 981 million kWh of electricity. E.ON Finland generated about 36 percent of its electric power at coal-fired power plants and about 35 percent at gas-fired plants in 2005. The remaining 29 percent was generated using biomass and hydroelectric plants. In 2005, E.ON Finland had sales of €269 million. Electricity contributed approximately 62 percent, heat 36 percent, and other 2 percent of 2005 sales. E.ON Finland also has an electricity trading business and traded a total of approximately 36 TWh of electricity in 2005 (including both purchases and sales).

In 2005, E.ON Finland estimated that it supplied about 7 percent of the electricity consumed by end users in Finland.

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, retail and trading.

The following table sets forth the sources and sales channels of electric power in E.ON Nordic’s operations during each of 2005 and 2004:


		Total 2005	Total 2004	%
Sources of Power		million kWh	million kWh	Change

Own generation		34,253	33,110	+3.5
Purchased power from jointly owned power stations		10,398	11,030	-5.7
Power purchased from outside sources		5,921	7,376	-19.7

Total power procured(1)		50,572	51,516	-1.8
Power used for operating purposes, network losses and pump storage		(2,001)	(2,054)	-2.6

	Total	48,571	49,462	-1.8


Sales of Power

Residential customers		8,500	9,132	-6.9
Commercial customers		13,830	14,454	-4.3
Sales partners(2)/ Nordpool		26,241	25,876	+1.4

	Total(1)	48,571	49,462	-1.8


(1)	Excluding physically-settled electricity trading activities. Nordic’s physically-settled electricity trading activities (including both purchases and sales) amounted to approximately 44 million kWh in each of 2005 and 2004.

(2)	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 2005, E.ON Nordic procured a total of 50,572 kWh of electricity, including 2,001 kWh used for operating purposes, network losses and pumped storage. E.ON Nordic purchased a total of 10,398 kWh of power from power stations in which it has an interest of 50 percent or less. In addition, E.ON Nordic purchased 5,921 kWh of electricity from other sources, mainly from the Nordpool power exchange. In 2005, own generation volumes increased by approximately 2.1 billion kWh in existing operations, primarily as a result of the higher levels of rainfall during the year. This was partially offset by a decline in nuclear power production of approximately 0.9 billion kWh due to the very high availability in 2004. Sales to residential and commercial customers decreased by approximately 1.3 billon kWh in 2005, mainly due to the January storm and continued strong competition. These negative effects were offset in part by the increase in hydroelectric production, which allowed E.ON Nordic to sell additional power on the Nordpool energy exchange. See “Item 5. Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 — Nordic.”

In 2005, E.ON Nordic supplied approximately 6 percent of the electricity consumed by end users in the Nordic countries.

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 2005 and 2004:


		Total 2005		Total 2004		%
Sources of Gas		million kWh		million kWh		Change

Long-term gas supply contracts			9,310		9,252		+0.6
Market purchases			281		402		-30.1

	Total gas supplied		9,591		9,654		-0.7


Sale and Use of Gas

Gas used for own generation		2,624	2,539	+3.4
Sales to industrial and distribution customers		6,729	6,963	-3.4
Sales to residential customers		238	152	+56.6
Market sales		0	0	—

	Total gas used and sold	9,591	9,654	-0.7

E.ON Sverige purchases gas under long-term gas supply contracts with natural gas importers. Up to November 1, 2004, E.ON Sverige had a long-term contract with Nova Naturgas AB (“Nova Naturgas”) for the supply of natural gas. As of November 1, 2004, the contract was transferred to DONG, as a consequence of DONG’s acquisition of the supply business of Nova Naturgas. The contract with DONG terminated at the end of September 2005, at which time E.ON Ruhrgas became the sole supplier of natural gas to E.ON Sverige 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, though it will provide E.ON Sverige 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 markets in Sweden and Finland have undergone major and far-reaching changes since the mid-1990s. Electricity market reforms have been instituted in both countries with the goal of increasing efficiency and keeping electricity prices low. 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 Swedish main transmission network, started operating in 1992. The networks were gradually opened to new participants, and legislation providing for competition became effective January 1, 1996. Finland instituted market competition beginning June 1, 1995. In 1997, Finland merged the grid operations of its two companies into a single national grid company, Fingrid.

Today, the key feature of the Swedish and Finnish electricity markets 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. In order to make competition in generation and retail sales possible, 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 Sweden, Finland, Norway and Denmark (the “Nordic countries”) is a liquid and transparent commodity market with trading taking place through the Nordic electricity exchange Nordpool. The market participants at Nordpool include power generators, distributors, industrial companies, other end users and portfolio managers. The electricity exchange markets consist of a spot market (delivery in the next 24-hour period), a financial market (contracts of up to four years for longer term

hedging) and clearing operations. The current volume of electricity traded at the Nordpool spot market exchange is equal to more than 40 percent of underlying consumption in the Nordic countries. As a result, pricing in the Nordic market has become increasingly efficient, with reduced 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 basis for sales contracts with end customers.

The electricity supply system in the Nordic countries is highly dependent on the hydro power systems in Norway and Sweden. The inflow of water in the two countries is generally well correlated, i.e. low inflow in Norway usually coincides with a low inflow in Sweden. On a region-wide basis, this means that hydro power generation varies widely between dry and rainy years. In a normal year, total hydro power generation in the Nordic countries amounts to approximately 190-200 TWh. Hydro power has relatively low variable costs and is therefore the generation source that is the first to be put to use (base load). When the water level of hydro power reservoirs decreases, other sources of power generation have to be put into operation at increasing marginal cost. 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 Nordpool electricity spot market can vary widely both within a given year and between years.

Since the introduction of the EU emissions trading scheme on January 1, 2005, CO₂ emission certificates have had a significant impact on electricity prices also in the Nordic countries. The price of certificates is correlated to fuel prices and to some degree to the hydrology in the Nordic countries as well as in the rest of the EU. In dry years, the demand for CO₂ emission certificates will potentially increase, while a decrease in demand can be expected in wet years. This can markedly increase the volatility of electricity prices.

In 2003, which was a dry year, the total volume of electrical energy generated by hydro power in the Nordic countries was 168 TWh. The system price, i.e. the traded price on Nordpool, reached levels of over 120 öre/kWh in the beginning of 2003 and did not drop below 30 öre/kWh until the end of March. Compared to this, prices in earlier years exceeded 30 öre/kWh only on a few occasions. During the summer of 2003, the price decreased to 20 öre/kWh, and then rose to levels between 25 and 30 öre/kWh during the autumn and winter.

In 2004, the total volume of electrical energy generated by hydro power was 183 TWh. In the beginning of 2004, electricity prices in Sweden remained at levels between 25 and 30 öre/kWh. Prices on the spot market as well as on the forward markets had a peak during summer and early autumn, with the spot price reaching levels of almost 40 öre/kWh. By the fourth quarter, more normal levels of rainfall during the course of the year allowed reservoir levels to recover and at year-end reservoirs were near normal levels. At year-end, electricity spot prices were quoted at levels of 22 öre/kWh.

In 2005, which was a wet year, the total volume of electrical energy generated by hydro power in the Nordic countries was 221 TWh. The year started with warm weather in January and February and after a cold March the rest of the year was a bit warmer than normal. The hydrological balance started at a level above normal and reached a peak of 16 TWh above normal in the beginning of the year. Reservoir levels decreased to normal at the end of the year. The introduction of the EU emissions trading scheme in January resulted in generally higher prices for electricity. The average electricity spot price in 2005 amounted to 27 öre/kWh.

Electricity consumption in the Nordic countries decreased during 2002 and 2003, before recovering in 2004. In 2001 there was a demand of 393 TWh, which fell in 2002 to 388 TWh and in 2003 to 380 TWh, with the decrease in demand being due to high electricity prices following the extremely dry autumn of 2002. In 2004 and 2005, electricity consumption recovered to around 390 TWh and 393 TWh, respectively.

In May 2003, the Swedish government introduced an electricity certificate system to support renewable electrical energy. This is a market-based support system in which the price of the electricity certificates is the result of the relationship 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 10 TWh by 2010 as compared with the 2002 level. Electricity certificates are granted by the Swedish government to generators of electricity from 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 customers) to purchase a certain

number of certificates in proportion to their consumption. This is known as the quota obligation. During 2004, the average quota obligation amounted to 8.1 percent of electricity consumed. In 2005, the average quota obligation amounted to 10.4 percent. The quota obligation is scheduled to gradually increase up to 16.9 percent in 2010. Any applicable end user who fails to meet this quota obligation must instead pay a quota obligation charge to the Swedish government. The electricity certificate scheme is currently under revision. In July 2005, the government proposed a number of amendments to the relevant law, including an increased level from 10 TWh renewable generation sources to 15 TWh by 2016, a prolongation of the overall support system until 2030 and the creation of a common certificate market with Norway. A new law proposal is expected in spring 2006 and parliament approval in mid-2006. E.ON Nordic believes that the proposed changes will positively affect its existing renewable energy generation sources and significantly reduce the uncertainty for future investments.

E.ON Nordic’s main competitors in the Nordic generation 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 Sverige in the Swedish retail market.

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 region, while at the national level, it comprises somewhat less than 2 percent of Sweden’s total energy supply. In 2005, 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 ten competitors active in the Swedish market, with E.ON Sverige accounting for the distribution and sale of approximately half of all gas distributed and sold in Sweden in 2005. The major competitors in the end customer market are municipally owned companies with customers mainly in the geographic area of their municipality. The most important of those are Göteborgs Energi, Öresundskraft and Lunds Energi. In addition, the Danish gas company DONG competes in the Swedish gas market. See also “— Regulatory Environment.”

District Heating. District heating supplies residential buildings, commercial premises and industries 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 Sverige 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. Similar to Sweden, Finland does not regulate district heating prices or revenues.

Power Generation

General. E.ON Nordic owns interests in electric power generation facilities in Sweden and Finland with a total installed capacity of approximately 14,982 MW, its attributable share of which is approximately 7,570 MW (not including mothballed, shutdown or reduced power plants).

E.ON Nordic generates electricity primarily at nuclear and hydroelectric power plants, with a small percentage generated at other types of power plants. In 2005, approximately 48 percent of E.ON Nordic’s electric output was fuelled by nuclear, 45 percent by hydroelectric, and the remaining 7 percent by other fuels including oil, hard coal, biomass, natural gas, wind and waste.

Based on the consolidation principles under U.S. GAAP, 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 following table sets forth E.ON Nordic’s major electric power generation facilities (including cogeneration plants), the total capacity, the stake held by E.ON Sverige or E.ON Finland and the capacity attributable to E.ON Sverige or E.ON Finland for each facility as of December 31, 2005, and their start-up dates.

E.ON NORDIC ELECTRIC POWER STATIONS


				E.ON Sverige’s/E.ON
				Finland’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Nuclear
Forsmark 1(S)			1,018		9.3		95		1980
Forsmark 2(S)			951		9.3		88		1981
Forsmark 3(S)			1,190		10.8		129		1985
Oskarshamn I(S)			467		54.5		255		1972
Oskarshamn II(S)			602		54.5		328		1974
Oskarshamn III(S)			1,160		54.5		632		1985
Ringhals 1(S)			873		29.6		258		1976
Ringhals 2(S)			870		29.6		258		1975
Ringhals 3(S)			920		29.6		272		1981
Ringhals 4(S)			910		29.6		269		1983

	Total		8,961				2,584

Hydroelectric
Balforsen(S)			88		100.0		88		1958
Bergeforsen(S)			160		44.0		70		1955
Bjurfors nedre(S)			78		100.0		78		1959
Blasjön(S)			60		50.0		30		1957
Degerforsen(S)			63		100.0		63		1965
Edensforsen(S)			67		96.5		65		1956
Edsele(S)			60		100.0		60		1965
Forsse(S)			52		100.0		52		1968
Gulsele(S)			64		65.0		42		1955
Hällby(S)			84		65.0		55		1970
Hammarforsen(S)			79		100.0		79		1928
Harrsele(S)			223		50.6		113		1957
Hjälta(S)			178		100.0		178		1949
Järnvägsforsen(S)			100		94.9		95		1975
Korselbränna(S)			130		100.0		130		1961
Moforsen(S)			135		100.0		135		1968
Olden (Langan)(S)			112		100.0		112		1974
Pengfors(S)			52		65.0		34		1954
Ramsele(S)			157		100.0		157		1958
Rätan(S)			60		100.0		60		1968
Sollefteaforsen(S)			61		50.0		31		Tba
Stensjön (Harkan)(S)			95		50.0		48		1968
Storfinnforsen(S)			112		100.0		112		1953


				E.ON Sverige’s/E.ON
				Finland’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Hydroelectric (continued)
Trangfors(S)			73		100.0		73		1975
Other (<50 MW installed capacity)			874		n/a		811		n/a

	Total		3,217				2,771

Fuel Oil
Barsebäck GT(S)			84		100.0		84		1974
Bravalla(S)			240		100.0		240		1972
Halmstad G11(S)			78		100.0		78		1973
Halmstad G12(S)			172		100.0		172		1993
Karlshamn G1(S)			332		70.0		232		1971
Karlshamn G2(S)			332		70.0		232		1971
Karlshamn G3(S)			326		70.0		228		1973
Karskär G4(S)			125		50.0		63		1968
Öresundsverket GT(S)			126		100.0		126		1971
Oskarshamn GT(S)			80		54.5		44		1973
Other (<50 MW installed capacity)			100		n/a		64		n/a

	Total		1,995				1,563

Natural Gas
Heleneholm G11, G12(S)(CHP)			130		100.0		130		1966+1970
Suomenoja GT(1)(FIN)			50		100.0		50		1989

	Total		180				180

Hard Coal
Suomenoja(1)(FIN)			80		100.0		80		1977

Wind Power
Sweden			19		n/a		19		n/a
Denmark			166		n/a		33		n/a

	Total		185				52

Other Power Plants
Abyverket G1, G2, G3(S)(CHP)			151		100.0		151		1962-1974
Händelö (Norrköping)(S)(CHP)			100		100.0		100		1983
Joensuu Bio(1)(FIN)			65		100.0		65		1986
Karskär G3(S)			48		50.0		24		1968

	Total		364				340

Shutdown
Barsebäck 1(S)(Nuclear)			—		25.8		—		1975
Barsebäck 2(S)(Nuclear)			—		25.8		—		1977

	Total		14,982				7,570


(1)	Power plant of E.ON Finland.

(FIN) Located in Finland.

(S) Located in Sweden.

(CHP) Combined Heat and Power Generation.

E.ON Nordic’s total attributable capacity decreased by 401 MW compared with 2004 mostly due to the sale of hydroelectric power plants to Statkraft (see “— Overview — E.ON Sverige” above).

Following receipt of the necessary approvals, E.ON Sverige plans to build a new gas-fired CHP plant in the Swedish city of Malmö. 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 has started in 2005. Pending receipt of thenecessary approvals, E.ON Sverige expects that all major efficiency improvements will have been carried out by 2010.

Nuclear Power. In Sweden, E.ON Sverige operates three nuclear power plants (Oskarshamn I — III), which provided 50 percent of its total power output in 2005 (48 percent of E.ON Nordic’s total power output in 2005). In addition, E.ON Sverige holds minority participations in all other Swedish nuclear power reactors. E.ON Sverige 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 production cost. E.ON Finland does not own an interest in or operate any nuclear power plants.

E.ON Sverige’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 Kärnbränslehantering AB (“SKB”), which is owned by the domestic nuclear power producers and controlled 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 plants. 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 plants. 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 Sverige expects that a decision will be taken on where the deep repository is to be built by 2010, with the first nuclear waste expected to be stored there by 2017.

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 Sverige has one nuclear reactor, Barsebäck 1, which was closed under this law in 1999 and for which E.ON Sverige received compensation. Beginning in 2002, the Swedish government appointed a special negotiator whose task was to negotiate with the Swedish energy industry on behalf of the government, with the aim of reaching an agreement about a sustainable policy for the energy system.

In September 2004, these negotiations were unilaterally abandoned by the Swedish government. At the same time, the government has opted for the phase-out of the nuclear reactor block Barsebäck 2, which was subsequently shut down in May 2005. The effect of a possible phase-out of Barsebäck 2 on E.ON Sverige had already been taken into account in the agreement when Barsebäck 1 was shut down in 1999. Based on this, a final agreement concerning the compensation for the closure of Barsebäck 2 was entered into in November 2005 between E.ON Sverige, the Swedish government and the state-owned Swedish utility Vattenfall. The main component of the agreement is that E.ON Sverige gets an increased shareholding in the Swedish nuclear power generator Ringhals AB. This will give E.ON Sverige approximately the same production capacity as before the closure of Barsebäck 2.

Overall, there is deemed to be no effect on the balance sheet or profits of E.ON Sverige due to the pre-mature closure of Barsebäck 1 or 2. As of today, E.ON Sverige 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 E.ON Sverige will need to shut down other nuclear power plants 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 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. Expenses for other low and intermediate-level operational nuclear waste have to be directly covered by the nuclear operators. For this purpose, E.ON Sverige has made provisions totaling €7.1 million as of December 31, 2005.

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. E.ON Sverige expects that the change will increase its related tax expense by €47 million in 2006.

E.ON Sverige purchases fuel elements for nuclear power plants from international suppliers. E.ON Sverige considers the supply of uranium and fuel elements on the world market to be adequate.

Hydroelectric. In Sweden, E.ON Sverige operates 115 hydroelectric power plants, which provided 46 percent of its total power output in 2005 (45 percent of E.ON Nordic’s total power output in 2005). In addition, E.ON Finland operates one minor hydroelectric plant. 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. In periods of severe water shortages, such as occurred in late 2002 and early 2003 E.ON Sverige must purchase electricity which cannot be generated at these plants from the market in order to meet contractual commitments. Conversely, following periods of high precipitation E.ON Sverige is able to generate more electricity than it needs to meet its commitments, and is therefore able to sell excess electricity to its sales partners or on the market. 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. See also “Item 3. Key Information — Risk Factors.”

Hydroelectric power plants in Sweden are subject to real estate taxes, which were increased in 2005. E.ON Sverige expects that its related tax expense will increase by €28 million in 2006 and rise further in 2007 due to a revaluation of the tax base.

Other Power Plants. Power plants fuelled by fuel oil, hard coal, biomass, natural gas, wind power and waste provided the remaining 7 percent of E.ON Nordic’s total power output in 2005. Hard coal and 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. E.ON Nordic believes it has adequate sources of power to meet foreseeable increases in demand, whether seasonal or otherwise.

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. In September 2003, a blackout in parts of Sweden and Denmark was caused by a combination of a fault in the transmission grid and a failure at the power plant Oskarshamn (which is 54.5 percent owned by E.ON Sverige) that occurred when the plant was being returned to service following routine maintenance. The power plant restarted in November 2003 following a comprehensive investigation and analysis. No serious consequences arose from the shutdown. 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 the market. Thus, as with water shortages, power plant outages can negatively affect the market unit’s financial and operating results. No significant unplanned outage occurred in 2004 or 2005.

Electricity Distribution

E.ON Nordic and its associated companies are actively involved in electricity distribution activities in both Sweden and Finland.

In Sweden, the high voltage electricity grid is managed by Svenska Kraftnät, a company owned by the Swedish government. Mid-voltage electricity is transmitted through a regional distribution network with a length of around 40,000 km, of which E.ON Sverige 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 Sverige. The length of the total local network for Sweden is about 550,000 km, of which E.ON Sverige owns 117,000 km. Balance control for the whole system is managed by Svenska Kraftnät.

In January 2005, a severe storm hit Sweden and devastated large areas of forest in southern Sweden. This had a serious effect on parts of E.ON Sverige’s distribution grid, which in some areas was destroyed. For details, including the cost incurred by E.ON Sverige, see “— Overview.” Following this storm, E.ON Sverige has launched a major reinvestment program in order to secure and increase the reliability of its local and regional distribution grids. The focus of reinvestment activity will be on cabling insulated overhead lines in the local networks and securing broader “right of way” corridors in the regional networks. E.ON Sverige expects that this will markedly reduce its exposure to weather-related damage in the future.

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 Energie in Germany. The Baltic Cable is one of the longest (250 km) direct current submarine cables in the world, with a designed capacity of 600 MW. E.ON Sverige owns one-third of the cable, with the remaining two-thirds owned by the Norwegian utility Statkraft.

In 2005, E.ON Sverige’s distribution network served approximately one million customers, including approximately 590,000 customers in southern Sweden, 325,000 customers in the metropolitan areas of Stockholm/Örebro/ Norrköping and 85,000 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 Sverige also owns and operates local power distribution grids in Finland through Kainuun Energia Oyj (54,300 customers in western Finland), with a length of 12,470 km, and Karhu Voima Oyj (16 industrial customers in southwest Finland), with a length of 68 km.

The power distribution grid of E.ON Finland is located in the areas of Espoo and Joensuu. The grid has a system length of approximately 7,000 km. In 2005, E.ON Finland’s distribution grid served approximately 162,000 customers.

The following map shows E.ON Nordic’s current distribution areas.

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 Sverige and E.ON Finland may choose other retail suppliers and E.ON Sverige and E.ON Finland may sell electricity to customers not covered by their own power transmission grids. For information on grid access, see “— Regulatory Environment — Nordic.”

Gas Distribution

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 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 Nova Naturgas, a consortium in which E.ON Ruhrgas holds a 29.6 percent interest. E.ON Sverige 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 Sverige 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 2005, E.ON Sverige transported a total of 6.9 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. E.ON Nordic is participating in the Baltic Gas Interconnector project promoting the construction of a pipeline between Germany, Sweden and Denmark. During 2004, E.ON Sverige was granted the Swedish concession for this project. The authorization processes in Germany and Denmark are ongoing.

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 and in Finland. In addition, E.ON Nordic sells electricity, heat and natural gas in Denmark.

Electricity. As of December 31, 2005, E.ON Sverige supplied electricity to approximately 850,000 electricity customer accounts in Sweden and to a minor degree in Denmark. Through its subsidiaries Kainuun Energia Oyj and Karhu Voima Oyj, E.ON Sverige supplied approximately 71,000 customers in Finland. Although

the majority of E.ON Sverige’s customer accounts are with residential customers, the majority of its sales are made to commercial customers. E.ON Sverige sold a total of 19.7 TWh of electricity in 2005, of which 7.0 TWh was delivered to residential customers and 12.7 TWh was delivered to commercial customers (including municipal distributors). E.ON Sverige’s electricity customers are concentrated in the south of Sweden, the areas of Stockholm, Örebro and Norrköping, as well as in the Mid-Norrland region, although E.ON Sverige potentially serves customers throughout Sweden.

E.ON Finland’s electricity sales operations cover all of Finland, although its customers are mainly located in the Espoo region. As of December 31, 2005, E.ON Finland supplied electricity to approximately 165,000 electricity customer accounts. In 2005, E.ON Finland sold electricity totaling 2.7 TWh, of which 1.5 TWh was sold to residential customers and 1.2 TWh was sold to commercial customers. E.ON Finland does not sell electricity to distributors.

Gas. In the Swedish gas market, E.ON Sverige supplied approximately 25,000 customers with gas in 2005. 6.1 TWh were delivered to large industrial and (mostly municipal) distribution customers, and 0.2 TWh were delivered to residential customers. E.ON Sverige also supplied a small amount of gas in Denmark in 2005.

E.ON Sverige also supplied 0.6 TWh of gas to eight industrial customers in Finland.

E.ON Finland sold 45 GWh of gas to 166 industrial customers in 2005. Overall, natural gas consumption in Finland is very limited in the residential customer sector. The main users of gas in Finland are power plants and the paper and pulp industry.

Heat & Waste. E.ON Sverige sells heating, including district heating, to approximately 18,000 customers in Sweden and Denmark. In 2005, sales of district heating in Sweden amounted to 6.2 TWh. In Denmark, 2005 sales amounted to 1.4 TWh. In addition, in 2005 E.ON Sverige sold a de minimis amount of heat in Poland. E.ON Finland’s district heating operations are concentrated in the area of Espoo. E.ON Finland served a total of approximately 7,600 customers in 2005, delivering 2.5 TWh of heat.

E.ON Nordic is also active in the Swedish waste business, mainly through E.ON Sverige SAKAB AB (“E.ON Sverige SAKAB”). E.ON Sverige SAKAB’s operations focus on recycling and destroying hazardous waste. In addition, E.ON Sverige SAKAB treats a small portion of household waste and industrial refuse for heat-recovery purposes. In 2005, E.ON Sverige’s waste activities had combined sales of €52 million. Waste volumes handled amounted to approximately 453,000 tons.

Other Activities. E.ON Nordic provides distribution network and other services primarily in Sweden through E.ON Sverige’s subsidiary ElektroSandberg AB. E.ON Sverige Bredband AB is active in the broadband communications business.

Trading

E.ON Nordic conducts its energy trading activities through E.ON Sverige and E.ON Finland. The focus is on electricity trading on the Nordpool exchange but does to a lesser extent include other commodities such as oil, natural gas, CO₂ emission certificates and propane.

E.ON Sverige and E.ON Finland use energy trading to optimize the value of and manage risks associated with their energy portfolios. E.ON Sverige 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. For additional information on these policies and related exposures, see “Item 11. Quantitative and Qualitative Disclosures about Market Risk.”

The following table sets forth the total volume of E.ON Nordic’s traded electric power in 2005 and 2004.

2005

2004

million

Trading of Power

kWh

% Change

Power sold

53,503

56,758

-5.7

Power purchased

56,225

48,764

+15.3

Total

109,728

105,522

+4.0

The major part of realized trading volumes is usually contracted in the year prior to realization. Trading volumes increased compared to 2004, which was affected by the extremely high spot and forward prices in the beginning of 2003.

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 off-system sale of excess power generated by physical assets owned or controlled by E.ON U.S. and its affiliates pursuant to bilateral contracts with wholesale customers on negotiated terms. 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, 2005, E.ON U.S. owned or controlled aggregate generating capacity of approximately 7,700 MW, including E.ON U.S.’s interest in independent power plants of 105 MW in North Carolina, which is the subject of a pending sale agreement. See “— Non-regulated Businesses.” E.ON U.S.’s 50 percent interest in a 550 MW Texas plant was sold in January 2005. In 2005, E.ON U.S. served more than one million customers. The U.S. Midwest market unit recorded sales of €2,045 million in 2005 and adjusted EBIT of €365 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 2005, 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 approximately 96 percent of E.ON U.S.’s revenues in 2005 (82 percent electricity, 18 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 approximately 4 percent of E.ON U.S.’s sales in 2005, is primarily comprised of the operations of E.ON U.S. Capital Corp. (formerly LG&E Capital Corp.) (“ECC”) and LG&E Energy Marketing Inc. (“LEM”).

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, including Virginia, 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 begun discussing re-regulation. To better support a competitive industry, federal regulators are transforming the manner in which the electric transmission grid is operated. Transmission owning entities are being strongly 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.’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.

E.ON U.S.’s primary retail electric service territories are located in Kentucky, which accounted for approximately 62 percent of E.ON U.S.’s total revenues in 2005. 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. During 2005, KU’s Virginia operations accounted for approximately 5 percent of KU’s total revenues and approximately 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 total revenues in each of 2005 and 2004.

Over the past decade, E.ON U.S. has taken steps to keep its rates low while maintaining high levels of customer satisfaction, including a reduction in the number of employees; aggressive cost reduction activities; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. E.ON U.S. also strives to control costs through competitive bidding and process improvements. The company’s performance in national customer satisfaction surveys continues to be high.

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 394,000 customers and supplies natural gas to approximately 321,000 customers in Louisville and adjacent areas of Kentucky. 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, 2005, LG&E owned steam and combustion turbine generating facilities with an attributable capacity of 3,105 MW and a 48 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 495,000 customers in 77 counties in central, southeastern and western Kentucky and approximately 30,000 customers in five counties in southwestern Virginia. In Virginia, KU operates under the name Old Dominion Power Company. KU also sells wholesale electric energy to 12 municipalities and fewer than 10 customers in Tennessee. KU’s coal-fired electric generating plants produce a significant amount (97 percent) of KU’s electricity; the remainder is generated by gas- and oil-fired combustion turbines (approximately 3 percent) and a hydroelectric facility. As of December 31, 2005, KU owned steam and combustion turbine generating facilities with an attributable capacity of 4,433 MW and a 24 MW hydroelectric facility.

Power Generation

The following table sets forth details of LG&E’s and KU’s electric power generation facilities, including their total capacity, the stake held by E.ON U.S. and the capacity attributable to E.ON U.S. for each facility as of December 31, 2005, and their start-up dates.

LG&E’S AND KU’S ELECTRIC POWER STATIONS


				E.ON U.S.’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Hard Coal
Cane Run 4(1)			155		100.0		155		1962
Cane Run 5(1)			168		100.0		168		1966
Cane Run 6(1)			240		100.0		240		1969
E.W. Brown 1(2)			101		100.0		101		1957
E.W. Brown 2(2)			167		100.0		167		1963
E.W. Brown 3(2)			429		100.0		429		1971
Ghent 1(2)			475		100.0		475		1974
Ghent 2(2)			484		100.0		484		1977
Ghent 3(2)			493		100.0		493		1981
Ghent 4(2)			493		100.0		493		1984
Green River 3(2)			68		100.0		68		1954
Green River 4(2)			95		100.0		95		1959
Mill Creek 1(1)			303		100.0		303		1972
Mill Creek 2(1)			301		100.0		301		1974
Mill Creek 3(1)			391		100.0		391		1978
Mill Creek 4(1)			477		100.0		477		1982
Trimble County(1)			511		75.0		383		1990
Tyrone 3(2)			71		100.0		71		1953

	Total		5,422				5,294

Natural Gas
Cane Run 11(1)			14		100.0		14		1968
E.W. Brown 5(3)			117		100.0		117		2001
E.W. Brown 6(3)			154		100.0		154		1999
E.W. Brown 7(3)			154		100.0		154		1999
E.W. Brown 8(2)			106		100.0		106		1995
E.W. Brown 9(2)			106		100.0		106		1994


				E.ON U.S.’s Share

		Total				Attributable
		Capacity				Capacity		Start-up
Power Plants		Net MW		%		MW		Date

Natural Gas (continued)
E.W. Brown 10(2)			106		100.0		106		1995
E.W. Brown 11(2)			106		100.0		106		1996
E.W. Brown IAC(3)			98		100.0		98		2000
Haefling 1(2)			12		100.0		12		1970
Haefling 2(2)			12		100.0		12		1970
Haefling 3(2)			12		100.0		12		1970
Paddy’s Run 11(1)			12		100.0		12		1968
Paddy’s Run 12(1)			23		100.0		23		1968
Paddy’s Run 13(3)			158		100.0		158		2001
Trimble County 5(3)			160		100.0		160		2002
Trimble County 6(3)			160		100.0		160		2002
Trimble County 7(3)			160		100.0		160		2004
Trimble County 8(3)			160		100.0		160		2004
Trimble County 9(3)			160		100.0		160		2004
Trimble County 10(3)			160		100.0		160		2004
Waterside 7(1)			11		100.0		11		1964
Waterside 8(1)			11		100.0		11		1964
Zorn 1(1)			14		100.0		14		1969

	Total		2,186				2,186

Oil
Tyrone Unit 1(2)			27		100.0		27		1947
Tyrone Unit 2(2)			31		100.0		31		1948

	Total		58				58

Hydroelectric
Dix Dam(2)			24		100.0		24		1925
Ohio Falls(1)			48		100.0		48		1928

	Total		72				72

E.ON U.S. Regulated Business Total			7,738				7,610

Shutdown
Green River 1(2)			22		100.0		22		1950
Green River 2(2)			22		100.0		22		1950

	Total		44				44


(1)	Power stations owned by LG&E.

(2)	Power stations owned by KU.

(3)	Power stations jointly owned by LG&E and KU.

Fuel. Coal-fired steam and combustion turbine generating units provided approximately 97 percent of LG&E’s and KU’s net kWh generation for 2005. The remainder of 2005 net generation was produced by natural gas- and oil-fueled combustion turbine peaking units (approximately 2 percent) and hydroelectric plants. E.ON

U.S. has no nuclear generating units and coal will 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 2006 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 and West Virginia, with additional KU purchases from eastern Kentucky, Wyoming and Colorado. In general, the delivered cost of coal has been rising since late 2000.

LG&E purchases natural gas transportation services from Texas Gas Transmission, LLC and Tennessee Gas Pipeline Company. 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, in addition to the wholesale sale of excess asset capacity. These off-system sales accounted for 4.4 TWh in 2005. Although the companies do not conduct proprietary or speculative trading, certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133. Wholesale sales of excess asset capacity in the MISO day-ahead and real-time markets (as defined below) are treated as normal sales under SFAS No. 133 and are not marked-to-market.

Transmission

E.ON U.S.’s utility subsidiaries LG&E and KU operate 4,930 miles of transmission line. They participate as transmission owning members of the Midwest Independent Transmission System Operator, Inc. (“MISO”), which commenced commercial operations in February 2002. The MISO implemented a day-ahead and real-time market (“MISO Day 2”), including a congestion management system, in April 2005. The Federal Energy Regulatory Commission (“FERC”) and the United States Courts of Appeals have generally affirmed the MISO’s imposition of certain of its administrative, congestion management and other regional market-related costs on market participants and users of the system, including native load customers, resulting in increased costs for LG&E and KU. LG&E and KU continue to participate in proceedings before the FERC, the federal courts in Washington D.C. and the KPSC, challenging the imposition of various costs on native load customers and seeking authorizations to exit the MISO regime, as described below under “— Regulatory Environment — U.S. Midwest.”

For additional information about transmission developments, including additional proceedings, see “— Regulatory Environment — U.S. Midwest.”

At this time, LG&E and KU cannot predict the outcome or effects of the various KPSC and FERC proceedings described above, including whether such proceedings will have a material impact on their financial condition or results of operations. Further, the ultimate financial consequences for E.ON U.S. (primarily changes in transmission revenues and costs) associated with the April 2005 implementation of day-ahead and real-time market tariff charges are subject to varying assumptions and calculations and are therefore difficult to estimate.

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 less than 10 customers in Tennessee. In 2005, LG&E’s total electric retail sales to residential, commercial and industrial customers were 11.0 billion kWh and its total aggregate electric sales, including off-system sales, were 16.1 billion kWh. In 2005, KU’s total electric retail sales to residential, commercial and industrial customers were 16.5 billion kWh and its total aggregate electric sales were 21.6 billion kWh.

The following table sets forth LG&E’s and KU’s sale of electric power for the periods presented:


		Total 2005		Total 2004
Sales of Electric Power to		million kWh		million kWh

Residential			10,864		10,084
Commercial and industrial customers			16,684		16,276
Municipals			2,014		1,959
Other retail			3,720		3,576
Off-system sales			4,434		4,199

	Total		37,716		36,094

The gas retail activities of LG&E are limited to its service territory in Kentucky. In 2005, LG&E’s total retail gas sales were 10.8 billion kWh (2004: 10.2 billion kWh ) and its total aggregate gas sales (including gas transportation volumes and wholesale sales) were 14.6 billion kWh (2004: 14.7 billion kWh).

On June 30, 2004, the KPSC approved electric and gas base rate changes at LG&E and KU that increased these rates by an aggregate of approximately $100 million per year. The new rates became effective on July 1, 2004. For details, including pending regulatory challenges, see “— Regulatory Environment — U.S. Midwest.”

Non-regulated Businesses

ECC. ECC is the primary holding company for E.ON U.S.’s non-regulated businesses discussed below. Its businesses include domestic power generation and wholesale sales, international operations, and pipeline services.

Argentine Gas Distribution Operations. ECC owns interests in Argentine gas distribution operations which provide natural gas to approximately two million customers in Argentina through three distributors (Gas Natural BAN S.A. (“Ban”), Distribuidora de Gas del Centro S.A. (“Centro”) and Distribuidora de Gas Cuyana S.A. (“Cuyana”)). ECC owns 19.6 percent of Ban, 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.

LPI. LG&E Power Inc. (“LPI”), a wholly-owned subsidiary of ECC, and its affiliates own, operate and maintain interests in U.S. independent power generation facilities. LG&E Power Services LLC (“LPS”), an affiliate of LPI, operates four facilities in the United States under medium-term operating contracts with independent third parties. LPI also has a 50 percent ownership interest in a 209 MW coal-fired facility in North Carolina and operates that facility under a medium-term operating contract with a utility. Following management’s decision in September 2003 to dispose of all of LPI’s assets, LPI and ECC sold their interests in wind power generation facilities in Texas and Spain in 2004. In January 2005, LPI sold its 50 percent ownership interest in a 550 MW gas-fired power generation facility in Texas. LPI has also entered into a contract to sell its share of the facility in North Carolina, which sale process has been in litigation concerning third party consent or first refusal rights. Negotiations seeking to resolve the litigation and agreeing on a revised sale contract for the North Carolina facility, which would also include the sale of all of the assets of LPS, are progressing and it is possible that the transaction may be completed in the first half of 2006. However, no assurance can be given that the sale or the disposal of LPI’s or LPS’s remaining assets will be completed as planned.

LEM. Effective June 30, 1998, LEM discontinued its merchant energy trading and sales business. This business consisted primarily of a portfolio of energy marketing contracts entered into in 1996 and early 1997,

including a long-term contract with Oglethorpe Power Corporation which terminated at the end of 2004, nationwide deal origination and some level of proprietary trading activities, which were not directly supported by E.ON U.S.’s physical assets. E.ON U.S.’s decision to discontinue these operations was primarily based on the impact that volatility and rising prices in the power market had on its portfolio of energy marketing contracts. As of December 31, 2005, E.ON U.S. has completed settlement of all commitments entered into during this period.

OTHER ACTIVITIES

Degussa

Overview

Degussa is one of the major specialty chemical companies in the world. In May 2002, E.ON reached a definitive agreement with RAG to sell a portion of E.ON’s majority interest in Degussa to RAG and to acquire RAG’s more than 18 percent interest in E.ON Ruhrgas in a two step transaction. In late January 2003, E.ON completed the first step of the RAG/ Degussa transaction by acquiring RAG’s Ruhrgas stake and tendering 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 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. The shares of Degussa AG are listed on the Frankfurt Stock Exchange and are part of the MDAX, the performance index of 50 German mid-cap companies. In the second step, E.ON sold a further 3.6 percent of Degussa stock to RAG as of May 31, 2004. Effective June 1, 2004, E.ON owns 42.9 percent of Degussa. 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 at the price of €31.50 per share, which would result in total proceeds of €2.8 billion. The transaction, which is subject to the approval of the German federal government and the state of North-Rhine Westphalia, is expected to be completed by July 1, 2006. Until completion of this transaction, E.ON and RAG operate Degussa under joint control.

Since the first step of the RAG/ Degussa transaction was completed, E.ON accounts for Degussa using the equity method. For all periods from February 1, 2003 until May 31, 2004, E.ON recorded 46.5 percent of Degussa’s after-tax earnings in its financial earnings. From June 1, 2004, E.ON records 42.9 percent of Degussa’s after-tax earnings in its financial earnings. For 2005, Degussa contributed adjusted EBIT of €132 million.

Operations

Degussa’s strategic management responsibilities lie with its board of management, while responsibility for management at the operational level rests with Degussa’s decentralized business units, each of which is grouped into one of Degussa’s core divisions. The following chart sets forth Degussa’s divisions divided into business units:

DEGUSSA



Technology	Construction	Consumer	Specialty
Specialists	Chemicals	Solutions	Materials

Building Blocks	Admixture Systems Europe	Superabsorber	Coatings & Colorants

Exclusive Synthesis & Catalysts	Admixture Systems North America	Care & Surface Specialties	High Performance Polymers

C ₄-Chemistry	Admixture Systems Asia/Pacific	Feed Additives	Methacrylates

Aerosil & Silanes	Construction Systems Europe		Specialty Acrylics

Advanced Fillers & Pigments	Construction Systems Americas

In March 2006, Degussa announced that it had reached an agreement to sell the activities of its Construction Chemicals division to BASF. The transaction, which is subject to regulatory approvals, is expected to close before

the end of the year. All other activities are grouped as non-core businesses or services/development units and are not shown in the table above.

DISCONTINUED OPERATIONS

In 2002 and 2001, the Company discontinued the operations of its former oil segment and of its former aluminum and silicon wafer segments, respectively. These former segments are accounted for as discontinued operations in accordance with U.S. GAAP. In addition, in 2003, E.ON discontinued and disposed of certain operations in the Central Europe and U.S. Midwest market units, as well as certain activities of Viterra in the Other Activities business segment. 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. 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.

Oil

In July 2001, E.ON and BP entered into an agreement pursuant to which BP agreed to acquire a 51.0 percent stake in VEBA Oel by way of a capital increase. VEBA Oel was then active in the oil and gas exploration and production, oil processing and marketing and petrochemicals businesses. The agreement also provided E.ON with a put option that allowed it to sell the remaining 49.0 percent interest in VEBA Oel to BP at any time from April 1, 2002 for €2.8 billion, subject to certain purchase price adjustments. In December 2001, the German Federal Cartel Office cleared the transaction. The capital increase took place in February 2002, giving BP majority control of VEBA Oel as of February 1, 2002. The aggregate consideration paid by BP for the capital increase was approximately €2.9 billion. In addition, €1.9 billion in shareholder loans from the E.ON Group to VEBA Oel were repaid. As of June 30, 2002, E.ON exercised the put option. E.ON has received €2.8 billion for its VEBA Oel shares plus the aforementioned repayment of the shareholder loans. In April 2003, E.ON and BP reached an agreement setting the final purchase price for VEBA Oel (without prejudice to the standard indemnities in the contract) at approximately €2.9 billion. The disposal of VEBA Oel resulted in a loss from discontinued operations net of income taxes of €37 million in 2003. E.ON recognized a loss on disposal of €35 million in 2003 related to the final purchase price settlement and a gain of €1.4 billion in 2002. In 2004, E.ON recognized a loss of €19 million resulting from claims under standard contractual indemnities. These effects were recorded under “Income (Loss) from discontinued operations, net” in the income statement for the relevant period.

Aluminum

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 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 (“SFAS 142”), 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.

Silicon Wafers

On September 30, 2001, E.ON agreed to sell its 71.8 percent interest in MEMC (then a worldwide manufacturer of silicon wafers for the semiconductor device industry) to Texas Pacific Group, a San Francisco-based financial investor, for a symbolic price, which included the assumption of shareholder loans made by E.ON. The transaction was completed on November 13, 2001. In September 2003, the purchase price was adjusted, as provided for in the purchase agreement, because MEMC had substantially improved its earnings

performance in 2002. This purchase price adjustment resulted in income from discontinued operations net of income taxes and minority interests for E.ON of €14 million.

Other Activities

In June 2003, Viterra disposed of Viterra Energy Services AG (“Viterra Energy Services”), which then provided heat and water submetering services for administrators and owners of residential and commercial property, to CVC Capital Partners. In March 2003, Viterra sold its Viterra Contracting GmbH (“Viterra Contracting”) subsidiary, which then provided heat contracting services to apartment buildings, to Mabanaft GmbH (“Mabanaft”). The aggregate consideration for both transactions totaled €961 million, including approximately €112 million of assumed liabilities, with Viterra realizing a gain of €641 million. The portion of 2003 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €681 million. For the portion of 2003 prior to their disposition, Viterra Energy Services and Viterra Contracting had combined revenues of €202 million. In 2004, the release of previously recorded provisions resulted in income in the amount of €10 million, which is recorded in the same line item.

On May 17, 2005, E.ON sold Viterra (then one of Germany’s largest private owners of residential property) to Deutsche Annington. The purchase price for 100 percent of Viterra’s equity was approximately €4 billion. The transaction closed in August 2005. The company was classified as a discontinued operation in May 2005 and deconsolidated as of July 31, 2005. 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 €2.6 billion and €294 million, respectively. In 2005, Viterra had revenues of €453 million. E.ON recorded a gain on disposal of €2.4 billion.

Other

As a legal condition for E.ON’s acquisition of Ruhrgas, E.ON Energie was required to dispose of its 80.5 percent shareholding in Gelsenwasser, which then provided drinking water, industrial water, natural gas and other utility services in Germany. In September 2003, a joint venture company owned by the municipal utilities of the German cities of Dortmund and Bochum purchased the Gelsenwasser interest for €835 million. The portion of Gelsenwasser’s 2003 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €479 million. In 2003, Gelsenwasser had revenues of €295 million. E.ON realized a gain on disposal of €418 million.

As a part of the regulatory approval of the former Powergen’s acquisition of LG&E Energy (now E.ON U.S.), the SEC had required that LG&E Energy sell CRC-Evans International Inc. (“CRC-Evans”), then a provider of specialized equipment and services used in the construction and rehabilitation of gas and oil transmission pipelines. Effective October 31, 2003, LG&E Energy sold CRC-Evans to an affiliate of Natural Gas Partners for €37 million. The portion of CRC-Evans’ results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to approximately €1 million in each of 2005 and 2003. E.ON realized no gain or loss on the disposal. In 2003, CRC-Evans had revenues of €73 million.

On June 15, 2005, E.ON Ruhrgas signed an agreement regarding the sale of Ruhrgas Industries (then an industrial business, which focused on metering and industrial furnaces) to CVC Capital Partners. The purchase price for 100 percent of Ruhrgas Industries’ equity was approximately €1.2 billion, with the purchaser’s assumption of Ruhrgas Industries’ debt and provisions bringing the total value of the transaction to approximately €1.5 billion. The transaction received antitrust approval in July and early September and 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 disposal of €0.6 billion.

In November 2005, E.ON U.S. entered into a letter of intent with Big Rivers Electric Corporation (“BREC”), a power generation cooperative in western Kentucky, regarding a proposed transaction to terminate the lease and operational agreements for nine coal-fired and one oil-fired electricity generation units in western

Kentucky among the parties, which were held through its wholly-owned subsidiary Western Kentucky Energy Corp. and affiliates (“WKE”). The parties are in the process of negotiating definitive agreements regarding the transaction, the closing of which would be subject to review and approval of various regulatory agencies and other interested parties. Subject to such contingencies, the parties are working on completing the proposed termination transaction by the end of 2006. WKE was classified as a discontinued operation at the end of December 2005. The portion of WKE’s 2005 and 2004 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to a loss of €162 million and €2 million, respectively.

For further information, see Note 4 of the Notes to Consolidated Financial Statements.

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”).

The First Electricity Directive was adopted in December 1996 and 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 Energy Law of 1998 modified the old Energy Law, the German legal framework governing utilities that sets forth the general obligations required of electricity and gas companies and defines which segments of the industry are subject to regulation.

The First Gas Directive was adopted in 1998 and was intended to open access to the internal gas markets of EU member states. The Energy Law of 1998 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 into 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 First Electricity and Gas Directives, the Energy Law, the Second Electricity and Gas Directives, and amendments of 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.

The First Electricity and Gas Directives

The First Electricity Directive established common rules for the internal EU electricity market. Under the First Electricity Directive, the EU electricity market was expected to be opened gradually to competition. Member states could choose to have either a so-called “single-buyer system” or a system permitting negotiated or regulated third party access to electricity networks (“nTPA” or “rTPA”). Member states that elected the nTPA system were required to publish frameworks for network charges. The Directive also required integrated utilities

to keep separate accounts for their transmission and distribution activities, as well as for other activities not relating to transmission and distribution, in their internal accounting.

The First Gas Directive provided for a gradual opening of EU member states’ natural gas markets to competition. It allowed each member state to opt for nTPA or rTPA systems, similar to the provisions of the First Electricity Directive. Under the First Gas Directive, natural gas companies were allowed to apply for a temporary derogation from the rules for third party access in case of serious economic and financial difficulties created by existing take-or-pay commitments. The First Gas Directive also required integrated utilities to keep separate accounts for their transmission and distribution activities, as well as for other activities not relating to transmission and distribution, in their internal accounting.

The German Energy Law

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 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 requires a transmission company to take into account the extent to which such transmission displaces 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 requires 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 that at least a methodology for calculating network charges be fixed by law or approved by an independent regulatory body which is required to be established. 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.

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 enables 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 requires 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 that at least a methodology for calculating network charges be fixed by law or approved by an independent regulatory authority which is required to be established. 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 became 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.

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 and 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 new law contains two phases of regulation. In the starting phase of regulation, the BNetzA and the state level regulators set allowed capital costs for utilities ex-ante using a cost-based rate-of-return model. 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. Network operators must calculate network charges using this cost-based model and submit the charges to the BNetzA for approval ex-ante. See “— Germany: Electricity — Electricity Network Charges” and “— Germany: Gas — Gas Network Charges” below. In a second phase of regulation, which is currently expected to be implemented in 2007, the BNetzA is obliged to develop and implement a new incentive-based regulation system which will replace the current cost-based model. At this time, E.ON is unable to predict the form of such incentive regulation, or 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 proved. 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. All network operators are obliged to develop an entry/exit model by February 1, 2006, with implementation required by October 1, 2006.

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.

The Company’s German transmission system operations already comply with the legal unbundling requirements contained in the Energy Law of 2005. With respect to its distribution system operations, the Company expects to comply with the legal unbundling requirement by the required deadline of July 1, 2007. The Company’s German transmission and distribution system operations already comply with the operational (organizational), information and accounting unbundling requirements contained in the Energy Law of 2005.

The exact interpretation of some of the new regulatory rules is still pending. Therefore, the Company cannot predict all consequences of the new legal framework for its operations or the effect of the new law on its future earnings and financial condition.

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 EU Commission. The committee will adopt guidelines on inter-transmission system operator compensation for electricity transit flows, on the harmonization of national

transmission charges and on network congestion management. The applicable guidelines have already been drafted and are expected to enter into force in 2006.

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. This transitional charge system will remain in effect until the guidelines outlined in the EU’s Regulation on Cross-Border Electricity Trading are applicable, i.e. at least for part of 2006.

Greenhouse Gas Emissions Trading

In order to reach the greenhouse gas emissions reduction targets set by the Kyoto Protocol to the United Nations Framework Convention on Climate Change (the “Kyoto Protocol”), the EU adopted a directive on emissions trading (Directive 2003/87/ EC Establishing a Scheme for Greenhouse Gas Emission Allowance Trading Within the Community, or the “Emissions Trading Directive”) on October 13, 2003. The Emissions Trading Directive establishes a greenhouse gas emissions allowance trading scheme for member states which started in 2005. The trading scheme is currently limited to the trading of CO₂ emission certificates. The first obligatory commitment period under the Kyoto Protocol will follow from 2008 to 2012. Under the emissions allowance trading scheme, operators of identified types of industrial installations within the EU (including fossil fuel-fired combustion installations and gas turbines with a thermal input exceeding 20 MW) are obliged to acquire one or more CO₂ emission certificates that entitle the installation to emit a specified quantity of CO₂. If an installation exceeds the level of emissions covered by its certificates (which were initially allocated free of charge), it is obliged to buy additional certificates on the market. If it fails to do so, it must pay a penalty fee of €40 per ton of CO₂ emitted and the missing certificates additionally have to be bought on the market. If the emissions of an installation fall below the level of allocated emission certificates, the certificates can be sold on the market. Discussions have recently started on the allocation of allowances for the second phase of the emissions trading scheme, which is scheduled to run from 2008 to 2012.

Most EU member states have already transposed the Emissions Trading Directive into national law. In Germany, in July 2004 the German Parliament passed the so-called Greenhouse Gas Emissions Trade Act (Treibhausgas-Emissionshandelsgesetz or “TEHG”) and in August 2004 the Allocation Act 2007 (Zuteilungsgesetz 2007 or “ZuG 2007”), which consists of methods of permit allocation and application procedures, came into force. Most of E.ON Energie’s gas-, oil- and coal-powered generating facilities are covered by the new legislation. In addition, E.ON Ruhrgas operates several compressor stations with a thermal capacity exceeding 20 MW which are covered by the legislation. Pursuant to ZuG 2007, E.ON Energie and E.ON Ruhrgas applied for the necessary CO₂ emission certificates by year-end 2004. The results of the allocation of CO₂ emission certificates for E.ON Energie’s covered facilities by the competent authority (Deutsche Emissionshandelsstelle or “DEHSt”) are generally acceptable to E.ON. However, E.ON Energie has filed lawsuits against the DEHSt with respect to the allocation of CO₂ emission certificates at certain installations. Currently, the number of certificates granted to E.ON Energie’s covered facilities nearly covers its emissions, with a slight shortfall. The actual shortfall at any time, however, depends on a number of influence parameters, e.g., availability of plants, weather conditions, electricity demand, electricity exports and fuel prices. E.ON considers the results of the allocation of CO₂ emission certificates for E.ON Ruhrgas’ covered facilities to be generally acceptable.

Outside Germany, CO₂ emission certificates have also been allocated in Sweden, Finland and the Netherlands. In the United Kingdom, an initial allocation of certificates has been made, although the U.K. government is considering an appeal of its CO₂ emissions allocation to try to claim additional allowances. Although the Company is generally satisfied with the allocations, E.ON Benelux has filed an objection for a single installation.

The implementation of the Emissions Trading Directive took effect in 2005. Since the CO₂ emissions trading market is still a developing market, the Company cannot currently predict how the trading of CO₂ emission certificates will develop or what long-term impact, if any, the new regime may have on the Company’s financial condition and results of operations. Currently, the Company does not generally expect the emissions trading scheme to have a significant negative impact on its operations. However, in 2005, companies of both the U.K. and Central Europe market units had to purchase additional CO₂ emission certificates on the market, with a resultant increase in operating costs. For more information, see “Item 5. Operating and Financial Review and Prospects — Results of Operations — Year Ended December 31, 2005 Compared with Year Ended December 31, 2004.” By the end of 2005, CO₂ emissions trading was possible between 15 member states of the European Union. For more information about the Company’s trading operations, see “— Business Overview — Central Europe — Trading,” “— U.K. — Energy Wholesale — Energy Trading” and “— Nordic — Trading.”

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 must transpose the Security of Supply Directive into national law by February 24, 2008.

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 EU Commission, which will have the authority to revise the rules annexed to the regulation. The regulation will apply from July 1, 2006, except for provisions concerning amendment of the rules in the regulation annex, which will apply as of January 1, 2007.

The European Commission has also proposed a directive on energy end-use efficiency and energy services. The text of the directive, which has already been agreed upon and is expected to be adopted during 2006, foresees indicative targets for member states to reduce overall end energy consumption by nine percent over a nine year period, which would be achieved by boosting energy efficiency measures in the EU.

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 is 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.

Markets in Financial Instruments Directive

The Markets in Financial Instruments Directive (“MiFID”), which substantially revises the existing Investment Services Directive, was adopted by the EU in April 2004. The original implementation deadline has been postponed and member states are now required to implement MiFID by May 1, 2006. This new legislation is then scheduled to apply to the relevant companies by November 1, 2007.

MiFID establishes high level organizational and conduct of business standards that apply to all investment firms, including the application of EU capital adequacy standards. The extension of regulation to include commodity derivatives and investment advice are two notable features of the directive which potentially affect energy firms which are active in the trading business. There are, however, a number of exemptions which could apply to energy firms, depending on how MiFID is eventually implemented in the member states. The Company cannot currently predict how the implementation of MiFID may affect its operations.

GERMANY: ELECTRICITY

The Electricity Feed-in Law and the Renewable Energy Law

Under the amended German Stromeinspeisungsgesetz (law governing renewable electricity fed into the power network, or “Electricity Feed-In Law”), which came into effect in 1991, all regional utilities with standard rate customers were required to pay for energy produced from renewable resources, including wind-generated electricity, fed into the network. The price paid by the regional utility to the generator of renewable energy, determined by the average electricity price to the end user nationwide, typically exceeded the regional utilities’ procurement costs, thereby forcing regional utilities to pay part of the costs of renewable sources of energy. Regional utilities in whose supply area the feeding plants are located had to bear these costs.

As this led to distortions in competition, the German Parliament passed another change in the Electricity Feed-in Law, which came into effect April 1, 2000. Important aspects of the changed law, which is called the Renewable Energy Law, include:


	•	Fixed charges for renewable energies: Charges for renewable energies are fixed. For wind turbines coming online in 2006, the charge is fixed at 8.36 €cent/kWh. This charge is limited in time, with a general term of five years that may be extended up to 20 years depending upon the actual production volume of the installation. After five years, the charge is reduced to 5.28 €cent/kWh if 150 percent or more of a reference production, which is the potential production of the installed wind turbine operating with a constant wind speed of five meters per second over five years, has been produced. In addition, the fixed charge is reduced by two percent for new wind turbines every year. For wind turbines coming online in 2007, this means a reduction to 8.19 €cent/kWh and 5.17 €cent/kWh respectively.

	•	National burden sharing: The Renewable Energy Law assumes that the subsidy obligation would be passed on in full to the supplying companies. At the transmission company level, there is an equalization process covering the whole country. Each transmission company first determines how much electricity it takes up under the Renewable Energy Law and how much electricity in total flows in its region to end users. An equalization will then be effected among all transmission companies so that all transmission companies take on and subsidize proportionally equivalent amounts of renewable electricity under the statute. The transmission company will then pass these quantities of electricity and the corresponding costs on to the suppliers delivering electricity to end users in its region in proportion to their respective sales.

The Renewable Energy Law abolished regional differences in electricity costs for consumers and the related competitive disadvantages for E.ON Energie. However, the growing production of energy from wind turbines has led to growing costs for balancing power, network extensions and back-up power for power stations that have to be kept in reserve. This became a growing burden for E.ON Energie, since almost half of Germany’s wind

turbines are situated in the network control area of E.ON Energie AG, an area that meets approximately 30 percent of German electricity demand.

In August 2004, an amendment of the Renewable Energy Law came into force which partially addressed this burden by introducing an obligation for the transmission system operators to share the effort of balancing power by equally distributing the feed-in of electricity from wind power according to the electricity consumption in the area of each transmission system operator. As a result of this burden sharing mechanism, E.ON Energie is able to pass a certain amount of balancing costs on to other network operators. Other costs caused by renewable energy (network extension and back-up power) are, however, currently not part of the national burden sharing mechanism. E.ON Energie believes that the charges for renewable energies are still too high and that competition which would bring down the cost of renewable energy generation has not developed.

In two court rulings dated December 22, 2003, the German Federal Court of Justice found that contractual provisions used by E.ON’s competitor RWE to impose taxes and levies upon the customer (so-called “Steuer- und Abgabeklauseln”) also apply to the additional burdens placed on electric power companies by the Renewable Energy Law, despite the fact that those burdens are neither taxes nor levies in a legal sense. Although E.ON was not a party to the proceedings that resulted in these rulings, it believes these rulings could be a legal base for all German electric power companies to pass the costs imposed by the Renewable Energy Law on to their customers.

Co-Generation Protection Law

In order to protect existing CHP plants and give incentives to improve them, the German Parliament passed a new Co-Generation Protection Law (Kraft-Wärme-Kopplung-Gesetz) on March 1, 2002, which came into effect on April 1, 2002 and replaced the former Co-Generation Protection Law of May 2000. The new law, which will expire at the end of 2010, requires local network operators to pay CHP plants the following bonus payments for electricity that is produced in combination with heat and fed into the public network:


	•	CHP plants that were commissioned before 1990 received 1.53 €cent/kWh in 2002 and 2003 and 1.38 €cent/kWh in 2004 and 2005, and will receive 0.97 €cent/kWh in 2006;

	•	CHP plants that were commissioned after 1990 received 1.53 €cent/kWh in 2002 and 2003 and 1.38 €cent/kWh in 2004 and 2005, and will receive 1.23 €cent/kWh in 2006 and 2007, 0.82 €cent/kWh in 2008, and 0.56 €cent/kWh in 2009;

	•	CHP plants that are modernized received 1.74 €cent/kWh in 2002, 2003 and 2004 and 1.69 €cent/kWh in 2005, and will receive 1.69 €cent/kWh in 2006, 1.64 €cent/kWh in 2007 and 2008, and 1.59 €cent/kWh in 2009 and 2010; and

	•	Small CHP plants with an installed capacity of less than two MW received 2.56 €cent/kWh in 2002 and 2003 and 2.4 €cent/kWh in 2004 and 2005, and will receive 2.25 €cent/kWh in 2006 and 2007, 2.1 €cent/kWh in 2008 and 2009, and 1.94 €cent/kWh in 2010.

The local network operators are in turn allowed to pass on the costs of the bonus payments to the network operators, which may pass on the costs of the bonus system to their customers. A nationwide equalization process among the utilities was implemented in order to ensure the equal distribution of the costs of the bonus system across utilities. In 2005, every consumer had to pay an additional approximately 0.336 €cent/kWh (including VAT). Industrial customers with an electricity consumption of more than 10,000 MWh and electricity costs higher than 15 percent of their total turnover had to pay only 0.05 €ct/kWh for that portion of their electricity consumption exceeding 10,000 MWh per year. For those customers whose electricity costs are higher than 4 percent of their total turnover, this fee for electricity consumption exceeding 100,000 kWh per year is limited to 0.025 € cent/kWh. In 2004, the government together with the utilities started a monitoring process to evaluate the extent to which CO₂ emissions have been reduced as a result of this law and whether the current bonus payments are adequate. The results of this monitoring process have not yet been published.

The European Union has passed a co-generation directive in order to promote the use of co-generation and thereby increase energy efficiency and reduce CO₂ emissions. The directive corresponds largely to the German national CHP legislation and will not require a change in current German law.

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 “— Revisions of the German Energy Law” above.

Electricity Network Charges

As described in “— 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. To obtain approval for network charges to be used in 2006, network operators had to submit the calculated charges to the BNetzA by the end of October 2005. Network operators may apply the currently valid network charges until BNetzA approves the new charges.

Electricity Rate Regulation

Prices at which local and regional distributors sell electricity to standard-rate and smaller industrial customers are currently regulated by the economics ministries of each of the German states (as provided in the Federal Electricity Charge Regulation (Bundestarifordnung Elektrizität, or “BTO Elt”)). The rates are set at a level to assure an adequate return on investment on the basis of the costs and earnings of the electricity company. However, these governmentally-set ceiling rates do not completely represent the actual market situation, with numerous rates offered which are designed to meet different customers’ special needs. 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 VDEW, 18.66 €cent per kWh in 2005 (all taxes included), while E.ON Energie charged an average of 18.84 €cent per kWh. The average price quoted by the German Association for Energy Consumption (“VEA”) for industrial customers was 9.06 €cent per kWh, while the average price per kWh charged by E.ON Energie was 9.42 €cent per kWh, as quoted by VEA as of July 1, 2005 (net of tax). Pursuant to the Energy Law of 2005, electricity rate regulation will be abandoned on July 1, 2007.

Prices for sales of electricity by E.ON Energie to regional electricity companies, municipal utilities and large industrial customers are not regulated by the BTO Elt; however, they are governed by the GWB, which requires that no patently unreasonable rates are set.

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 Ruhrgas Transport on November 1, 2004. For more information, see “— Business Overview — 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 “— Revisions of the German Energy Law” above. Under the Energy Law of 2005, gas network operators have to offer an entry/exit system. In order to comply with this requirement, E.ON Ruhrgas Transport has adjusted its entry/exit system with the introduction of the new “ENTRIX 2” system on February 1, 2006.

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Gas Network Charges

As described in “— 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. To obtain approval for network charges to be used in 2006, network operators had to submit the calculated charges to the BNetzA by the end of January 2006. Network operators may apply the currently valid network charges until BNetzA approves the new charges.

The Energy Law of 2005 provides an exemption from cost calculations for gas transmission networks if actual or potential pipeline competition can be proved. E.ON Ruhrgas Transport sent an application for such an exemption to the BNetzA in January 2006.

Gas Rates

Gas and heat rates are not regulated in Germany, but the GWB does apply.

For information about proceedings regarding gas price calculations, e.g. against E.ON Hanse, see “Item 3. Key Information — Risk Factors — External.”

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 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 Gas Act 1986 (as amended), as appropriate. The Authority has power to impose financial penalties on licensees and/or make 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.

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.

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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 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 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 Powergen Retail Limited 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. The supply license used to place price controls on supply; however, these price controls lapsed after March 31, 2002. Following the end of the price controls, 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.

A separate supply license is held by E.ON UK, trading as E.ON Energy, 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 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 Powergen Retail Limited and E.ON UK.

In June 2005, E.ON UK acquired the electricity supply company of Economy Power. Former customers of Economy Power are currently supplied under a separate electricity supply license but are being migrated to the supply licenses held by Powergen Retail Limited and E.ON UK.

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 anticipating that about 60 percent of its expenditures will be on home insulation. The U.K. government estimates that the cost to suppliers of this requirement will be about GBP9 per year for each of their gas and electricity customers, although the actual cost will depend on the cost to suppliers of contracting for energy efficiency measures, which is to some extent uncertain.

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

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apply to the Secretary of State for a direction requiring the pipeline owner to make spare capacity available to the third party.

NORDIC

Sweden

Electricity. The main 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.

The Electricity Act promotes competition by creating opportunity for customers to enter into agreements 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”), which is part of the Swedish Energy Agency, 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 the 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 connection fee and an hourly transmission 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 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, the model is used for assessing the performance of the local networks only, but EMI intends to include the regional networks in the near future.

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 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 has decided that E.ON Sverige must reduce the network charges for 2003 by SEK19.7 million, by repaying customers a portion of the network charges. E.ON Sverige has appealed the decision to the relevant administrative court. With respect to 2004 network charges, EMI decided in October 2005 to prolong its inspection of 4 distribution areas within E.ON Sverige. EMI has not issued a final decision regarding 2004 network charges.

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

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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 the 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 came into force on January 1, 2006, a customer shall be compensated for power outages that last more than 12 hours by at least 12.5 percent and up to 300 percent of the customer’s annual network charges. With effect from January 1, 2011, the maximum allowable period of time for a power outage will be 24 hours.

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 may choose their gas supplier. Household customers will be eligible as of 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 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 examination by EMI ex-post. EMI is currently developing a model for assessing the revenues from network charges. The first examination will take place in 2007 regarding revenues for 2006. If EMI finds that revenues from network charges are not reasonable, it can obligate the operator to reduce network charges.

Renewable Energy and Electricity Certificates. The Swedish electricity certificate system has been in operation since May 2003. The objective of the current system, which is based on the Swedish Act on Electricity Certificates (SCS 2003:313), is 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 during 2005. The amendment proposals and Parliament approval are expected during 2006. For more information about the current system and proposed changes, see “— Business Overview — Nordic — Market Environment.”

Finland

The main legislation applicable to the Finnish electricity industry is the Electricity Market Act (Sähkömarkkinalaki (386/1995), or the “Electricity Market Act”), which came into effect in June 1995. The Electricity Market Act pre-dated the requirements of the First Electricity Directive, but is basically consistent with the terms of that directive. The purpose of the Electricity Market Act is to ensure preconditions for an efficiently functioning electricity market so as to secure the sufficient supply of high-standard electricity at reasonable prices. The Electricity Market Act contains regulations for distribution and transmission companies with regard to electricity network licenses, general obligations and pricing principles for network operation, systems responsibility, balance responsibility and balance determination, construction of electricity networks, retail sale of electricity and unbundling of operations. Under the Electricity Market Act, generation, retail and electricity trading are subject to competition, while transmission and distribution remain regulated natural monopolies. The

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Finnish government amended the Electricity Market Act at the end of 2004 because the legislation did not meet all the requirements of the Second Electricity Directive, in particular the requirement for legal unbundling.

The Finnish energy regulator, the Energy Market Authority (“EMA”), is an expert body subordinate to the Finnish Ministry of Trade and Industry. Its operation started in June 1995, at the same time as the Electricity Market Act took effect.

Electricity and natural gas network operation in a specific geographical area is subject to license, with only one license allowed per specific geographical area. The EMA grants network licenses to utilities engaged in distribution operations. Moreover, the EMA also grants permits for constructing high voltage power lines.

The pricing of network services, such as connection, distribution and metering, must be public, reasonable, non-discriminatory and regionally impartial. The EMA supervises and monitors the pricing of transmission and distribution services of the regional network operators and the national grid. Moreover, the EMA also intervenes in the terms and prices of network services that are considered to restrict competition. The EMA can forbid a network operator from applying a pricing system that does not meet requirements and can obligate the company to correct its pricing within three months. The EMA itself cannot impose any penalty on network operators.

In order to comply with all of the requirements of the Second Electricity Directive, the Finnish government has revised the regulations on pricing supervision with effect from January 1, 2005. The revised act (Laki sähkömarkkinalain muuttamisesta No. 1172) also requires the legal unbundling of distribution operators that have a network capacity over 200 GWh and functional unbundling for operators serving over 100,000 customers. The new regulation provides for evaluation of the reasonableness of distribution pricing based on the network operator’s rate of return, combined with efficiency requirements. The reasonableness of distribution pricing is evaluated ex-post. In cases where the EMA determines that over-charging has occurred, network operators must return the excess profits to customers. The first regulatory period covers the years 2005-2007, with a four year period to follow. The EMA has set allowed annual profits for this period; the allowed income level is lower than in 2004. Distribution operators are not satisfied with the level of allowed income, and over 80 percent of the operators, including E.ON Finland, have appealed to The Market Court to change the EMA’s Regulatory Decision setting the earnings basis and level of regulated income. E.ON Finland expects a final resolution of this matter in 2006.

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 and Virginia State Corporation Commission, respectively, 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 less than 10 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.

On December 29, 2003, LG&E and KU filed general rate case applications with the KPSC seeking increases in regulated tariffs. LG&E’s last electric rate case was in 1990 and its last gas rate case was in 2000; KU’s last rate case was in 1983. LG&E requested an increase in its annual electric rates of an aggregate of $63.8 million or 11.3 percent and an increase in its annual gas rates of an aggregate of $19.1 million or 5.4 percent. KU requested an increase of an aggregate of $58.3 million or 8.5 percent. On June 30, 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

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base electric rates of approximately $46.1 million or 6.8 percent. The rate increases took effect on July 1, 2004. The Attorney General of Kentucky (“Kentucky Attorney General”) appealed these rate increases and opened an investigation into the communications between the companies and the KPSC which led to them. The KPSC granted a rehearing on a single issue appealed by the Kentucky Attorney General and also opened an investigation into the communications involved in the rate cases. In December 2005, the KPSC issued an order noting completion of its inquiry, including review of the Kentucky Attorney General’s investigative report. The order concluded no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted, concerning state tax rates used in calculating the granted rate increases. The resolution of this income tax issue is expected to fall within the range of earnings provided by the KPSC in its original order approving the rate increases. Upon resolution of this income tax issue on appeal at the KPSC, the initial rate increase order could then be subject to further appeal through the courts. Additional proceedings before the KPSC, and possibly Kentucky courts, regarding the rate increases are expected to continue during 2006. It is uncertain when such matters will be concluded or whether they will ultimately have an effect on the rate increase. Pending the results of such matters, LG&E and KU are charging customers the approved higher rates.

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.

Through December 31, 2003, the electric rates LG&E and KU charged in Kentucky were subject to an earnings sharing mechanism (“ESM”). The ESM was originally put in place for three years beginning January 1, 2000. The KPSC’s order approving new base rates effective July 1, 2004 terminated the ESM for all periods after 2003, but allowed for recovery of amounts requested through 2003. Under the ESM settlement, LG&E and KU were able to collect from customers approximately $13.0 million and $16.2 million, respectively, of ESM revenue earned in calendar year 2003, beginning in April 2004. No additional ESM amounts remain to be charged or recovered at this time.

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 (the “Clean Air Act”) and other environmental regulations. The magnitude of the surcharge fluctuates with the amount of approved environmental compliance costs incurred during each rate 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.

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Transmission Developments

A number of regional or industry-wide 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. In April 2005, the MISO implemented day-ahead and real-time markets (MISO Day 2), including a congestion management system, which are part of the FERC-required Transmission and Energy Markets Tariff (“TEMT”). MISO membership and operations, including the MISO Day 2 markets, have resulted in substantial changes, including increased costs, for LG&E and KU. In 2003, the KPSC initiated a proceeding examining the benefits and costs of LG&E’s and KU’s membership in MISO. In this KPSC proceeding, LG&E and KU requested an order directing their ultimate exit from MISO, if approved by the FERC and under other appropriate circumstances. In November 2005, in a separate proceeding, LG&E and KU filed applications with the KPSC for approval of certain proposed transmission and reliability arrangements effective upon any exit from MISO. Orders in the KPSC proceedings may occur during the first half of 2006. In October 2005, LG&E and KU submitted applications with the FERC seeking its authority to exit MISO and to transfer certain transmission functions to a reliability coordinator and an independent transmission organization. Various entities, including MISO and certain wholesale customers of LG&E and KU, filed interventions and protests with the FERC. LG&E and KU subsequently reached settlement agreements with the Kentucky wholesale customers addressing their post-exit concerns and such customers withdrew their protests. LG&E and KU have requested an order in early 2006 in the FERC proceeding, but no assurance can be given as to the ultimate timing of such an order.

At this time, LG&E and KU cannot predict the outcome or effects of the various proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the initial implementation of MISO Day 2 and TEMT markets since April 2005 remain difficult to fully quantify. One component, MISO-related administrative costs incurred by LG&E and KU, was approximately $12 million during 2005. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable. Should LG&E or KU exit MISO, current MISO rules may also impose an aggregate exit fee of up to $41 million depending on the timing and circumstances of actual withdrawal. While LG&E and KU believe legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

Energy Policy Act of 2005 and Repeal of PUHCA

The Energy Policy Act of 2005 (“EPAct 2005”) was enacted on August 8, 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.

The FERC was directed by the EPAct 2005 to adopt rules to address many areas previously regulated by other agencies under other statutes, including PUHCA. The FERC is in various stages of rulemaking on these issues and E.ON U.S. is monitoring these rulemaking activities and actively participating in applicable proceedings. In general, where FERC rules have been finalized, such rules similarly liberalize federal regulation or oversight in these areas. E.ON U.S. is still evaluating the potential impact of EPAct 2005 and PUHCA 2005 and the associated rulemakings and cannot predict what impact the legislation and such rulemakings will have on its operations or financial position.

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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 as is customary in these types of proceedings before the KPSC. Proceedings will continue in 2006, although no procedural schedule has been established.

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.

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, chemicals plants, waste disposal sites and chemicals warehouses. 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 liability can be reasonably estimated. The provisions made are considered 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: ELECTRICITY

Air Pollution. All of E.ON Energie’s plants are subject to EU and/or national regulations, and are equipped where necessary with pollution removal devices. The most important pollution law applicable to E.ON Energie’s German plants is the German Federal Pollution Control Act (Bundesimmissionsschutzgesetz, or “BImSchG”) and its implementing ordinances. One of such ordinances, the Ordinance on Large Combustion Plants (Verordnung über Großfeuerungsanlagen, or “13. BImSchV”), sets stringent emission limits for power stations for all known air pollutants, such as sulphur oxides (“SO_x”), NO_x and dust. The relevant emissions of E.ON Energie’s power plants are continuously measured and reported. Due to the extensive installation of scrubbers, catalysts, electrostatic precipitators and other pollution control devices, E.ON Energie’s power plants comply with all current requirements. In order to implement the EU environmental guideline 2001/80/ EU, the German government amended 13. BImSchV in 2004 to introduce lower emission limits. Because of the reduction in emission limits, especially for particulate emissions, some of E.ON Energie’s power plants require retrofitting of their instrumentation and/or electrostatic precipitators in order to comply with the amended ordinance. E.ON

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Energie expects to implement most of these retrofits between 2008 and 2011. The total cost of compliance is currently expected to be approximately €10 million, primarily for efficiency improvements in some electrostatic precipitators.

Emission trading for carbon dioxide started in the EU on January 1, 2005. For details on the Emissions Trading Directive, applicable German legislation and effects on E.ON Energie, see “— Regulatory Environment.”

Nuclear Energy. Details of E.ON Energie’s nuclear power operations in Germany and those of its 21 percent minority investee BKW in Switzerland can be found under “— Business Overview — Central Europe — Power Generation” and “— Other Minority Shareholdings” above. E.ON Energie does not own interests in or operate any nuclear power facilities in any other country. German safety standards for nuclear power stations are among the most stringent in the world. German nuclear power regulations are found in the AtG and a number of national regulations, guidelines and technical rules. The German regulatory framework regarding nuclear power regulations is also governed by international agreements, including the Euratom Agreement, dated March 23, 1957 (Euratomvertrag), the Paris Liability Agreement, dated July 29, 1960 (Pariser Haftungsübereinkommen), and the Non-Proliferation Treaty, dated July 1, 1968 (Nichtverbreitungsvertrag).

Under the AtG, the import, export, transportation or storage of nuclear materials (Kernbrennstoff) requires the approval and supervision of regulatory authorities. The building, operating, owning or materially altering by any entity of any plants or installations that produce, fission or otherwise process or reprocess nuclear materials (“Nuclear Plants”) also requires approvals of, and is supervised by, regulatory authorities. Approvals can be subject to limitations or conditions, including conditions subsequent, and may also be subsequently revoked if they are not complied with or one of their preconditions has ceased to exist. The regulatory authorities may also give orders to obtain information from, enter and inspect any Nuclear Plants.

According to the AtG, radioactive wastes and dismantled radioactive parts must either be recycled or permanently disposed of by any entity handling or otherwise using nuclear power. The AtG follows the so-called “polluter pays” principle, which requires such entity to pay for the recycling or permanent disposal of nuclear waste.

Liability. In case of environmental damages, the owner of a German facility is subject to liability provisions that guarantee comprehensive compensation to all injured parties. Because of achievements in pollution control, the issue of environmental damage due to air pollutants from electric utilities has not recently been a subject of public debate in Germany. In general, subjects such as acid rain, as well as high concentrations of ground level ozone have been linked to accumulated deposits from many emission sources or, in the case of the ozone, predominantly from traffic emissions. There has been some relaxation in the evidence required under the German Environmental Liability Law (Umwelthaftungsgesetz) to establish and quantify environmental claims. If claims were to arise in relation to environmental damages and plaintiffs were successful in overcoming problems of proof and other issues, such claims could result in costs to E.ON Energie that might be material. So far as E.ON Energie is aware, no material environmental claims have been made against it and, under current circumstances, E.ON Energie does not believe that there is a significant risk of material liability in respect of any potential claims.

In case of a nuclear accident in Germany, the owner of the reactor, the factory or the nuclear materials storage facility (the “Proprietor”) is subject to liability provisions that guarantee comprehensive compensation to all injured parties. Under German nuclear power regulations, the Proprietor is strictly liable, and the geographical scope of its liability is not limited to Germany or the contractual territory of the Paris Liability Agreement. The Proprietor is in principle subject to unlimited liability. The AtG and the Regulation regarding the Provision for Coverage pursuant to the AtG (Atomrechtliche Deckungsvorsorge-Verordnung, or “AtDeckV”) require every Proprietor to provide liability coverage by either insurance or financial security. The amount of coverage required is reevaluated every five years. In February 2002, the AtG was amended and the required liability coverage was increased from €256 million to €2.5 billion. E.ON Energie has insurance covering the first €256 million of damages. To provide liability coverage for the additional amounts required by the AtG amendment, the German nuclear power plant operators entered into a solidarity agreement to cover the increase, which provides that the costs of liability exceeding the operator’s own resources and those of its parent company in the event of a nuclear

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accident will be covered by a pool, with the nuclear facility operators having a mutual responsibility to cover each other’s damages. For details, see Note 25 of the Notes to Consolidated Financial Statements. For this reason, the AtG amendment has resulted in only a slight cost increase for liability coverage.

GERMANY: GAS

Air Pollution. The construction and operation of E.ON Ruhrgas’ gas pipeline system is subject to EU and national law, rules and regulations. The most important pollution law applicable to E.ON Ruhrgas’ gas transport and storage facilities is the BImSchG and its implementing ordinances. E.ON Ruhrgas’ facilities comply with all of the current requirements. One of such ordinances, 13. BImSchV, was amended in 2004 to require reduced emission limits also for existing gas turbines for air pollutants such as NO_x and carbon monoxide (by 2015). For more information, see “— Germany: Electricity.” E.ON Ruhrgas uses gas turbines to drive compressors for gas transportation and storage. If the turbines do not comply with the new emission limits, E.ON Ruhrgas will have to take measures to retrofit the non-complying turbines. E.ON Ruhrgas cannot currently quantify the measures that will be required by the amendment of 13. BImSchV. Any other amendments to or new environmental legislation that creates new or more stringent environmental standards could also affect the future operation of E.ON Ruhrgas’ facilities and related costs.

Emission trading for carbon dioxide started in the EU on January 1, 2005. For details on the Emissions Trading Directive, applicable German legislation and effects on E.ON Ruhrgas, see “— Regulatory Environment.”

Gas Storage. Natural gas underground storage facilities in Germany are subject to the 12th Ordinance on the Implementation of the German Federal Pollution Control Act (12. Verordnung zur Durchführung des Bundesimmissionsschutzgesetzes, or Störfallverordnung), which came into force in May 2000. Since then, all facilities operated by E.ON Ruhrgas have complied with all relevant requirements. Further compliance is continuously measured and reported by public authorities.

For information on E.ON Ruhrgas’ environmental management system, see “— Business Overview — Pan-European Gas — Transmission and Storage.” For information on the German Environmental Liability Law, see “— Germany: Electricity” above.

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 SO₂, NO_x 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 allows each member state to include all its existing large coal and oil combustion plants within a single National Emissions Reduction Plan. Last year the U.K. government discussed using a “combined approach” with the European Commission, 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). The European Commission has accepted this approach and the U.K. government is expected to submit the U.K. plan to the European Commission during early 2006. E.ON UK has decided to opt out the Grain, Kingsnorth and Ironbridge power stations 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 is implementing 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 “ —

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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 draft regulations for implementing the trading scheme were initially published in January 2004, releasing for consultation a draft National Allocation Plan which includes the proposed allocation of CO₂ emissions certificates for E.ON UK’s plants and for other power stations in the U.K. Following this, the U.K. government recalculated and increased the size of its requested allowance for CO₂ emission certificates, but the European Commission chose not to increase the allowance. The matter has been referred to the EU Court of First Instance, which asked the Commission to reconsider its position. The Commission has announced its is not prepared to change its position, which leaves the U.K. government with the option of launching an appeal to try to claim the additional allowances.

Each of E.ON UK’s fossil-fuelled power stations in the United Kingdom is required to have an Integrated Pollution Control Authorization, issued by a government agency, which regulates releases into the environment and seeks to minimize their impact. The current system of authorizations is to be 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. Existing power stations are to be brought under the newly-expanded Integrated Pollution Prevention and Control regime during 2006. E.ON UK is currently in the process of applying for these permits for its generation sites.

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 renewed on November 1, 2004 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. The oil storage regulations require E.ON UK to ensure that oil is appropriately stored and managed.

NORDIC

Air Pollution. The power and heat production plants of E.ON Sverige and E.ON Finland are subject to EU, international and/or national regulations, and are equipped where necessary with pollution removal devices. In Sweden and Finland, production plants are subject to emission limits for air pollutants such as SO_x, NO_x and dust.

In Sweden, there are taxes attached to emitting SO_x (for coal, oil and peat) and CO₂ (applicable primarily to heat production from coal, oil, natural gas and liquified petroleum gas). There is also a fee for emitting NO_x (applicable to large combustion plants). In Finland, excise taxes are applied to the different fuels according to their carbon content. There are also limits for the sulphur content of coal and oils to be used in energy generation.

The relevant emissions of E.ON Sverige’s and E.ON Finland’s power and heat production plants are continuously measured and reported.

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 Sverige and E.ON Finland 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

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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 Financing of Future Expenses for Spent Nuclear Fuel (SFS 1992:1537). 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 Authority, which supervises all nuclear facilities in Sweden.

According to the Act on Financing of Future Expenses for Spent Nuclear Fuel, 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 25 of the Notes to Consolidated Financial Statements.

For more information about E.ON Sverige’s nuclear power operations, see “— Business Overview — Nordic — Power Generation.” E.ON Sverige does not own interests in or operate any nuclear power facilities in any country other than Sweden, and E.ON Finland does not own interests in or operate any nuclear power facilities.

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, 2005, the liability is limited to an amount equal to SEK3,401 million (€362 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.

Currently, a government investigation is ongoing regarding nuclear liabilities. To date, it is unclear to what extent this investigation will lead to an adjustment of the nuclear liability limit in Sweden.

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.

The Clean Air Act Amendments of 1990 imposed stringent SO₂ and NO_x emission limits on electric generating units located in the United States. LG&E had previously installed flue gas desulphurization equipment on all of its generating units, while KU met its Phase I SO₂ requirements primarily through installation of flue gas desulphurization equipment on Ghent Unit 1. E.ON U.S.’s combined strategy for Phase II, which commenced on January 1, 2000, uses accumulated emissions allowances to defer additional capital expenditures and also includes fuel switching or the installation of additional flue gas desulphurization equipment. LG&E and KU met the initial NO_x emission requirements of the Clean Air Act through installation of low-NO_x burner systems. E.ON U.S.’s compliance plans are subject to many factors, including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control 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.

In September 1998, the EPA announced its final “NO_x SIP Call” rule requiring reductions in NO_x emissions of approximately 85 percent compared with 1990 levels, in order to mitigate alleged ozone transport to the northeastern United States. In related proceedings in response to petitions filed by various northeastern states, in December 1999 the EPA issued a final rule directing similar reductions from a number of specifically named electric generating units, including all LG&E and KU power stations in the eastern half of Kentucky. To implement the new federal requirements, in June 2002 Kentucky revised its State Implementation Plan (“SIP”) to

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require electric generating units to reduce their NO_x emissions to 0.15 pounds weight per million British thermal unit (“lb./ MMBtu”) on a system-wide basis.

In order to achieve the NO_x emission reductions mandated by the NO_x SIP Call as enacted by the Kentucky SIP, E.ON U.S. has implemented a NO_x control plan for its LG&E and KU generating units. Installation of additional NO_x controls, including selective catalytic control technology, began in 2000. Appropriate NO_x control equipment was placed into service by the May 2004 compliance deadline. E.ON U.S. estimates that it will incur total capital costs of approximately $407 million through 2006 (of which approximately $405 million was incurred through year-end 2005) to reduce its NO_x emissions to the 0.15 lb./ MMBtu level on a company-wide basis. With respect to costs incurred at LG&E and KU, in April 2001 the KPSC granted recovery of these costs under their environmental surcharge mechanisms.

In March 2005, the EPA announced its final Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”). CAIR requires additional SO₂ emission reductions of 70 percent and NO_x emission reductions of 60 percent compared with 2003 levels. CAIR provides for a two-phase cap and trade program, with initial reductions of NO_x and SO₂ emissions due by 2009 and 2010, respectively, and final reductions due by 2015. The closely related CAMR rule provides for mercury emission reductions of almost 70 percent compared with 2003 to be achieved in two phases, with initial reductions due by 2010 and final reductions by 2018. The 2010 CAMR mercury reduction targets are set at a level consistent with reductions that will occur as a “co-benefit” of the controls installed for purposes of compliance with CAIR. E.ON U.S. is carefully monitoring pending appeals of the CAIR and CAMR rules and related regulatory proceedings, including adoption of the rules at the state level, that could affect implementation of the rules.

In order to achieve the emissions reductions mandated by CAIR and CAMR, E.ON U.S. expects to incur additional operating and maintenance costs in operating new NO_x controls and expects to make additional capital expenditures to reduce SO₂ emissions totaling $743 million through 2009. In June 2005, the KPSC granted recovery of these costs incurred by LG&E and KU under their environmental surcharge mechanisms.

E.ON U.S. believes its costs in reducing SO₂, NO_x and mercury emissions to be comparable to those of similarly situated utilities with like generation assets.

Certain E.ON U.S. power plants are situated in or adjacent to counties which the EPA has designated as being in non-attainment with the 8-hour ozone and particulate matter 2.5 ambient air quality standards. Various state and local agencies are currently in the process of developing plans which may mandate emissions reductions from a range of air emissions sources in order to achieve compliance with the ambient air quality standards. Depending on the provisions ultimately incorporated into state and local implementation plans, certain E.ON U.S. power plants could potentially be subject to requirements for additional reductions in SO₂ and NO_x emissions. The effect on E.ON U.S. of such rules is not yet determinable, but could include increased capital expenditures and operating costs in the future.

E.ON U.S. is also monitoring several other air quality issues that may potentially impact coal-fired power plants. These include the appeal of the District of Columbia Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter and measures to implement the EPA’s Clean Air Visibility Rule.

From time to time, E.ON U.S. conducts negotiations with the EPA or various state or local regulatory authorities to resolve matters involving compliance with applicable environmental laws and regulations. Such matters include the effectiveness of remedial measures aimed at controlling particulate matter emissions at LG&E’s Mill Creek Station, remediation obligations for former manufactured gas plant sites, liability under the Comprehensive Environmental Response, Compensation and Liability Act for various off-site waste sites, and settlement of the government’s claims relating to a fuel oil discharge at KU’s Brown Station. Based on negotiations to date, the resolution of such matters is not expected to have a material impact on the operations of E.ON U.S.

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OPERATING ENVIRONMENT

As Germany’s second-largest industrial group on the basis of market capitalization, all social, political and economic developments and conditions in Germany affect E.ON. Labor costs, corporate taxes and employee benefit expenses in Germany are high and weekly working hours are shorter compared with most other EU member states, the United States and Japan. Nonetheless, many factors, including monetary and political stability, high environmental protection and standards and a well-educated, highly qualified workforce continue to positively affect Germany’s competitive position in world trade.

By virtue of its operations outside the European Monetary Union (“EMU”), the Group is also subject to the risks normally associated with cross-border business transactions and business activities, particularly those relating to exchange rate fluctuations. In addition, because most of the Group’s operations are based in Europe, both the development of the European market and the entry of new members into the EU will continue to create new opportunities and challenges for E.ON.

ECONOMIC BACKGROUND

Germany

During 2005, the general economic situation improved worldwide, although less dynamically than in 2004. German export performance was good as a consequence of improved worldwide economic conditions and the depreciation of the euro and despite the surge in oil prices. Domestic demand, however, remained unchanged compared with 2004. As a result, the German economy again had one of the worst performances in the Eurozone in 2005. The real gross domestic product increased by 0.9 percent, compared with an increase of 1.6 percent in 2004. Capital spending by businesses decreased by 0.3 percent, mainly due to the continuing recession in construction. Other investment grew by 1.4 percent. The German Council of Economic Advisers forecasts ongoing global economic growth in 2006, with a German growth rate of 1.0 percent in 2006.

Germany’s competitive position in world trade continues to benefit from many factors, including monetary stability, a reputation for quality and recent productivity gains. In 2005, Germany achieved a surplus in exports and services in real terms of €109 billion. Due to weak economic growth and lack of structural reforms, however, unemployment remained high in Germany in 2005. The reasons for unemployment are predominantly of a structural nature and include, among other factors, extensive regulation of the labor market and high labor costs (compared with the rest of the EU and the United States).

For information on the tax regime applicable to German corporations, see “Item 10. Additional Information — Taxation — Taxation of German Corporations.” For information on changes in German tax regulation that have a material impact on the Company, see Note 7 of the Notes to Consolidated Financial Statements.

Europe

In 1992, the twelve original members of the former European Economic Community signed the Treaty on European Union (the “Treaty”), a significant step toward creating a single integrated market. The Treaty provided a working program for European integration, including the coordination of economic policies of the EU countries and preparations for the introduction of a single currency. On January 1, 1999, Germany, Spain, France, Ireland, Italy, Luxembourg, the Netherlands, Austria, Portugal and Finland (the “participating countries”) adopted the euro as their single currency through the EMU, with fixed exchange rates for the participating currencies (the “legacy currencies”) against the euro. In the beginning of 2001, Greece also joined the EMU, becoming a participating country. On January 1, 2002, the euro became the official legal tender for cash transactions in all participating countries. The legacy currencies have been withdrawn from circulation. Not all EU member states participate in the EMU. The United Kingdom, Sweden and Denmark chose not to be initial participants in the euro.

Since the ratification of the Treaty, the EU has been enlarged from 12 to 25 member states, with the entry of Austria, Finland and Sweden in January 1995 and Cyprus, the Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta, Poland, Slovakia and Slovenia as of May 1, 2004. As new countries join the EU, significant institutional reform within the existing EU member states will be necessary to enable the EU to integrate the new

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members. As a first step, an EU convention drafted a treaty establishing a European Constitution. The new Constitution, which includes significant institutional reforms of the EU Commission and the EU policy-making process, was defeated in national referendums in France and the Netherlands in 2005. Currently, the ratification process is at a standstill.

In addition to the countries which joined in May 2004, the European Council has invited Bulgaria and Romania to join the EU in 2007. Negotiations with Croatia to join the EU began in 2005, although further institutional reforms must be implemented in Croatia before it also may join the EU. In October 2005, the EU also started negotiations with Turkey to join the EU. Since these negotiations may take years, there is no fixed date for Turkey to join the EU.

Long-term interest rates in the Eurozone decreased by 0.16 percentage points in 2005 compared to December 2004. In December 2005 the European Central Bank raised its deposit facility and margin lending rates to 1.25 percent and 3.25 percent, respectively.

United Kingdom

The U.K. economy performed better in 2005 than in most other EU economies although household demand and public and private expenditures were weaker than in 2004. Monetary and fiscal policy provided a stable macroeconomic environment, so that prospects for 2006 are quite good. The U.K. economy is estimated to have grown at a rate of 1.7 percent in 2005 in real terms, according to the German Council of Economic Advisers. This is expected to increase to a growth rate of 2.4 percent in 2006. Inflation in 2005 is estimated to have been at 2.4 percent.

Sweden/Finland

In 2005, the Swedish economy again performed well above average compared with other EU member states, driven by a robust investment performance, although exports were weaker than in 2004. The Swedish economy is estimated to have grown at a rate of 2.5 percent in real terms, according to data from the German Council of Economic Advisers. This is expected to increase to a growth rate of 3.0 percent in 2006. Finland performed slightly better than the EU average, with an estimated real growth rate of 1.7 percent driven by strong domestic demand. Finland’s growth rate is expected to increase to 4.1 percent in 2006, according to the German Council of Economic Advisers. Inflation remained low in both countries, with an annual rate of 0.7 percent in Sweden and 1.0 percent in Finland for 2005.

United States

Since 2003, the United States’ economic growth has increased, stimulated by expansive fiscal and monetary policies. In 2005, private consumption remained strong, but business investment weakened slightly. Despite tighter monetary policy, interest rates remained relatively low in 2005, supporting growth. The United States is estimated to have grown at a rate of 3.6 percent in 2005, with a slight decrease to 3.0 percent expected in 2006, according to the German Council of Economic Advisers. Inflation remained under control despite higher energy prices, with an annual rate of 3.4 percent for 2005.

RISK MANAGEMENT

While E.ON’s market units have varying exposures to fluctuations in exchange rates, on an overall basis E.ON has certain exposures mainly to fluctuations between the euro and the U.S. dollar, the British pound, the Swedish krona and the Norwegian krona, respectively, that it seeks to manage through hedging activities. Foreign exchange rate risk management, along with liquidity management and interest rate risk management, is generally centralized on a Group-wide basis and is the responsibility of the Group treasury. The currency and interest rate risks of Group companies are hedged with Group treasury in conformity with E.ON’s financial guidelines, or, in certain cases, with external counterparties with E.ON AG’s approval. E.ON uses interest rate and currency derivatives only to hedge its risk positions deriving from underlying business transactions, and E.ON continually assesses its exposure to these risks resulting from the underlying exposures and the results of hedging

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transactions. Moreover, E.ON is exposed to risks from fluctuations in the prices of commodities and raw materials which are subject to commodity risk hedging activities. The market units also engage in the trading of energy-related commodity derivatives, which is also subject to guidelines for risk management. For a more detailed discussion of the current exchange rate, interest rate and commodity price risk exposures and risk management policies of the Group, see “Item 5. Operating and Financial Review and Prospects — Exchange Rate Exposure and Currency Risk Management,” “Item 11. Quantitative and Qualitative Disclosures about Market Risk” and Notes 28 and 29 of the Notes to Consolidated Financial Statements.

ORGANIZATIONAL STRUCTURE

E.ON AG is the Group’s Düsseldorf-based management holding company. E.ON AG provides strategic management for Group companies and coordinates Group activities. E.ON AG also provides centralized controlling, treasury, risk management (including hedging) and service functions to Group members, as well as communications, capital markets and investor relations functions. The Group’s operating activities are organized into market units, each of which is responsible for managing its own day-to-day business. The following table sets forth certain information about each of the entities which served as a parent company of an E.ON market unit as of December 31, 2005:


			Percentage			Percentage
	Country of		Ownership Interest			Voting Interest
Name of Subsidiary	Incorporation		held by E.ON			held by E.ON

E.ON Energie AG (energy)		Germany		100.0	%		100.0	%
E.ON Ruhrgas AG (energy)		Germany		100.0	%		100.0	%
E.ON UK plc (energy)		U.K.		100.0	%		100.0	%
E.ON Nordic AB (energy)		Sweden		100.0	%		100.0	%
E.ON U.S. LLC (energy)		U.S.A.		100.0	%		100.0	%

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, 2005, the total amount of indebtedness collateralized by these facilities was approximately €0.8 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.

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 36,400 MW, E.ON Energie’s attributable share of which is approximately 27,800 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 “— Business Overview — 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 90.1 percent of available capacity in 2005. 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.

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Pan-European Gas

E.ON Ruhrgas owns, co-owns or has interests through project companies in gas pipelines in Germany totaling 11,273 km. In addition, E.ON Ruhrgas owns, co-owns or has interests through project companies in 34 compressor stations in Germany. The current installed capacity of these compressor stations totals 938 MW. E.ON Ruhrgas also owns, co-owns, leases or has interests through project companies in 11 underground gas storage facilities in Germany; E.ON Ruhrgas’ share in the usable working gas storage capacity of these facilities is approximately 5.1 billion m³. Due to the number and complexity of factors influencing gas pipeline and storage utilization, E.ON Ruhrgas does not consider data on the utilization of the transmission system and gas storage capacity to be meaningful. E.ON Ruhrgas also owns interests in two project companies operating gas transmission systems and in another two project companies developing gas transmission systems outside of Germany. For further details, see “— Business Overview — Pan-European Gas — Transmission and Storage.”

E.ON Ruhrgas 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 10,762 MW, E.ON UK’s attributable share of which is approximately 10,547 MW. Electricity is transmitted to purchasers by means of the National Grid transmission network in the United Kingdom. For further details, see “— Business Overview — 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 2005, E.ON UK’s power plants operated at approximately 48 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 14,982 MW, its attributable share of which is approximately 7,570 MW (not including mothballed and shutdown power plants). In Sweden and Finland, electricity is transmitted to purchasers via high voltage electricity grids, which are operated by state-owned companies, and through regional and local distribution networks. E.ON Sverige and E.ON Finland own and operate regional and local electricity distribution networks in Sweden (E.ON Sverige) and Finland (E.ON Sverige and E.ON Finland). E.ON Sverige 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 Sverige also owns and operates high- and low-pressure gas pipelines. For more information, see “— Business Overview — Nordic.” E.ON Nordic believes that its power plants, 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 87 percent of available capacity in 2005. 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 8,300 MW, E.ON U.S.’s attributable share of which is approximately 7,700 MW (not including mothballed and shutdown power plants). Electricity is transmitted to purchasers by means of E.ON U.S.’s transmission network (operated by MISO) in the United States. For further details, see “— Business Overview — U.S. Midwest.” E.ON U.S. believes that its power plants are in good operating condition and that its machinery and equipment have been well maintained. In 2005, E.ON U.S.’s

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power plants operated at approximately 53 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.

Other Activities

Degussa. On a global basis, Degussa operates 130 major production plants in 50 different countries.

Degussa believes that its production facilities are in good operating condition and that its machinery and equipment have been well maintained.

INTERNAL CONTROLS

E.ON’s own financial controls indicate that E.ON is organized, and will continue to be operated, in a financially sound manner. E.ON’s internal controls and procedures are integrated with its firm-wide risk management system. E.ON’s integrated risk management and internal controls system have the following key elements: the planning and controlling process, the reporting structure, E.ON Group-wide guidelines, internal control and monitoring by E.ON’s Management Board and Supervisory Board, the internal auditing process and the risk reporting system.

E.ON’s internal control systems and procedures are used to monitor the Company’s investments, obligations, commitments and operations. The internal control system is not restricted to identifying and monitoring balance sheet items, but also identifies and monitors off-balance sheet transactions. The formation of corporate or other business entities to hold, control or own any investment, asset or liability would also be controlled by the process to manage the risks associated therewith.

E.ON believes that appropriate internal controls are in place to achieve effective and efficient operations as well as reliable internal and external reporting, and to ensure compliance with applicable laws and regulations as well as internal policies and procedures. In addition, E.ON believes that its internal controls over financial reporting provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with applicable law and generally accepted accounting principles.

As a result of the listing of its ADRs on the NYSE, E.ON is also subject to the listing requirements of the NYSE and the U.S. federal securities laws, including the U.S. Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”) and the rules and regulations thereunder. For more information on E.ON’s compliance with these requirements, see “Item 10. Additional Information — Memorandum and Articles of Association,” “Item 15. Controls and Procedures,” “Item 16A. Audit Committee Financial Expert,” “Item 16B. Code of Ethics,” “Item 16C. Principal Accountant Fees and Services,” “Item 16D. Exemptions from the Listing Standards for Audit Committees” and “Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers,” as well as the certifications included as exhibits to this annual report.


Item 4A.	Unresolved Staff Comments.

Not applicable.


Item 5.	Operating and Financial Review and Prospects.

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 “Item 4. Information on the Company — History and Development of the Company — VEBA-VIAG Merger.”

In July 2002, E.ON acquired 100 percent of the issued share capital of the former Powergen, an integrated utility business based in London and Coventry, England, for total cash consideration of €7.6 billion (net of €0.2 billion of cash acquired) and the assumption of €7.4 billion of debt. The acquisition was accounted for under the purchase method and goodwill in the amount of €8.9 billion resulted from the purchase price allocation. A subsequent impairment charge reduced this amount to €6.5 billion. Additional information on the Powergen

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Group acquisition can be found in “Item 4. Information on the Company — History and Development of the Company — Powergen Group Acquisition” and “— Business Overview — U.K.”

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. The acquisition had initially been blocked by the German Federal Cartel Office and then by a temporary injunction imposed by the courts following lawsuits brought by a number of plaintiffs who had challenged the validity of the ministerial approval that had overturned the Federal Cartel Office’s decision. In January 2003, E.ON reached settlement agreements with all of the plaintiffs, allowing the transaction to proceed. For further information, see “Item 4. Information on the Company — History and Development of the Company — Ruhrgas Acquisition.”

Upon termination of the Ruhrgas court proceedings 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. The purchase price is expected to total approximately €2.8 billion, equal to €31.50 per Degussa share, and an amount roughly equivalent to the purchase price is expected to be distributed as a cash dividend to E.ON’s shareholders. The transaction is expected to be completed by July 1, 2006, and E.ON expects to record a book gain on the sale of approximately €400 million. Until the completion of this transaction, E.ON and RAG operate Degussa under joint control, and E.ON accounts for its interest in Degussa under the equity method. E.ON owns a 39.2 percent interest in RAG.

As a result of E.ON’s on.top strategic review launched in 2003, the core energy business has been re-organized into five new 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. Beginning in 2004, E.ON’s financial reporting has mirrored the new 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. E.ON also reports its only remaining telecommunications interest, a 50.1 percent stake in the Austrian mobile telecommunications network operator ONE GmbH (“ONE”), which is accounted for at equity in E.ON’s Consolidated Financial Statements, under Corporate Center. E.ON’s proportionate share of Degussa’s after-tax earnings following its deconsolidation continue to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which is reported as a separate segment. As part of the implementation of the new structure, E.ON completed intra-Group transfers of shareholdings in a number of its companies in December 2003, in 2004 and in 2005. None of these transfers had any impact on E.ON’s financial results on a consolidated basis. For additional information, see “Item 4. Information on the Company — History and Development of the Company — On.top Project” and “— Results of Operations — Business Segment Information” below.

E.ON participates in a number of different businesses. E.ON operates in the continental European energy business through E.ON Energie, E.ON Ruhrgas and E.ON Nordic, in the U.K. energy business through E.ON UK and in the U.S. energy business through E.ON U.S. Outside its core energy business, E.ON disposed of its real estate business Viterra in 2005, and has entered into a framework agreement for the sale of its minority equity interest in Degussa, the chemicals company. The E.ON Group also has minority participations in numerous companies, particularly in the Central Europe and Pan-European Gas market units, which are classified as associated companies. Income from these participations is reflected in the income statement as income from equity interests and is generally included in adjusted EBIT. Management views these associated companies as an integral part of the operations of E.ON. In line with its objective to focus on energy as its core business, E.ON has sold or classified as discontinued the operations of its former silicon wafer, aluminum and oil segments and real estate business, as well as certain components of its Pan-European Gas, Central Europe and U.S. Midwest market

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units and of its non-core activity Viterra. For additional information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations” and “— Acquisitions and Dispositions — Discontinued Operations.”

2005 Highlights. E.ON’s sales in 2005 increased 22.3 percent to €51,854 million from €42,384 million in 2004 (in each case net of electricity and natural gas taxes). The increase was primarily attributable to higher average prices in the electricity and gas business at all market units, higher electricity and gas sales volumes at the Central Europe and Pan-European Gas market units, an increase in sales of electricity generated from renewable resources at the Central Europe market unit reflecting regulatory requirements and consolidation effects, including the first-time consolidation of Distrigaz Nord and E.ON Moldova. Net income increased by 70.7 percent to €7,407 million in 2005 from €4,339 million in 2004, primarily reflecting higher income from discontinued operations, as described in more detail below. Cash provided by operating activities increased 13.0 percent to €6,601 million in 2005 from €5,840 million in 2004, with the increase being primarily attributable to changes in tax payments.

ACQUISITIONS AND DISPOSITIONS

The following discussion summarizes each of the principal acquisitions and dispositions made by E.ON since January 1, 2003, and is organized by business segment according to E.ON’s new market unit structure, which was adopted in January 2004. In particular, transactions with respect to E.ON Nordic, E.ON Sverige, Graninge, E.ON Finland and Thüga are described according to the market unit each entity currently belongs to, rather than the former segment it belonged to at the time of the relevant transaction. For information on the accounting treatment of the most significant of these transactions, see Note 4 of the Notes to Consolidated Financial Statements. For information on E.ON AG’s acquisition of the Powergen Group in 2002 and the former Ruhrgas in 2003, see “Item 4. Information on the Company — History and Development of the Company — Powergen Group Acquisition” and “— Ruhrgas Acquisition.” For acquisitions and dispositions related to the Ruhrgas acquisition, including those required by the ministerial approval authorizing the transaction, see “Central Europe/ Pan-European Gas/ U.K./ Nordic” below.

Central Europe. In August 2003, E.ON Energie merged EWW, EMR and PESAG Aktiengesellschaft into the single larger regional distribution company, E.ON Westfalen Weser, in which E.ON Energie held a 62.8 percent stake as of December 31, 2005. Also in August 2003, Hein Gas Hamburger Gaswerke GmbH (“Hein Gas”) was merged with Schleswag AG and Hanse Gas GmbH to form E.ON Hanse, in which E.ON Energie held a 73.8 percent interest as of December 31, 2005.

In September 2003, E.ON Energie acquired majority stakes in the Czech regional electricity utilities JME and JCE through a series of transactions. As of December 31, 2003, E.ON’s interest in JME and JCE was 85.7 percent and 84.7 percent, respectively. The total aggregate purchase price amounted to €207 million. Goodwill in the amount of €48 million resulted from the final purchase price allocation for these stakes (at December 31, 2003, goodwill of €152 million had been recorded according to the preliminary purchase price allocation). The acquisition process also involved the sale of E.ON Energie’s minority stakes in the regional power distributors ZCE and VCE to the Czech state-owned company CEZ for €206 million, resulting in a gain of €2 million. In December 2004, E.ON Energie acquired additional stakes in JME and JCE, increasing its interests in the two companies to 99.0 percent and 98.7 percent, respectively. The aggregate acquisition costs for the 2004 transactions amounted to €81 million. In 2005, E.ON Energie acquired all remaining interests in the two companies for a total of €5 million. As of January 1, 2005, E.ON Energie re-organized 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 for the acquisitions in 2004 and 2005.

In January 2004, E.ON Energie sold its 4.99 percent shareholding in the Spanish utility Union Fenosa on the market for approximately €217 million, realizing a gain on the sale of approximately €26 million.

In July 2004, E.ON Energie completed the statutory squeeze-out procedure to obtain the remaining 1.1 percent of E.ON Bayern held by minority shareholders. The aggregate purchase price amounted to

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€189 million (€165 million of which was paid in E.ON shares), with goodwill of €148 million resulting from the purchase price allocation.

In December 2004, E.ON Energie increased its stake in the German regional electricity distribution company Avacon (since renamed E.ON Avacon) by 13.1 percent to 69.6 percent in a multistage process involving the acquisition of the intermediate holding companies Ferngas Salzgitter and FSG Holding. E.ON Energie increased its stake in FSG Holding to 100 percent by acquiring a 10.0 percent interest from Bayerische Landesbank and the remaining 90.0 percent from three companies in the Pan European Gas market unit (RGE Holding GmbH (45.0 percent), Thüga-Konsortium Beteiligungs GmbH (35.0 percent) and Thüga (10.0 percent)). In addition, E.ON Energie purchased direct shareholdings in Ferngas Salzgitter from BEB (13.0 percent), EGM (13.0 percent) and RGE Holding GmbH (39.0 percent). Following these acquisitions, FSG Holding was merged into E.ON Energie and Ferngas Salzgitter into Avacon. The aggregate purchase price paid to Bayerische Landesbank, BEB and EGM was €133 million, with €38 million in goodwill resulting 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.

In July 2005, E.ON Energie transferred its 51.0 percent interest (49.0 percent voting interest) in GVT and its 72.7 percent interest in TEAG to 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 ETE. Following this reorganization, E.ON Energie holds an 81.5 percent interest in TEB and TEB holds 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.

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 preliminary 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 — now E.ON Moldova — and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. The aggregate purchase price for the 51.0 percent interest amounted to €101 million, with no goodwill resulting from the preliminary 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 €35 million was attributable to the transfer of E.ON shares), resulting in goodwill from the purchase price allocation of €36 million.

Pan-European Gas. In May 2004, E.ON AG completed a squeeze-out procedure to obtain the remaining 3.4 percent of Thüga. The total purchase price for the 2.9 million shares amounted to €223 million. Goodwill of €106 million resulted from the purchase price allocation.

In November 2004, ERI signed an agreement with the Hungarian oil and gas company 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. The agreement also includes put options allowing MOL to sell its remaining interests in the gas trading and gas storage units, as well as an interest of up to 75.0 percent minus one share of its gas transmission business, to ERI for a period of 5 years from the closing date and through

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July 1, 2007, respectively. In December 2005, the EU 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 two businesses. The total purchase price is now approximately €450 million. In addition, ERI will assume debt amounting to approximately €600 million. ERI and MOL have also agreed upon a purchase price adjustment mechanism designed to reflect developments in the relevant regulatory framework through 2009. These transactions are expected to be completed by the end of March 2006.

In June 2005, after clearance was obtained from the relevant authorities, E.ON Ruhrgas acquired a 51.0 percent stake in the Romanian gas supplier 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 first, this stake was increased to 51.0 percent through a capital increase. E.ON Ruhrgas paid an aggregate of approximately €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 €56 million resulted from the preliminary purchase price allocation. Distrigaz Nord was consolidated as of June 30, 2005.

In September 2005, E.ON Ruhrgas Norge acquired an additional 15.0 percent stake in the Njord oil and gas field from the British oil and gas company Paladin Resources plc. and now owns a 30.0 percent stake in this field. The total purchase price for the additional 15.0 percent interest amounted to €61 million.

In the course of 2005, E.ON Ruhrgas UK acquired a further 13.59 percent stake in Interconnector from BP (4.0 percent), International Power (3.38 percent) and Amerada Hess (6.21 percent). E.ON Ruhrgas UK now holds a total interest of 23.59 percent in this company. The total purchase price for the additional 13.59 percent interest amounted to €84 million.

In November 2005, E.ON Ruhrgas acquired 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 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 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 24 of the Notes to Consolidated Financial Statements. Goodwill of €349 million resulted from the preliminary purchase price allocation. Caledonia was fully consolidated as of November 1, 2005.

U.K. In November 2002, in accordance with E.ON UK’s strategy to focus on the core U.K. market, E.ON UK reached agreements to sell its share in certain joint venture companies holding interests in independent power projects in India, Australia and Thailand. The sale of these interests in 2003 generated aggregate proceeds of €112 million and a gain of €29 million. In January 2004, E.ON UK reached an agreement to sell its only remaining Asian interests, a 35.0 percent stake in PT Jawa Power, owner of a 1,220 MW plant in Indonesia, and 100 percent of the associated operations and maintenance company, PT Jawa Power Timur, to Keppel Energy and J-Power. In April 2004, an existing shareholder, Bumipertiwi, exercised its pre-emption rights over this sale. In July 2004, E.ON UK terminated the agreement with Keppel Energy and J-Power and in August 2004, E.ON UK entered into agreements with Bumipertiwi and YTL PI reflecting Bumipertiwi’s exercise of its pre-emption rights and subsequent sale of its interests to YTL PI. On December 7, 2004, E.ON UK completed the disposal of its investment in PT Jawa Power and PT Jawa Power Timur. The sale of these interests in 2004 generated aggregate proceeds of €120 million and a loss of €6 million.

In January 2004, E.ON UK completed the acquisition of Midlands Electricity from Aquila and FirstEnergy for €1.7 billion (GBP1,180 million), net of €0.1 billion cash acquired. The acquisition price comprised €55 million paid to stockholders, €881 million paid to creditors and €856 million of debt assumed. Cash acquired amounted to €86 million. In the transaction, E.ON UK also acquired a number of other businesses, 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 three generation plants in the United Kingdom, Turkey and Pakistan. Goodwill in the amount of €473 million resulted from the purchase price allocation.

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In the first half of 2005, E.ON UK acquired, in two tranches, 100 percent of the equity of Enfield from NRG, El Paso and Indeck. The purchase price amounted to approximately €185 million (GBP127 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 percent of HGSL from Scottish Power Energy Management Limited. The purchase price amounted to €140 million (GBP96 million), with no goodwill resulting from the purchase price allocation. HGSL was consolidated as of July 28, 2005.

Nordic. In October 2001, the Company concluded a put option agreement, which allows a minority shareholder of E.ON Sverige to sell any or all of its shares of E.ON Sverige to E.ON Energie at any time through December 15, 2007. The consideration payable by E.ON Energie upon the exercise of this option in full is approximately €2.0 billion.

Beginning in November 2003, following its receipt of the required approvals from the relevant antitrust authorities, E.ON Sverige increased its stake in the Swedish utility Graninge from 36.3 percent to 79.0 percent by acquiring shares from Electricité de France (“EdF”) and other shareholders. Swedish law required E.ON Sverige to make a public tender for all outstanding Graninge shares following the acquisition of a majority stake. At the close of this mandatory offer in January 2004, E.ON Sverige’s indirect stake in Graninge had increased to 97.5 percent and Graninge was delisted. By June 2004, E.ON Sverige had acquired the remaining outstanding shares and controlled 100 percent of Graninge. Total acquisition costs to E.ON Sverige in 2003 (therefore not including those relating to the tender offer) amounted to €628 million. The purchase price for the Graninge shares acquired in 2004 was approximately €307 million, with €76 million in goodwill resulting from the purchase price allocation. As of December 31, 2004, the goodwill relating to E.ON Sverige’s 100 percent interest in Graninge amounted to €233 million.

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 acquisition to Statkraft. In July 2005, Sydkraft and Statkraft signed the corresponding agreement, whereby Statkraft would acquire a total of 24 hydroelectric power plants. In accordance with the agreement, Statkraft took ownership of the plants in October 2005. The purchase price amounted to approximately €480 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. The major balance sheet line items affected by the transaction were presented in the Consolidated Balance Sheet as of December 31, 2004 under “Assets/ Liabilities of disposal groups.”

On February 2, 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 price of €37.12 per share, corresponding to a total of approximately €380 million. E.ON Nordic currently expects to record an estimated book gain of approximately €25 million on the sale, which is subject to the approval of the Finnish competition authorities. Beginning January 16, 2006, E.ON Finland is accounted for as discontinued operations.

Central Europe/ Pan-European Gas/ U.K./ Nordic. The ministerial approval authorizing E.ON’s acquisition of Ruhrgas and certain of the settlement agreements with plaintiffs challenging the transaction required E.ON Energie and E.ON Ruhrgas to dispose of a number of shareholdings, including those described below:


	•	In July 2003, E.ON Energie and E.ON Ruhrgas each agreed to sell a 22.0 percent stake in Bayerngas to the municipal utilities of the cities of Munich, Augsburg, Regensburg and Ingolstadt, and to the city of Landshut, for a total of €127 million. The transaction was completed in November 2003. E.ON Energie realized a gain on the disposal in the amount of €22 million. No gain was realized on the sale of the E.ON Ruhrgas stake, as these shares had been recorded at their fair value at the time of E.ON’s acquisition of Ruhrgas.

	•	In September 2003, E.ON Energie sold its 80.5 percent interest in Gelsenwasser to a joint venture company owned by the municipal utilities of the cities of Dortmund and Bochum. Gelsenwasser was accounted for as a discontinued operation in the Consolidated Financial Statements. For further information, see “Discontinued Operations” below.

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	•	In October 2003, E.ON Energie transferred its 5.26 percent stake in VNG to E.ON Ruhrgas, which already owned an interest in this Leipzig-based gas distributor. In December 2003, E.ON Ruhrgas agreed to sell 32.1 percent of VNG to EWE Aktiengesellschaft (“EWE”), and offered its remaining 10.0 percent stake in VNG to eleven municipalities in eastern Germany for the same price per share. The total consideration for the sale of the entire interest was approximately €899 million. E.ON Energie realized a gain of approximately €60 million on its stake. No gain was realized on the sale of the E.ON Ruhrgas stake, as these shares had been recorded at their fair value at the time of E.ON’s acquisition of Ruhrgas. The sales were subject to the fulfillment of a number of conditions and were completed in January 2004.

	•	In November 2003, E.ON Energie divested its 100 percent interest in E.ON-Energiebeteiligungs-Gesellschaft to EWE for €305 million. E.ON Energiebeteiligungs-Gesellschaft had a 32.36 percent interest in swb, comprising all of the shares previously held by E.ON Energie and E.ON Ruhrgas. E.ON Energie realized a gain on the disposal in the amount of €85 million. No gain was realized on the sale of the E.ON Ruhrgas stake, as these shares had been recorded at their fair value at the time of E.ON’s acquisition of Ruhrgas.

	•	In December 2003, E.ON concluded an agreement to divest its stake in EWE. E.ON Energie’s 27.4 percent stake in EWE was acquired by EWE’s majority shareholders Energieverband Elbe-Weser Beteiligungsholding GmbH and Weser-Ems Energiebeteiligungen GmbH for total consideration of approximately €520 million. E.ON recorded a gain of €257 million on the disposal, which was completed in January 2004.

In February/ March 2003, as a consequence of E.ON’s settlement agreement with Fortum, a Finnish utility that was one of the plaintiffs challenging the E.ON Ruhrgas transaction, Fortum and E.ON swapped certain shareholdings. Fortum acquired E.ON Sverige’s equity interests in the Norwegian utilities Hafslund, Østfold and Frederikstad and E.ON Energie’s equity interest in the Russian utility AO Lenenergo for a total of approximately €460 million, including the repayment of debt. In return, E.ON Sverige bought the Swedish distribution company Fortum Nät Småland AB (“Småland”) and E.ON AG bought the German power plant Fortum Kraftwerk Burghausen GmbH (“Burghausen”), ownership of which was transferred to E.ON Energie, and the Irish peat-fired plant Edenderry, ownership of which was transferred to E.ON UK. The consideration paid by the E.ON Group in these transactions totaled approximately €288 million, including the assumption of debt.

Corporate Center. In January 2003, E.ON entered into an agreement to sell its 15.9 percent shareholding in Bouygues Telecom S.A. (“Bouygues Telecom”) to the Bouygues Group for a total of approximately €1.1 billion in a two-step transaction. In the first step, the Bouygues Group acquired a 5.8 percent stake in Bouygues Telecom (including approximately €60 million in shareholder loans) from E.ON for €394 million in March 2003. In the second step, the Bouygues Group exercised a fixed price call option on E.ON’s remaining 10.1 percent interest, acquiring the shares for €692 million in December 2003. E.ON recorded a gain of €840 million on the two-step sale.

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. The purchase price is expected to amount to approximately €2.8 billion, equal to €31.50 per Degussa share. The transaction is currently expected to close by July 1, 2006. E.ON expects to record a book gain of approximately €400 million and expects to distribute to its shareholders a cash dividend in an amount roughly equivalent to the purchase price.

Discontinued Operations. Consistent with its plans to focus on its core energy business, E.ON has disposed of a number of its non-core divisions and businesses in recent years. As a result of divestitures in 2001, the Company’s former aluminum and silicon wafers business segments were accounted for as discontinued operations in accordance with Accounting Principles Bulletin No. 30, Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions (“APB 30”). On January 1, 2002, the Company adopted SFAS 144, which requires it to account for disposals of a component of a segment as discontinued operations, thereby reducing the threshold needed for a particular divestiture to result in discontinued operations treatment. In 2002, E.ON discontinued the operations of its former oil business segment, following its disposal of VEBA Oel. In 2003, E.ON discontinued and disposed of certain operations in the Central Europe and U.S. Midwest market units, as

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well as certain activities of Viterra in the Other Activities business segment. 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. These transactions are summarized below.

On September 30, 2001, E.ON entered into an agreement for the sale of MEMC, its former silicon wafer division, to TPG Partners III. In November 2001, E.ON sold both its 71.8 percent interest in the silicon wafer division and its shareholder loans for a symbolic purchase price of $6. The disposal of the silicon wafer division resulted in a loss from discontinued operations net of income taxes and minority interests of €810 million in 2001. The loss includes a €990 million loss on disposition. In 2003, a final purchase price adjustment based on MEMC’s having met specific performance targets in 2002 resulted in E.ON recording income from discontinued operations net of income taxes and minority interests of €14 million. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Silicon Wafers.”

On January 6, 2002, E.ON entered into an agreement to sell its 100 percent stake in its former aluminum division VAW to Norsk Hydro ASA for €3.1 billion. The results of the ongoing operations of VAW up to the date of disposal and the €893 million gain realized by E.ON on its disposal were reported in “Income (Loss) from discontinued operations, net” in the income statement for the relevant period. The net gain on disposal of €893 million does not include the reversal of VAW’s negative goodwill of €191 million, as this amount was required to be recognized as income from a change in accounting principles upon the adoption of SFAS 142 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. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Aluminum.”

In July 2001, E.ON and BP entered into an agreement pursuant to which BP agreed to acquire a 51.0 percent stake in VEBA Oel by way of a capital increase. The agreement also provided E.ON with a put option that allowed it to sell its remaining 49.0 percent interest in VEBA Oel to BP at any time from April 1, 2002 for an exercise price of €2.8 billion, subject to certain purchase price adjustments. The capital increase took place in February 2002, giving BP majority control of VEBA Oel as of February 1, 2002. E.ON exercised its put option effective June 30, 2002. E.ON received proceeds of €2.8 billion for its VEBA Oel shares. In addition, €1.9 billion in shareholder loans made previously by the E.ON Group to VEBA Oel were repaid. In April 2003, E.ON and BP reached an agreement setting the final purchase price for VEBA Oel (without prejudice to the standard indemnities in the contract) at approximately €2.9 billion. The disposal of VEBA Oel resulted in a loss from discontinued operations net of income taxes of €37 million in 2003, and income from discontinued operations net of income tax of €1,784 million in 2002. E.ON recognized a loss on disposal of €35 million in 2003 and a gain of €1,367 million in 2002. In 2004, E.ON recognized a loss of €19 million resulting from claims under standard contractual indemnities. These effects were each recorded under “Income (Loss) from discontinued operations, net” in the income statement for the relevant period. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Oil.”

Under the ministerial approval for E.ON’s acquisition of Ruhrgas, E.ON Energie was required to dispose of its 80.5 percent shareholding in Gelsenwasser. In September 2003, a joint venture company owned by the municipal utilities of the German cities of Dortmund and Bochum purchased the Gelsenwasser interest for €835 million. The disposal of Gelsenwasser resulted in income from discontinued operations net of income taxes and minority interests of €479 million in 2003. In 2003, E.ON realized a gain on disposal of €418 million. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other.”

As a condition to its approval of the former Powergen’s acquisition of LG&E Energy (now E.ON U.S.), the SEC had required that LG&E Energy sell CRC-Evans. Effective October 31, 2003, LG&E Energy sold CRC-Evans to an affiliate of Natural Gas Partners for €37 million. Approximately €1 million in income from discontinued operations net of income taxes and minority interests was recorded in each of 2005 and 2003. E.ON realized no gain or loss on the disposal. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other.”

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Viterra Energy Services was accounted for as a discontinued operation in the Consolidated Financial Statements for 2002. In June 2003, Viterra sold this wholly-owned subsidiary to CVC Capital Partners. In March 2003, Viterra sold its Viterra Contracting subsidiary to Mabanaft. The aggregate consideration for both transactions totaled €961 million, including approximately €112 million of assumed liabilities, with Viterra realizing a gain of €641 million. The portion of 2003 and 2002 results included in “Income (Loss) from discontinued operations, net” in the income statements for the relevant periods amounted to €681 million and €52 million, respectively. In 2004, the release of previously recorded provisions resulted in income in the amount of €10 million, which is recorded in “Income (Loss) from discontinued operations, net.” For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other Activities.”

In May 2005, E.ON sold Viterra to Deutsche Annington. The purchase price for 100 percent of Viterra’s equity was approximately €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. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other Activities.”

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 percent of Ruhrgas Industries was approximately €1.2 billion, with the purchasers’ assumption of Ruhrgas Industries’ debt and provisions bringing the total value of the transaction to approximately €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 roughly €0.6 billion. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other.”

In November 2005, E.ON U.S. entered into a letter of intent with BREC regarding a proposed transaction to terminate the lease and operational agreements among the parties and other related matters. The parties are in the process of negotiating definitive agreements regarding the transaction, the closing of which would be subject to the review and approval of various regulatory agencies and other interested parties. Subject to such contingencies, the parties are working on completing the proposed termination transaction by the end of 2006. The classification of WKE as a discontinued operation at the end of December 2005 resulted in a loss from discontinued operations, net of income taxes and minority interests of €162 million and €2 million in 2005 and 2004, respectively. For further information, see “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other.”

The Consolidated Financial Statements and related notes thereto for the years ending December 31, 2005 and 2004 and the Consolidated Statement of Income for 2003, as well as the related notes thereto, have been 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, 2005 and 2004, 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.

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

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CRITICAL ACCOUNTING POLICIES

The discussion and analysis of E.ON’s financial condition and results of operations are based on its Consolidated Financial Statements, which are prepared in accordance with U.S. GAAP and included in Item 18. The reported financial condition and results of operations of E.ON are sensitive to accounting methods, assumptions and estimates that underlie the preparation of the financial statements. The Company’s critical accounting policies, the judgments and other uncertainties affecting application of those policies and the sensitivity of reported results to changes in conditions and assumptions are factors to be considered in reviewing E.ON’s Consolidated Financial Statements and the discussions below in “— Results of Operations.”

Goodwill and Intangible Assets

E.ON’s group strategy is to maximize the value of its portfolio of businesses through creating value from the convergence of European energy markets and of the electricity and gas value chains. Another element of that strategy is the improvement of the Group’s position in target markets through pursuing selective market investments.

Business Combinations. This strategy has resulted in E.ON completing a significant number of acquisitions in recent years, and E.ON can be expected to continue to make acquisitions in the future. E.ON’s acquisitions have been, and, as required, will continue to be, accounted for under the purchase method of accounting (the “purchase method”). Under the purchase method, an acquired company is recorded on E.ON’s balance sheet using the fair values of the acquired assets (tangible and intangible) and liabilities as of the acquisition date.

The application of the purchase method requires a company to make certain estimates and judgments. One of the most significant estimates relates to the determination of the fair value of assets and liabilities acquired. For other than intangible assets acquired, E.ON determines the fair value based on the nature of the asset. For example, marketable securities are valued at the market rate on the date of acquisition, while an independent appraisal is often obtained for land, buildings and equipment. The Company also assesses whether any significant intangible assets arise from contractual or other legal rights of the acquired entity or are separable from the acquired entity (i.e. capable of being sold). If any intangible assets are identified, the Company must determine the value of these intangibles. Depending on the type of intangible and the complexity of determining its fair value, the Company either consults with an independent external valuation expert or develops the fair value internally, using an appropriate valuation technique. The determination of the useful life of intangible assets is based upon the nature of the intangible, as well as the characteristics of the acquired business and the industry in which it operates. Any residual amount remaining after allocation of the purchase price to the fair value of all assets and liabilities acquired is goodwill.

Goodwill. On January 1, 2002, E.ON adopted SFAS 142, which significantly changed the accounting requirements for goodwill. The first step of the SFAS 142 impairment test requires E.ON to identify potential impairment situations by comparing the fair value of a reporting unit with its carrying value including goodwill. When determining the fair value of the reporting units, E.ON utilizes appropriate valuation techniques. The input data for the valuation is in principle based on the Company’s mid-term plan.

If the carrying value exceeds the fair value of a reporting unit, thus indicating a possible impairment, E.ON performs the second step of the SFAS 142 impairment test, which requires E.ON to allocate the fair value to the assets and liabilities of the reporting unit using a methodology consistent with the application of the purchase method. Any excess of fair value of the reporting unit over the fair value of net assets is compared to the allocated goodwill as recorded. If the allocated goodwill exceeds the residual fair value, an impairment charge equal to the difference is recognized.

E.ON has designated the fourth quarter of its fiscal year for its annual impairment test in order to coincide with its mid-term planning process. E.ON believes that this schedule ensures that the most current information available is used and provides consistency in methodology. Acquisitions in 2005 resulted in goodwill totaling approximately €0.6 billion. Total goodwill as of December 31, 2005 was €15.4 billion.

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Fair Value of Derivatives

As quoted market prices for certain derivatives used by E.ON are not readily available, the fair values of these derivatives have been calculated using common market valuation methods and value-influencing market data at the relevant balance sheet date as follows:


	•	Currency, electricity, gas, oil and coal forward contracts, swaps, and emission rights derivatives are valued separately at future rates or market prices as of the balance sheet date. The fair values of spot and forward contracts are based on spot prices that consider forward premiums or discounts from quoted prices in the relevant markets.

	•	Market prices for currency, electricity and gas options are obtained 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 rate risk are determined by discounting future cash flows using market interest rates over the remaining term of the instrument. Discounted cash values are 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 considered with an effect on current results at the date of payment or accrual.

	•	Equity swaps are valued on the basis of the stock prices of the underlying equities, taking into consideration any financing components.

	•	Exchange-traded energy future and option contracts are valued individually at daily settlement prices determined on the futures markets that are published by their respective clearing houses. Initial margins paid 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, and are accounted for with an impact on earnings at settlement or realization.

	•	Certain long-term commodity contracts are valued by the use of valuation models that include average probabilities and take into account individual contract details and variables.

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.

The objective of E.ON’s financial and commodity risk management is to limit the risk of significant volatility in earnings and cash flows from the underlying operational business. Through internal guidelines (i.e., Group finance guidelines and Group commodity risk guidelines), the Company ensures that derivatives used for risk management purposes, rather than proprietary trading, are only utilized to hedge booked, contracted or planned underlying transactions. E.ON’s proprietary trading is limited to commodity derivatives and takes place in specified markets within defined limits designed to limit any significant impact of trading activities on earnings. The open positions from the operational business and the hedging and proprietary trading activities are reported and monitored regularly. The Company, in line with international banking standards, calculates and assesses market risks in accordance with the policies outlined in “Item 11. Quantitative and Qualitative Disclosures about Market Risk.” For additional details on the Group’s use of derivative financial instruments, see Note 28 of the Notes to Consolidated Financial Statements.

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Electricity Contracts

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 under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), and are marked to market. However, due to the normal purchase normal sales exemption for electricity companies as specified by SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS 149”), some of these contracts are not accounted for as derivatives under SFAS 133 and therefore are not being marked to market. As a result, any price volatility inherent in these contracts is not reflected in the operating results of E.ON. If this exemption is disallowed through future interpretations or actions of the Financial Accounting Standards Board (“FASB”), the impact on future operating results could be significant.

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 and the operation of E.ON UK’s generation plants. Contracts providing for physical delivery in Germany or Sweden are currently accounted for as contracts outside the scope of SFAS 133, as no functioning natural gas market mechanism or spot market exists in Germany and Sweden which would allow the Company to classify gas as readily convertible to cash. 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 German and Swedish contracts for derivatives under SFAS 133. If any such reassessment resulted in contracts being accounted for as derivatives under SFAS 133, the impact on future operating results could be significant. Within the U.K. market, a number of non-standard gas contracts at E.ON UK have been marked to market since 2003 following the implementation of Derivatives Implementation Group Issue C-20.

Deferred Taxes

E.ON has significant deferred tax assets and liabilities which are expected to be realized through the statement of income over extended periods of time in the future. In calculating the deferred tax items, E.ON is required to make certain assumptions and estimates regarding the future tax consequences attributable to differences between the carrying amounts of assets and liabilities as recorded in the Consolidated Financial Statements and their tax basis. Significant assumptions made include the expectation that: (1) future operating performance for subsidiaries will be consistent with historical operating results; (2) recoverability periods for tax credits and net operating loss carryforwards will not change; (3) undistributed earnings of foreign investments have been permanently reinvested; (4) net operating losses for which E.ON has not provided a valuation allowance will more likely than not be recovered through future taxable income; and (5) existing tax laws and rates to which E.ON is subject in various tax jurisdictions will remain unchanged into the foreseeable future. E.ON believes that it has used prudent assumptions and feasible tax planning strategies in developing its deferred tax balances; however, any changes to the facts and circumstances underlying its assumptions could cause significant changes in the deferred tax balances and resulting volatility in its operating results.

Nuclear Waste Management

German law requires nuclear power plant operators to establish sufficient financial provisions for financial obligations that arise from the use of nuclear power. The amounts provided by E.ON for its German nuclear power plants have been determined based on an industry-wide valuation prepared by German governmental authorities and qualified parties. In Sweden, nuclear power plant operators are obliged to contribute cash to a fund managed by the governmental authorities. The amount of the contributions, as determined annually by governmental authorities, is based on the volume of electricity produced using nuclear power. Despite these contributions to the fund, nuclear power plant operators in Sweden will still be obligated to make additional contributions if actual costs for nuclear waste management and decommissioning exceed the government’s estimates and the amount available in the fund.

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E.ON believes that the valuations used for both the German and Swedish nuclear waste management programs provide the best estimate available in respect to its nuclear waste management and decommissioning liabilities. The costs associated with nuclear waste management and the decommissioning of nuclear power plants are substantial and are based on current legal requirements and the projection of costs over extended future periods. Any changes to the current legal requirements for nuclear waste management/decommissioning or the timing of payments to be made in relation to these requirements, as well as changes in cost estimates, could have a significant impact on E.ON’s future operating results.

E.ON adopted SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) as of January 1, 2003. SFAS 143 requires that asset retirement obligations be recorded at their fair value on a company’s balance sheet. For Germany, SFAS 143 changed the methodology for calculating the nuclear decommissioning accrual; however, the information used as a basis for establishing the total costs of decommissioning will remain consistent with that used in prior years. The asset retirement obligation for Swedish nuclear power plants was recorded on a gross basis upon the adoption of SFAS 143. E.ON recorded an asset retirement obligation at fair value and a corresponding long-term receivable against the Swedish national Nuclear Waste Fund at fair value not exceeding the fair value of the asset retirement obligation. The adoption of SFAS 143 increased the amounts recorded on the Consolidated Balance Sheet for E.ON’s nuclear decommissioning liabilities as of January 1, 2003 by €1,294 million. For more details, see Note 23 of the Notes to Consolidated Financial Statements.

NEW ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board issued the following accounting pronouncements, each of which will become applicable to E.ON in 2006:


	•	SFAS No. 123, Share-Based Payment;

	•	SFAS No. 154, Accounting Changes and Error Corrections — a replacement of APB Opinion No. 29 and FASB Statement No. 3; and

	•	SFAS No. 155, Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140.

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 2005 increased 22.3 percent to €51,854 million from €42,384 million in 2004 (in each case net of electricity and natural gas taxes). The increase was primarily attributable to higher average prices in the electricity and gas business at all market units, higher electricity and gas sales volumes at the Central Europe and Pan-European Gas market units, an increase in sales of electricity generated from renewable resources at the Central Europe market unit reflecting regulatory requirements and consolidation effects, including the first-time consolidation of Distrigaz Nord and E.ON Moldova. Net income increased by 70.7 percent to €7,407 million in 2005 from €4,339 million in 2004, primarily reflecting higher income from discontinued operations, as described in more detail below. Cash provided by operating activities increased 13.0 percent to €6,601 million in 2005 from €5,840 million in 2004, with the increase being primarily attributable to changes in tax payments.

In 2005, 59.5 percent of the Group’s total sales were to customers in Germany and 40.5 percent were to customers in other parts of the world, as compared with 61.2 percent and 38.8 percent in 2004, 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

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“Item 4. Information on the Company — Business Overview” and “— Operating Environment,” as well as “Item 3. Key Information — Risk Factors.”

BUSINESS SEGMENT INFORMATION

As a result of the on.top strategic review E.ON launched in 2003, the core energy business has been re-organized into five new regional market units (Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest), plus the Corporate Center. Beginning in 2004, E.ON’s financial reporting has mirrored the new 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. E.ON’s proportionate share of Degussa’s after-tax earnings following its deconsolidation continue to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which is reported as a separate segment.

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 minority interests, excluding 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, 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. 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 the relevant periods, E.ON has used adjusted EBIT as its segment reporting measure in accordance with SFAS 131. However, on a consolidated Group basis, adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable GAAP measure. For a reconciliation of Group adjusted EBIT to net income for each of 2005, 2004 and 2003, see the table on page 132 below and the accompanying analyses on pages 134 to 135 and pages 146 to 147. For a reconciliation of adjusted EBIT to income (loss) from continuing operations before income taxes and minority interests for each of the three years, see Note 31 of the Notes to Consolidated Financial Statements.

The following table sets forth sales and adjusted EBIT for each of E.ON’s business segments for 2005, 2004 and 2003 (in each case excluding the results of discontinued operations):

E.ON BUSINESS SEGMENT SALES AND ADJUSTED EBIT


		2005						2004						2003

					Adjusted						Adjusted						Adjusted
		Sales			EBIT			Sales			EBIT			Sales			EBIT

								(€ in millions)
Central Europe(1)(2)			24,295			3,930			20,752			3,602			19,253			2,979
Pan-European Gas(2)(3)			17,914			1,536			13,227			1,344			11,919			1,401
U.K.			10,176			963			8,490			1,017			7,923			610
Nordic(4)			3,471			806			3,347			701			2,824			546
U.S. Midwest(2)			2,045			365			1,718			354			1,771			318
Corporate Center(2)(5)			(1,502	)		(399	)		(792	)		(338	)		(575	)		(323	)

	Core Energy Business		56,399			7,201			46,742			6,680			43,115			5,531
	Other Activities(2)(6)		—			132			—			107			994			176

Total			56,399			7,333			46,742			6,787			44,109			5,707


(1)	Sales include electricity taxes of €1,049 million in 2005, €1,051 million in 2004 and €1,015 million in 2003.

(2)	Excludes the sales and adjusted EBIT of certain activities now accounted for as discontinued operations. For more details, see “— Acquisitions and Dispositions — Discontinued Operations” and Note 4 of the Notes to Consolidated Financial Statements.

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(3)	Includes the results of the former Ruhrgas activities from the date of consolidation on February 1, 2003. Sales include natural gas and electricity taxes of €3,110 million in 2005, €2,923 million in 2004 and €2,555 million in 2003.

(4)	Sales include electricity and natural gas taxes of €402 million in 2005, €395 million in 2004 and €324 million in 2003.

(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 in “Item 4. Information on the Company — Business Overview — Introduction.” Sales between companies in the same market unit are eliminated in calculating sales on the market unit level.

(6)	In 2003, includes sales of Degussa for the month of January only, prior to its deconsolidation. For more details, see “Item 4. Information on the Company — Business Overview — Other Activities — Degussa” and Note 4 of the Notes to Consolidated Financial Statements.

SFAS 131 requires that the segment presentation included in Note 31 of the Notes to Consolidated Financial Statements be reclassified to reflect the new market unit structure (including the transfers of businesses noted above) and the adoption of adjusted EBIT as the segment reporting measure for each of the three years presented. To enhance comparability, the analysis of E.ON’s segment results in 2004 and 2003 presented below has been prepared using these reclassified figures for 2003.

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 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 2005, 2004 and 2003 appears in the table below. The analysis below discusses 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 31 of the Notes to Consolidated Financial Statements and the analyses on pages 134 to 135 and pages 146 to 147.


	2005			2004			2003

	(€ in millions)
Adjusted EBIT		7,333			6,787			5,707
Adjusted interest income, net		(1,027	)		(1,031	)		(1,515	)
Net book gains		491			589			1,257
Cost-management and restructuring expenses		(29	)		(100	)		(479	)
Other non-operating results		440			110			195

Income/(loss) from continuing operations before income taxes and minority interests		7,208			6,355			5,165
Income taxes		(2,276	)		(1,850	)		(1,145	)
Minority interests		(553	)		(478	)		(445	)

Income/(loss) from continuing operations		4,379			4,027			3,575
Income/(loss) from discontinued operations		3,035			312			1,512
Cumulative effect of change in accounting principles		(7	)		—			(440	)

Net income		7,407			4,339			4,647

YEAR ENDED DECEMBER 31, 2005 COMPARED WITH YEAR ENDED DECEMBER 31, 2004

E.ON Group

E.ON’s sales in 2005 increased 22.3 percent to €51,854 million from €42,384 million in 2004 (in each case net of electricity and natural gas taxes). As noted above, the increase was primarily attributable to higher average prices in the electricity and gas business, higher electricity and gas sales volumes, an increase in sales of electricity generated from renewable resources reflecting regulatory requirements and consolidation effects. As

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illustrated in the table on the previous page, the overall increase in the Group’s sales reflected an increase in sales at each of its market units other than the Corporate Center.

Sales of the Central Europe market unit increased 17.1 percent in 2005 to €24,295 million (including €1,049 million of electricity taxes) from €20,752 million (including €1,051 million of electricity taxes) in 2004. Pan-European Gas’ sales increased by 35.4 percent to €17,914 million (including €3,110 million of natural gas and electricity taxes) in 2005 from €13,227 million (including €2,923 million of natural gas and electricity taxes) in 2004. Sales of the U.K. market unit increased by 19.9 percent, amounting to €10,176 million in 2005 as compared to €8,490 million in 2004. The Nordic market unit grew its 2005 sales by 3.7 percent to €3,471 million (including €402 million of electricity and natural gas taxes) from €3,347 million (including €395 million of electricity and natural gas taxes) in 2004. Sales of the U.S. Midwest market unit increased by 19.0 percent in 2005 to €2,045 million compared with €1,718 million in 2004. The elimination of intersegment sales at the Corporate Center resulted in the segment reporting negative sales of €792 million in 2004 and negative sales of €1,502 million in 2005. The sales of each of these segments are discussed in more detail below.

Total cost of goods sold and services provided in 2005 increased 29.7 percent or €9,346 million to €40,787 million compared with €31,441 million in 2004, with increases at the Pan-European Gas market unit (€4,571 million), primarily reflecting the effect of higher procurement costs at the gas operations due to increased oil prices, at the Central Europe market unit (€3,120 million), reflecting higher electricity and gas procurement costs (approximately €1,000 million), higher purchases of energy produced from renewable resources under the Renewable Energy Law (approximately €800 million) and effects from first-time consolidation (approximately €800 million), and at the U.K. market unit (€1,801 million), primarily attributable to higher gas purchase costs (€629 million) and increased prices for power purchased (€566 million). Cost of goods sold as a percentage of revenues (net of electricity and natural gas taxes) increased to 78.7 percent in 2005 from 74.2 percent in 2004, 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 1.1 percent to €11,067 million in 2005 from €10,943 million in 2004.

Selling expenses decreased 9.0 percent or €383 million to €3,852 million in 2005, compared with €4,235 million in 2004. The decline reflected an overall reduction of €180 million in selling expenses at the U.K. market unit, including €62 million in reduced operating costs at Central Networks following the restructuring in 2004 and approximately €60 million from the release of a provision, as well as declines at the U.S. Midwest market unit (€114 million), primarily resulting from the reclassification of selling expenses to cost of goods sold and services provided, and at the Central Europe market unit (€59 million), reflecting effects from the first-time consolidation of E.ON IS totaling €190 million, which were partially offset by increased other expenses, in particular those resulting from first-time consolidations.

General and administrative expenses increased by €178 million, amounting to €1,528 million in 2005 compared with €1,350 million in 2004. The 13.2 percent increase reflected increases at all market units. At the U.K. market unit such costs increased by €70 million, primarily due to additional shared service costs as a result of acquisitions and project costs, and at the Pan-European Gas market unit by €36 million, primarily due to higher project costs and changes in the basis of consolidation. At the U.S. Midwest market unit general and administrative expenses increased by €29 million as a result of the reclassification of cost of goods sold and services provided to such expenses, while at the Corporate Center such costs increased by €26 million.

Other operating income (expenses), net increased to €1,695 million in 2005 from €1,361 million in 2004. This increase of €334 million, or 24.5 percent, reflected higher income from exchange rate differences and higher gains on derivative financial instruments. Net income (expenses) arising from exchange rate differences was equal to income of €138 million in 2005, as compared to expenses of €309 million in 2004, reflecting the results from the recognition of exchange rate movements on foreign currency transactions and net realized losses on foreign currency derivatives. Gains/losses on derivative financial instruments, net amounted to €946 million in 2005, compared with €585 million in 2004. This increase in income of €361 million or 61.7 percent was primarily attributable to the U.K. market unit. These effects were partially offset by lower net book gains on the disposal of fixed assets and decreased miscellaneous other operating income (expenses), net. Net book gains decreased by €390 million year on year, amounting to €83 million in 2005, compared with €473 million in 2004. The 2004 figure primarily included gains from the sale of stakes in EWE and VNG (€317 million), the sale of an additional

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3.6 percent of Degussa’s share capital to RAG (€51 million), the sale of shares in Union Fenosa (€26 million) and the sale of certain shareholdings at the Central Europe market unit (€57 million). In 2005, a SAB 51 gain of €31 million related to the sale of shares of E.ON Avacon. Miscellaneous other operating income (expenses), net decreased by €103 million, amounting to income of €559 million in 2005, as compared with income of €662 million in 2004. This decrease was primarily attributable to lower income from the reversal of provisions (€218 million) and the impairment loss recorded at cogeneration facilities at the U.K. market unit (€129 million). These effects were partially offset by higher gains realized on the sale of securities classified as non-fixed assets (approximately €153 million) and the gain from the transfer of the Company’s stake in TEAG (€90 million). For further information, see Note 5 of the Notes to Consolidated Financial Statements.

Financial earnings increased by €190 million, or 52.2 percent, resulting in a loss of €174 million in 2005 compared with a loss of €364 million in 2004. The increase was primarily attributable to a decrease of €326 million in interest and similar expenses, net, a decline of €145 million in income from share investments and a decrease of €9 million in write-downs of financial assets and long-term loans. For additional information, see Note 6 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 increased by 13.4 percent or €853 million to €7,208 million in 2005, as compared with €6,355 million in 2004.

In 2005, E.ON recorded income tax expenses of €2,276 million, as compared to a tax expense of €1,850 million in 2004. This increase of €426 million or 23.0 percent was primarily attributable to an increase of foreign deferred taxes, due in particular to the marking to market of energy derivatives in the U.K. market unit. For additional information, see Note 7 of the Notes to Consolidated Financial Statements.

Income attributable to minority interests, and therefore deducted in the calculation of net income, was €553 million in 2005, as compared to €478 million in 2004, with the increase of €75 million, or 15.7 percent, reflecting improved results at a number of the entities in which the Group holds a minority interest.

Results from discontinued operations increased net income by €3,035 million in 2005, as compared to a contribution to net income of €312 million in 2004. The significant increase reflected the gains on the disposal of Viterra and Ruhrgas Industries. For details, see Note 4 of the Notes to the Consolidated Financial Statements. The Group’s net income increased 70.7 percent, totaling €7,407 million in 2005, compared with €4,339 million in 2004. Excluding the results of discontinued operations, E.ON would have recorded net income of €4,372 million in 2005, as compared to net income of €4,027 million in 2004.

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 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 2005, 2004 and 2003 appears in the table on page 132. 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 31 of the Notes to Consolidated Financial Statements.

On a consolidated Group basis, adjusted EBIT increased by 8.0 percent to €7,333 million in 2005, as compared with €6,787 million in 2004.

As detailed in the table below, adjusted interest income, net, remained essentially stable, amounting to an expense of €1,027 million in 2005 as compared to €1,031 million in 2004. The interest portion of long-term provisions deducted in the calculation was €252 million, as compared to €120 million in 2004, reflecting the fact that the 2004 result included a one-off effect related to amendments to Germany’s Ordinance on Advance Payments for the Establishment of Federal Facilities for Safe Custody and Final Storage for Radioactive Wastes (Endlager-Vorausleistungsverordnung). Non-operating interest income, net, amounted to income of €39 million in 2005 as compared with an expense of €151 million in 2004. In 2005, non-operating interest income primarily

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reflected the termination of an interest provision (€32 million), while in 2004 the largest portion of this item resulted from accruals for interest payments due on taxes for audit periods which are still under review.


	2005			2004

	(€ in millions)
Interest income and similar expenses (net) as shown in Note 6 of the Notes to Consolidated Financial Statements		(736	)		(1,062	)
(+) Non-operating interest income, net(1)		(39	)		151
(–) Interest portion of long-term provisions		252			120

Adjusted interest income, net		(1,027	)		(1,031	)


(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 decreased by €98 million or 16.6 percent in 2005 from €589 million in 2004 to €491 million. In 2005, net book gains primarily resulted from the sale of other securities held by the Central Europe market unit (€371 million). In addition, the Central Europe market unit realized a gain on disposal of €90 million from the transfer of shares in TEAG. In 2004, net book gains resulted from the sale of equity interests in EWE and VNG (€317 million), the sale of shares of Union Fenosa and other securities held by the Central Europe market unit (€221 million) and the sale of an additional 3.6 percent of Degussa’s share capital to RAG (€51 million). These book gains are calculated on a more inclusive basis than those discussed above in the analysis of 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 decreased by 71.0 percent to €29 million in 2005, compared with €100 million in 2004. 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. In 2004, the principal expenses contributing to this item were restructuring costs of €63 million at the U.K. market unit, mainly attributable to the integration of Midlands Electricity, and restructuring costs of €37 million at the Central Europe market unit that were primarily attributable to the merger of a number of its regional distribution companies into E.ON Hanse and E.ON Westfalen Weser.

The income reported as other non-operating results amounted to €440 million in 2005, compared with €110 million in 2004. In 2005, other non-operating earnings positively reflected unrealized gains from the required marking to market of derivatives under SFAS 133 (€1.2 billion), 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 approximately €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 approximately €347 million attributable to its direct 42.9 percent shareholding in Degussa. For more information, see Note 6 of the Notes to Consolidated Financial Statements. Additional offsetting effects on other non-operating earnings were storm-related costs for rebuilding of the distribution grid and compensating customers of approximately €140 million at the Nordic market unit, impairments recorded at cogeneration facilities in the U.K. market unit (€129 million), and an adjustment of deferred taxes (€103 million) made at an equity holding of the Corporate Center. In 2004, positive other non-operating results in the amount of approximately €290 million were attributable to unrealized gains from the required marking to market of derivatives under SFAS 133, primarily at the U.K. market unit, which were partially offset by unusual charges on investments at the Central Europe and U.K. market units (€110 million) and by impairment charges on real estate and short-term securities at the Central Europe market unit (€84 million). For more information, see Note 6 of the Notes to Consolidated Financial Statements.

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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, nuclear and hydroelectric generation businesses, transmission, 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 other 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 17.1 percent to €24,295 million (including €1,049 million of electricity taxes and €248 million in intersegment sales) in 2005, compared with a total of €20,752 million (including €1,051 million of electricity taxes and €212 million in intersegment sales) in 2004. The overall increase of €3,543 million reflected higher sales at each of Central Europe’s business units other than its Other/ Consolidation 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, in each case excluding electricity taxes:

SALES OF CENTRAL EUROPE MARKET UNIT

Percent

2005

2004

Change

(€ in millions)

Central Europe West

20,408

17,576

+16.1

Power

16,945

14,597

+16.1

Gas

3,463

2,979

+16.2

Central Europe East

2,618

1,877

+39.5

Other/ Consolidation

220

248

-11.3

Total

23,246

19,701

+18.0

Sales of the Central Europe West Power business unit increased by €2.348 million or 16.1 percent from €14,597 million in 2004 to €16,945 million in 2005. The increase was primarily attributable to higher electricity prices and higher grid access fees (approximately €750 million) as well as to an increase in the sale of electricity produced from renewable resources (approximately €570 million), as the volume of such energy, which E.ON Energie is required to purchase under regulatory requirements, increased in 2005. Increased trading revenues contributed approximately €480 million to the overall increase, with the remainder reflecting increases in sales volumes and in other revenues.

Sales of the Central Europe West Gas business unit increased by 16.2 percent from €2,979 million in 2004 to €3,463 million in 2005, with the increase of €484 million primarily reflecting higher gas prices (approximately €425 million) as well as the first-time consolidation of two gas companies at E.ON Bayern and of GVT (approximately €205 million). These positive factors were partly offset by lower sales volumes, with the decrease reflecting weather-related effects as well as increased competition.

Sales of the Central Europe East business unit increased by 39.5 percent or €741 million, from €1,877 million in 2004 to €2,618 million in 2005, with the increase primarily due to the first-time inclusion of results from the 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 E.ON Moldova (consolidated

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as of September 2005) (together approximately €530 million). Higher electricity prices in Hungary and the Czech Republic also contributed to the increase.

Total power procured by the Central Europe market unit (excluding physically-settled trading activities) rose 6.7 percent to 271.3 billion kWh in 2005, compared with 254.3 billion kWh in 2004, primarily reflecting an increase in power procured from third parties. E.ON Energie’s own production of power declined by 1.7 percent from 131.3 billion kWh in 2004 to 129.1 billion kWh in 2005. E.ON Energie produced approximately 48 percent of its power requirements in 2005, compared with approximately 52 percent in 2004. Compared with 2004, electricity purchased from jointly operated power stations increased by 7.1 percent from 11.2 billion kWh to 12.0 billion kWh. Purchases of electricity from third parties increased by 16.4 percent, from 111.8 billion kWh in 2004 to 130.2 billion kWh in 2005, largely due to the first-time consolidation of the electricity distribution companies in Bulgaria and Romania (approximately 6 TWh), as well as the purchase of significant higher volumes of renewable source electricity produced from renewable resources, which is regulated under Germany’s Renewable Energy Law (approximately 6 TWh). The residual rise was mainly related to an increase in short- and midterm trading volumes.

In 2005, the Central Europe market unit contributed adjusted EBIT of €3,930 million, a 9.1 percent increase from a total of €3,602 million in 2004. 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


								Percent
			2005			2004		Change

			(€ in millions)
Central Europe West				3,696			3,311		+11.6
	Power			3,389			2,996		+13.1
	Gas			307			315		-2.5
Central Europe East				237			235		+0.9
Other/ Consolidation				(3	)		56		—

		Total		3,930			3,602		+9.1

Adjusted EBIT at the Central Europe West Power business unit increased by €393 million from €2,996 million in 2004 to €3,389 million in 2005. This 13.1 percent increase was primarily attributable to higher wholesale electricity prices which could be passed on to customers (approximately €610 million) as well as operational improvements (approximately €80 million). The positive effects of these factors on the business unit’s adjusted EBIT were partly offset by higher fuel costs (approximately €210 million), primarily reflecting significantly higher prices for hard coal. Costs for the purchase of electricity from jointly owned power plants and from third parties increased by approximately €90 million. Procurement of CO₂ emission certificates also reduced overall adjusted EBIT at Central Europe West Power by a net amount of €46 million.

Adjusted EBIT of the Central Europe West Gas business unit declined by 2.5 percent to €307 million in 2005, compared with €315 million in 2004. The decrease of €8 million was primarily the result of lower sales volumes due to weather related effects as well as increased competition (approximately €30 million). This effect was partially offset by the first time consolidation effect of two gas companies at E.ON Bayern and of GVT (€15 million), as well as increased gas transport revenues.

The Central Europe East business unit contributed adjusted EBIT of €237 million in 2005, a 0.9 percent increase from €235 million in 2004. As expected, the first time consolidation of the Bulgarian, Romanian and Hungarian companies did not have a material impact on the business unit’s adjusted EBIT in 2005.

Central Europe’s Other/ Consolidation business unit recorded a €59 million decline in adjusted EBIT, from adjusted EBIT of €56 million in 2004 to adjusted EBIT of negative €3 million in 2005. The 2004 result had reflected the release of provisions relating to E.ON Energie in 2004.

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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.

The results of the Downstream Shareholdings business unit have included the results of Distrigaz Nord since July 1, 2005. The results of the Up-/ Midstream business unit included 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 35.4 percent to €17,914 million (including €3,110 million of natural gas and electricity taxes and €1,079 million in intersegment sales) in 2005, compared with a total of €13,227 million (including €2,923 million of natural gas and electricity taxes and €556 million in intersegment sales) in 2004. The increase was mainly attributable to higher sales volumes, as well as higher average sales prices.

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

Percent

2005

2004

Change

(€ in millions)

Up-/ Midstream

13,380

9,274

+44.3

Downstream

1,848

1,358

+36.1

Other/ Consolidation

(424

)

(328

)

-29.3

Total

14,804

10,304

+43.7

Sales in the Up-/ Midstream business unit increased in 2005 by €4,106 million or 44.3 percent from €9,274 million to €13,380 million, with the increase being primarily attributable to the increase of average sales prices in the midstream activities (approximately €2.4 billion) as well as a rise in sales volumes (from 641.4 billion kWh to 690.2 billion kWh). The business unit’s overall sales figure also benefited from the increase of sales prices (€102 million) and higher sales volumes (€31 million), primarily resulting from higher production of the Njord oil and gas field and of the Scoter gas field, as well as the first-time inclusion of E.ON Ruhrgas North Sea (€35 million) within the exploration and production activities.

In the Downstream Shareholdings business unit, sales increased by €490 million or 36.1 percent to €1,848 million in 2005 compared with €1,358 million in 2004. The main reason for the change was an increase in sales in ERI’s downstream operations (€347 million), particularly Distrigaz Nord (€199 million) and Ferngas Nordbayern (€144 million). The overall figure also reflected an increase in sales of €143 million at Thüga’s downstream operations, reflecting changes in the basis of consolidation at Thüga Italia (€50 million) and higher average gas prices at Thüga in Germany (€45 million).

The total volume of gas sold by E.ON Ruhrgas’ midstream operations increased by 7.6 percent to 690.2 billion kWh in 2005 from 641.4 billion kWh in 2004. Sales to domestic distributors decreased by 1.5 percent from 328.7 billion kWh to 323.7 billion kWh. Sales to domestic municipal utilities increased by 3.1 percent from 156.1 billion kWh to 160.9 billion kWh. E.ON Ruhrgas sold 70.4 billion kWh of gas to domestic industrial customers, an increase of 2.0 percent from 69.0 billion kWh in 2004. Exports reached 135.2 billion kWh in 2005, a 54.3 percent increase from 87.6 billion kWh in 2004. E.ON Ruhrgas purchased approximately 84.5 percent of its gas supplies from outside Germany and approximately 15.5 percent from German producers in 2005, compared with 83.2 percent and 16.8 percent, respectively, in 2004. In the Downstream Shareholdings business unit, total gas sales volumes increased by 35.3 percent from 51.0 billion

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kWh in 2004 to 69.0 billion kWh in 2005. Thüga increased its sales volumes by 7.7 percent to 22.5 billion kWh from 20.9 billion kWh, primarily due to changes in the basis of consolidation at Thüga Italia. Sales volumes at ERI rose by 54.5 percent to 46.5 billion kWh, largely due to the first time inclusion of Distrigaz Nord in the second half of 2005.

Adjusted EBIT of the Pan-European Gas market unit increased by 14.3 percent to €1,536 million in 2005 from €1,344 million in 2004. The rise in adjusted EBIT reflected positive results in the Up-/ Midstream business unit as well as 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

Percent

2005

2004

Change

(€ in millions)

Up-/ Midstream

988

862

+14.6

Downstream Shareholdings

551

486

+13.4

Other/ Consolidation

)

+25.0

Total

1,536

1,344

+14.3

Adjusted EBIT in the Up-/ Midstream business unit increased by €126 million or 14.6 percent from €862 million in 2004 to €988 million in 2005. The €104 million increase in adjusted EBIT at the upstream activities primarily reflected higher production volumes, as well as higher average sales prices. Adjusted EBIT in the midstream activities increased by €22 million. Contributing to the increase were positive effects from hedging activities (€103 million), the recalculation of fees for the use of natural gas pipelines (€61 million), higher income from share investments (€44 million), the impact of increased sales volumes as well as changes in the sales portfolio structure (€44 million), higher results from capacity charges mainly due to the impact of higher temperature spikes (€35 million) and higher transportation volumes (€31 million). These positive effects were partially offset by negative impacts derived from price effects (€255 million) (e.g., reflecting higher procurement costs attributable to the sharp increase in heating oil prices and the underlying linkage between these prices and natural gas prices), as well as negative results from trading derivatives (€39 million).

In the Downstream Shareholdings business unit, adjusted EBIT increased by €65 million or 13.4 percent to €551 million in 2005 from €486 million in 2004. This increase reflected positive developments at Thüga (€95 million), that were attributable to changes in the basis of consolidation at Thüga Italia, higher equity earnings and lower writedowns. ERI’s adjusted EBIT decreased by €30 million, largely due to the inclusion of the results of Distrigaz Nord for the second half of the year 2005.

U.K.

Total sales of the U.K. market unit in 2005 increased by 19.9 percent to €10,176 million (including €74 million in intersegment sales) from €8,490 million (including €10 million in intersegment sales) in 2004, primarily as a result of significantly increased sales in the Non-Regulated Business business unit, as explained in more detail below.

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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

Percent

2005

2004

Change

(€ in millions)

Non-regulated Business

9,553

7,788

+22.7

Regulated Business

813

941

-13.6

Other/ Consolidation

(190

)

(239

)

+20.5

Total

10,176

8,490

+19.9

Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and trading) and retail businesses in the U.K., increased by €1,765 million from €7,788 million in 2004 to €9,553 million in 2005. This 22.7 percent increase was primarily attributable to higher retail prices (€1,222 million) and higher market commodity gas and power sales (approximately €752 million), the effects of which were offset in part by a reduction in retail sales volumes (€209 million) primarily arising in the industrial and commercial business.

Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, decreased to €813 million in 2005 from €941 million in 2004. The sales decrease of €128 million, or 13.6 percent, was attributable to the reallocation of new business income from turnover to below gross margin (€72 million), the disposal of non-core businesses acquired in the Midlands acquisition and other items (€38 million) and tariff changes (€18 million).

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 €190 million in 2005, as compared to a negative impact of €239 million in 2004.

The volume of electricity sold by the U.K. market unit decreased by 7.1 billion kWh or 8.6 percent to 75.0 billion kWh, as compared with 82.1 billion kWh in 2004. Mass market sales increased by 1.1 billion kWh or 3.1 percent to 37.3 billion kWh, while those to industrial and commercial customers decreased by 4.2 billion kWh or 15.9 percent to 22.3 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 power purchased from outside sources. Own production increased by 2.4 billion kWh or 7.0 percent from 34.9 billion kWh in 2004 to 37.3 billion kWh in 2005. Power purchased from other suppliers decreased by 7.9 billion kWh or 17.0 percent to 39.2 billion kWh from 47.1 billion kWh. In addition, the volume of power purchased from power stations in which E.ON UK has an interest of 50 percent or less decreased by 1.4 billion kWh or 69.4 percent as a result of the acquisition of remaining shares in the CDC power station. Gas sales increased by 6.6 billion kWh or 3.7 percent from 175.9 billion kWh in 2004 to 182.5 billion kWh in 2005, with the increase reflecting higher market sales (7.2 billion kWh), offset in part by lower sales to industrial and commercial customers (3.4 billion kWh), as well as an increase in gas used for the market unit’s own generation (1.3 billion kWh). E.ON UK satisfied its increased need for gas mainly through an increase of 7.6 billion kWh or 6.0 percent in market purchases, while the volume of gas being sourced under long-term gas supply contracts decreased by 1.1 billion kWh or 2.1 percent from 49.5 billion kWh in 2004 to 48.4 billion kWh in 2005.

Adjusted EBIT at the U.K. market unit decreased by €54 million or 5.3 percent from €1,017 million in 2004 to €963 million in 2005, reflecting a decrease at Other/ Consolidation, which more than offset higher results of the Non-regulated Business and the Regulated Business, as described in more detail below.

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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

Percent

2005

2004

Change

(€ in millions)

Non-regulated Business

661

626

+5.6

Regulated Business

452

446

+1.4

Other/ Consolidation

(150

)

(55

)

-172.7

Total

963

1,017

-5.3

The Non-regulated Business contributed adjusted EBIT of €661 million in 2005. This €35 million or 5.6 percent increase from €626 million in 2004 mainly resulted from higher retail prices and the realization of additional cost savings from the integration of the former TXU retail business (€1,282 million), which were partially offset by increased commodity input costs which include the new CO₂ emission certificates and other items (€1,247 million).

The Regulated Business increased its adjusted EBIT from €446 million in 2004 to €452 million in 2005. The 1.4 percent increase was almost entirely attributable to the first-time full-year inclusion of Midlands Electricity, which was acquired on January 16, 2004.

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 €150 million in 2005, as compared with negative €55 million in 2004. The change was primarily attributable to additional project expenditure and service costs associated with acquisitions (€40 million), the absence of earnings from Asian Asset Management activities following the divestment of that business (€32 million) and an expiry of deferred warranty income from previous asset sales (€18 million).


	*Nordic*

Total sales of the Nordic market unit increased from €3,347 million in 2004 (including €395 million of electricity and natural gas taxes and €66 million in intersegment sales) to €3,471 million (including €402 million of electricity and natural gas taxes and €102 million in intersegment sales) in 2005. This 3.7 percent increase was primarily attributable to increased sales in Sweden.

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

Percent

2005

2004

Change

(€ in millions)

Sweden

2,821

2,714

+3.9

Finland

248

238

+4.2

Total

3,069

2,952

+4.0

Sales in Sweden increased by €107 million or 3.9 percent from €2,714 million to €2,821 million, primarily due to higher average spot prices in conjunction with successful hedging activities.

Sales in Finland increased from €238 million to €248 million. This 4.2 percent increase was mainly attributable to the sale of CO₂ emission certificates.

Total power supplied by E.ON Nordic (excluding physically settled trading activities) decreased by 1.6 percent to 48.5 billion kWh in 2005, compared with 49.5 billion kWh in 2004. The decrease of one billion

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kWh reflected a reduction in the volume of power sold to residential customers by 6.6 percent from 9.1 billion kWh in 2004 to 8.5 billion kWh in 2005, primarily reflecting the effects of the January storm. Sales to commercial customers decreased by 4.8 percent to 13.8 billion kWh in 2005 compared with 14.5 billion kWh in 2004, also reflecting the impact of the January storm. Sales to sales partners and Nordpool increased slightly by 1.2 percent from 25.9 billion kWh in 2004 to 26.2 billion kWh in 2005, primarily resulting from increased generation in owned power plants. E.ON Nordic’s own production rose by 3.6 percent from 33.1 billion kWh in 2004 to 34.3 billion kWh in 2005, mainly resulting from increased hydropower generation (2.1 billion kWh). This was partially offset by a decline in nuclear power production (0.9 billion kWh) that primarily reflected the fact that the availability of Swedish nuclear power plants in 2004 had been unusually high. E.ON Nordic purchased less power, primarily from outside sources (1.5 billion kWh) mostly reflecting lower imports from Germany. Purchases from jointly owned power stations declined (0.6 billion kWh) due to a lower availability in these plants. The total volume of gas sold to third parties decreased slightly in 2005 to 7.0 billion kWh from 7.1 billion kWh in 2004, mainly resulting from slightly lower sales to industrial customers (0.2 billion kWh).

Adjusted EBIT at the Nordic market unit increased by €105 million or 15.0 percent from €701 million to €806 million, primarily reflecting higher results in Sweden, 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

Percent

2005

2004

Change

(€ in millions)

Sweden

765

662

+15.6

Finland

+5.1

Total

806

701

+15.0

Adjusted EBIT in Sweden increased by €103 million from €662 million in 2004 to €765 million in 2005. This 15.6 percent increase reflected the rising electricity wholesale prices in conjunction with successful hedging activities, which enabled E.ON Nordic to record higher effective prices per unit for energy generated from its electricity production portfolio (€83 million), as well as higher hydropower production (€27 million). In addition, the results of E.ON Sverige’s gas operations improved due to a favorable spread between gas oil and fuel oil prices (€10 million). The positive effects of these factors on E.ON Sverige’s adjusted EBIT were partially offset by rebranding costs (€15 million).

In Finland, adjusted EBIT increased by €2 million from €39 million in 2004 to €41 million in 2005. This 5.1 percent increase mainly resulted from the sale of CO₂ emission certificates (€7.5 million), partially offset by lower revenues at the electricity retail operations (€6.0 million).

U.S. Midwest

Total sales of the U.S. Midwest market unit amounted to €2,045 million in 2005, an increase of 19.0 percent from €1,718 million in 2004. The increase primarily reflected higher retail sales due to higher electric and gas rates effective July 1, 2004, higher off-system sales due to both higher volumes and higher prices, as well as higher retail electric volumes resulting from warmer summer and fall weather.

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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

Percent

2005

2004

Change

(€ in millions)

Regulated Business

1,965

1,643

+19.6

Non-regulated Business

+6.7

Total

2,045

1,718

+19.0

Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, increased by €322 million to €1,965 million in 2005, from €1,643 million in 2004. The 19.6 percent increase was attributable to higher recovery from customers of passed-through costs of fuel used for generation (€91 million) and of gas supply costs (€54 million), higher revenues from off-system electric sales reflecting higher wholesale electric prices driven by higher gas prices and higher volumes (€49 million), an increase in retail volumes resulting from warmer summer and fall weather (€49 million), higher retail prices following the rate increases that took effect in mid-2004 (€43 million), MISO revenue sufficiency guarantee payments (€35 million), higher wholesale natural gas sales (€10 million) and higher environmental cost recoveries (€9 million). These positive effects were partially offset by the impact of the expiration of the ESM (€11 million).

Sales of the Non-regulated Business, which primarily consists of ECC and its subsidiaries, increased by €5 million or 6.7 percent from €75 million in 2004 to €80 million in 2005, with the increase being primarily due to higher revenues in the Argentina operations due to higher summer gas volumes.

Adjusted EBIT at the U.S. Midwest market unit increased by 3.1 percent from €354 million in 2004 to €365 million in 2005.

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

Percent

2005

2004

Change

(€ in millions)

Regulated Business

351

339

+3.5

Non-regulated Business

-6.7

Total

365

354

+3.1

Adjusted EBIT at the Regulated Business increased by €12 million or 3.5 percent from €339 million in 2004 to €351 million in 2005. The increase was primarily attributable to the increase in sales resulting from increased retail electric and gas rates that went into effect July 1, 2004 (€43 million), higher retail electric volumes due to warmer summer and fall weather (€38 million) and the contribution from off-system sales (€38 million), reflecting higher wholesale electric prices driven by higher gas prices and higher volumes. These positive effects were partially offset by costs associated with participation in MISO (€49 million), higher purchased power costs due to unit outages (€31 million), higher operating expenses (€14 million), the impact of the expiration of the ESM (€11 million) and higher depreciation on newly installed assets (€11 million).

Adjusted EBIT at E.ON U.S.’s Non-regulated Business was generally consistent with 2004, decreasing by €1 million or 6.7 percent, from €15 million in 2004 to €14 million in 2005.

Corporate Center

The Corporate Center reduced Group sales by €1,502 million in 2005, compared with reducing sales by €792 million in 2004. The reduction in adjusted EBIT attributable to the segment was €399 million in 2005,

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compared with €338 million in 2004. 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.

Other Activities

Effective February 1, 2004, Degussa has been accounted for using the equity method in line with E.ON’s minority shareholding in the company. Under the equity method, Degussa’s sales are not included in E.ON’s consolidated sales. From February 1, 2004, a percentage of Degussa’s earnings after taxes and minority interests equal to E.ON’s proportionate interest is recorded in E.ON’s financial earnings. After selling a further 3.6 percent interest, E.ON has owned 42.9 percent of Degussa since June 1, 2005 and 42.9 percent of Degussa’s earnings after taxes and minority interests are recorded in E.ON’s financial earnings. Degussa contributed €132 million to adjusted EBIT in 2005, compared with €107 million in 2004. For information of the framework agreement regarding the planned disposal of E.ON’s remaining interest in Degussa, see “— Overview.”

As of December 31, 2005, Degussa took an impairment charge of €836 million (before taxes) in its Fine Chemicals business unit due to significant changes in market conditions. For more information on the impact on E.ON, see the discussion of other non-operating results in the reconciliation of adjusted EBIT for the E.ON Group above.

YEAR ENDED DECEMBER 31, 2004 COMPARED WITH YEAR ENDED DECEMBER 31, 2003

E.ON Group

E.ON’s sales in 2004 increased 5.4 percent to €42,384 million from €40,223 million in 2003 (in each case net of electricity and natural gas taxes). As noted above, the increase was primarily attributable to consolidation effects. As illustrated in the table on page 131, the overall increase in the Group’s sales reflected an increase in sales in the core energy business as a whole and at each of its market units other than U.S. Midwest and the Corporate Center, the effect of which was partially offset by a sharp decline in sales at E.ON’s Other Activities, primarily due to the fact that the 2003 results included one month of Degussa’s sales prior to its deconsolidation as of February 1, 2003.

Sales of the Central Europe market unit increased 7.8 percent in 2004 to €20,752 million (including €1,051 million of electricity taxes) from €19,253 million (including €1,015 million of electricity taxes) in 2003. Pan-European Gas’ sales increased by 11.0 percent to €13,227 (including €2,923 million of natural gas and electricity taxes) in 2004 from €11,919 million (including €2,555 million of natural gas and electricity taxes) in 2003. Sales of the U.K. market unit increased by 7.2 percent, amounting to €8,490 million in 2004 as compared to €7,923 million in 2003. The Nordic market unit grew its 2004 sales by 18.5 percent to €3,347 million (including €395 million of electricity and natural gas taxes) from €2,824 million (including €324 million of electricity and natural gas taxes) in 2003. Sales of the U.S. Midwest market unit decreased by 3.0 percent in 2004 to €1,718 million compared with €1,771 million in 2003. The elimination of intersegment sales at the Corporate Center resulted in the segment reporting negative sales of €575 million in 2003 and €792 million in 2004. The sales of each of these segments are discussed in more detail below.

Total cost of goods sold and services provided in 2004 increased 2.0 percent or €629 million to €31,441 million compared with €30,812 million in 2003, with increases at the Pan-European Gas market unit (€956 million) primarily reflecting the effect of the first-time full-year inclusion of the former Ruhrgas activities, at the Central Europe market unit (€419 million), primarily resulting from higher procurement costs, and at the Nordic market unit (€273 million), mainly due to the first-time full-year inclusion of Graninge. These effects were largely offset by decreases at the Other Activities due to the deconsolidation of Degussa (€690 million), lower cost of goods sold and services provided at the Corporate Center (€170 million) and a similar decrease at the U.K. market unit (€109 million). Cost of goods sold as a percentage of revenues (net of electricity and natural gas taxes) decreased to 74.2 percent in 2004 from 76.6 percent in 2003, as sales increased more than the cost of goods sold and services provided. Gross profit therefore increased at a higher rate than sales, rising by 16.3 percent to €10,943 million in 2004 from €9,411 million in 2003.

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Selling expenses decreased 4.1 percent or €183 million to €4,235 million in 2004, compared with €4,418 million in 2003. The decline reflected an overall reduction of €209 million in selling expenses at the Central Europe market unit, including €90 million in reduced personnel costs and €63 million from the release of provisions, as well as the fact that the 2003 results reflected €136 million in selling expenses at Degussa. These effects were offset in part by an increase of €189 million in selling expenses at the U.K. market unit, primarily reflecting expenses at Midlands Electricity following its acquisition.

General and administrative expenses increased by €102 million, amounting to €1,350 million in 2004 compared with €1,248 million in 2003. The 8.2 percent increase was primarily attributable to an increase of €148 million in such costs at the Central Europe market unit, including an impairment charge of €73 million for real estate, as well as personnel costs arising from the first-time consolidation of E.ON Facility Management (€48 million). An increase of €78 million at the Nordic market unit mainly reflecting the first-time full-year inclusion of Graninge also contributed to the higher total. The factors were offset in part by the fact that the 2003 results included €77 million of general and administrative expenses from Degussa, as well as lower general and administrative expenses at the U.K. market unit in 2004 (€5 million).

Other operating income (expenses), net decreased to €1,361 million in 2004 from €1,658 million in 2003. This decrease of €297 million, or 17.9 percent, reflected lower net book gains on the disposal of businesses and fixed assets and increased expenses arising from exchange rate differences. Net book gains decreased by €843 million year on year, amounting to €473 million in 2004, compared with €1,316 million in 2003. The 2004 figure primarily included gains from the sales of stakes in EWE and VNG (€317 million), the sale of an additional 3.6 percent of Degussa’s share capital to RAG (€51 million), the sale of shares in Union Fenosa (€26 million) and the sale of certain shareholdings at the Central Europe market unit (€57 million). The higher net book gains of €1,316 million for 2003 included gains from the sale of E.ON’s 15.9 percent interest in Bouygues Telecom (€840 million), the sale of 18.1 percent of Degussa’s shares to RAG (€168 million), as well as from the sale of a number of shareholdings at the Central Europe market unit (aggregating €150 million). Net expenses arising from exchange rate differences increased by €348 million, from income of €39 million in 2003 to expenses of €309 million in 2004, reflecting results from the recognition of exchange rate movements on foreign currency transactions and net realized losses on foreign currency derivatives. The impact of the lower net book gains and higher expenses from exchange rates differences on the overall figure was partially offset by an increase in gains on the required marking to market of derivatives (€201 million) and a reduction in write-downs of non-fixed assets (€168 million). Miscellaneous other operating income (expenses), net increased by €498 million, amounting to income of €662 million in 2004, as compared with income of €164 million in 2003. This improved result was primarily attributable to income from the reversal of certain provisions (approximately €158 million) and higher net gains from the sale of short-term securities (approximately €106 million). For further information, see Note 5 of the Notes to Consolidated Financial Statements.

Financial earnings decreased by €126 million, or 52.9 percent, resulting in a loss of €364 million in 2004 compared with a loss of €238 million in 2003. The decrease was primarily attributable to an increase of €84 million in interest and similar expenses, net, a decline of €22 million in income from share investments and an increase of €20 million in write-downs of financial assets and long-term loans. For additional information, see Note 6 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 increased by 23.0 percent or €1,190 million to income of €6,355 million in 2004, as compared with income of €5,165 million in 2003.

In 2004, E.ON recorded income tax expenses of €1,850 million, as compared to a tax expense of €1,145 million in 2003. The increase of €705 million or 61.6 percent primarily reflected the improved operating results. Changes in tax rates and tax laws that took effect in 2004 also resulted in increased tax expenses of approximately €142 million, including deferred tax expenses of €77 million. These effects were partially offset by the change in valuation allowances for deferred taxes on loss carryforwards that amounted to income of €202 million in 2004 as compared to expenses of €542 million in 2003. For additional information, see Note 7 of the Notes to Consolidated Financial Statements.

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Income attributable to minority interests, and therefore deducted in the calculation of net income, was €478 million in 2004, as compared to €445 million in 2003, with the increase of €33 million, or 7.4 percent, reflecting improved results at a number of the entities in which the Group holds a minority interest.

Results from discontinued operations increased net income by €312 million in 2004, as compared to a contribution of €1,512 million to net income in 2003. The significant decrease is due to the book gains recorded on the disposal of discontinued operations in 2003, including Gelsenwasser, Viterra Energy Services and Viterra Contracting, which did not recur in 2004. The Group’s net income decreased 6.6 percent, totaling €4,339 million in 2004, compared with €4,647 million in 2003. Excluding the results of discontinued operations, E.ON would have recorded net income of €4,027 million in 2004, as compared to net income of €3,135 million in 2003.

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 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 2005, 2004 and 2003 appears in the table on page 132. 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 31 of the Notes to Consolidated Financial Statements.

As detailed in the table below, adjusted interest income, net increased by €484 million or 31.9 percent to an expense of €1,031 million in 2004 from an expense of €1,515 million in 2003, primarily due to a reduction of €355 million in the interest portion of long-term provisions, of which approximately €270 million related to amendments to Germany’s Ordinance on Advance Payments for the Establishment of Federal Facilities for Safe Custody and Final Storage for Radioactive Wastes (Endlager-Vorausleistungsverordnung). Under the amended ordinance, construction costs for the final storage facilities at Gorleben and Konrad will now be shared by nuclear plant operators and by other users, such as research institutes, in line with their expected actual usage of the storage facilities, thus lowering E.ON’s share of the costs. Non-operating interest income, net amounted to income of €62 million in 2003 and an expense of €151 million in 2004, with the change reflecting an increase in accruals for interest payments due on taxes for audit periods which are still under review.


	2004			2003

	(€ in millions)
Interest income and similar expenses (net) as shown in Note 6 of the Notes to Consolidated Financial Statements		(1,062	)		(978	)
(+) Non-operating interest income, net(1)		151			(62	)
(–) Interest portion of long-term provisions		120			475

Adjusted interest income, net		(1,031	)		(1,515	)


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

Net book gains in 2004 decreased by 53.1 percent from €1,257 million in 2003 to €589 million. In 2004, net book gains resulted from the sale of equity interests in EWE and VNG (€317 million), the sale of shares of Union Fenosa and other securities held by the Central Europe market unit (€221 million) and the sale of an additional 3.6 percent of Degussa’s share capital to RAG (€51 million). In 2003, net book gains mainly resulted from the sale of E.ON’s 15.9 percent interest in Bouygues Telecom (€840 million), E.ON’s sale of 18.1 percent of Degussa to RAG (€168 million) and the sale of securities at E.ON Energie (approximately €165 million). Additional book gains in the amount of approximately €160 million were primarily attributable to E.ON Energie’s sale of its interest in swb (€85 million) and Powergen’s disposal of certain power plants (€24 million). The overall impact of these gains in 2003 was offset in part by a loss of €76 million recorded on the sale by E.ON Energie of a 1.9 percent interest in HypoVereinsbank in March of that year. These book gains are calculated on a more inclusive basis than those discussed above in the analysis of 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

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and losses realized by equity investees, which are included in the income statement as a component of financial earnings.

Cost-management and restructuring expenses decreased by 79.1 percent to €100 million in 2004, compared with €479 million in 2003. In 2004, the principal expenses contributing to this item were restructuring costs of €63 million at the U.K. market unit, mainly attributable to the integration of Midlands Electricity, and restructuring costs of €37 million at the Central Europe market unit that were primarily attributable to the merger of a number of its regional distribution companies into E.ON Hanse and E.ON Westfalen Weser. In 2003, the principal expenses contributing to this item were primarily costs attributable to the Central Europe market unit (€358 million), including those resulting from the merger of regional distributors noted above. Additional restructuring costs of €121 million were attributable to the U.K. market unit’s integration of the former TXU Group retail activities.

The income reported as other non-operating results amounted to €110 million in 2004, compared with €195 million in 2003. In 2004, positive other non-operating results in the amount of approximately €290 million were attributable to unrealized gains from the required marking to market of derivatives under SFAS 133 primarily at the U.K. market unit, which were partially offset by unusual charges on investments at the Central Europe and U.K. market units (€110 million) and by impairment charges short-term securities at the Central Europe market unit (€84 million). In 2003, other non-operating earnings primarily reflected the positive effects from the required marking to market of derivatives (€494 million), which was partially offset by the impact of an impairment charge that Degussa took as of September 30, 2003. Degussa recorded an impairment charge of €500 million (before taxes) in its Fine Chemicals business unit due to significant changes in market conditions. As a result of this impairment charge, E.ON recorded a loss of €187 million attributable to its direct shareholding in Degussa (then 46.5 percent). For more information, see Note 6 of the Notes to Consolidated Financial Statements.

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, nuclear and hydroelectric generation businesses, transmission, 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 and district heating 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 shareholdings in regional distribution companies in the Czech Republic, Hungary and Slovakia. Other/ Consolidation primarily includes the results of other 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 7.8 percent to €20,752 million (including €1,051 million of electricity taxes and €212 million in intersegment sales) in 2004, compared with a total of €19,253 million (including €1,015 million of electricity taxes and €270 million in intersegment sales) in 2003. The overall increase of €1,499 million reflected higher sales at each of Central Europe’s business units other than its Central Europe West Gas business unit, as described in more detail below.

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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 electricity taxes:

SALES OF CENTRAL EUROPE MARKET UNIT

Percent

2004

2003(1)

Change

(€ in millions)

Central Europe West

17,576

16,814

+4.5

Power

14,597

13,662

+6.8

Gas

2,979

3,152

-5.5

Central Europe East

1,877

1,308

+43.5

Other/ Consolidation

248

116

+113.8

Total

19,701

18,238

+8.0


(1)	Excludes sales of Thüga and the activities transferred to the Pan-European Gas market unit and those of E.ON Sverige and the other businesses of E.ON Nordic.

Sales of the Central Europe West Power business unit increased by €935 million or 6.8 percent from €13,662 million in 2003 to €14,597 million in 2004. The increase was primarily attributable to an increase in the sale of electricity from renewable resources, reflecting regulatory requirements (approximately €550 million), as well as higher electricity prices (approximately €275 million).

Sales of the Central Europe West Gas business unit decreased by 5.5 percent from €3,152 million in 2003 to €2,979 million in 2004, with the decrease of €173 million reflecting a decrease of 9.5 TWh or 8.5 percent in the volume of gas sold that was primarily attributable to warmer temperatures in 2004 compared with 2003.

Sales of the Central Europe East business unit increased by 43.5 percent or €569 million, from €1,308 million in 2003 to €1,877 million in 2004, with the increase being primarily due to the first-time inclusion of a full year of results from JME and JCE, which were consolidated as of October 2003 (approximately €520 million).

Total power procured by the Central Europe market unit (excluding physically-settled trading activities) rose 5.5 percent to 254.3 billion kWh in 2004, compared with 241.0 billion kWh in 2003. E.ON Energie’s own production of power declined by 4.2 percent from 137.1 billion kWh in 2003 to 131.3 billion kWh in 2004, largely as a result of the shut down of the nuclear power plant Stade in November 2003 as part of Germany’s planned phase-out of nuclear power (4.6 TWh). E.ON Energie produced approximately 52 percent of its power requirements in 2004, compared with approximately 57 percent in 2003. Compared with 2003, electricity purchased from jointly operated power stations increased by 5.7 percent from 10.6 billion kWh to 11.2 billion kWh. Purchases of electricity from third parties increased by 19.8 percent, from 93.3 billion kWh in 2003 to 111.8 billion kWh in 2004, largely due to the first-time inclusion of full year results at JME and JCE (approximately 9 TWh), as well as a significant increase in purchases of energy produced from renewable sources (approximately 8 TWh).

In 2004, the Central Europe market unit contributed adjusted EBIT of €3,602 million, a 20.9 percent increase from a total of €2,979 million in 2003. The overall increase reflected improved adjusted EBIT results at each of the market unit’s business units, as described in more detail below.

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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


								Percent
			2004		2003(1)			Change

			(€ in millions)
Central Europe West				3,311		2,819			+17.5
	Power			2,996		2,530			+18.4
	Gas			315		289			+9.0
Central Europe East				235		172			+36.6
Other/ Consolidation				56		(12	)		—

		Total		3,602		2,979			+20.9


(1)	Excludes results of Thüga and the activities transferred to the Pan-European Gas market unit and those of E.ON Sverige and the other businesses of E.ON Nordic.

Adjusted EBIT at the Central Europe West Power business unit increased by €466 million from €2,530 million in 2003 to €2,996 million in 2004. This 18.4 percent increase was primarily attributable to higher electricity prices (€275 million), as well as lower expenses for nuclear fuel management (approximately €270 million) largely due to lower depreciation expense as a consequence of a reduction of the remaining asset base. The release of provisions contributed €151 million in adjusted EBIT. These provisions related to additional costs relating to the Renewable Energy Law and the Co-Generation Protection Law and to allegedly excessive grid access fees and were released following court decisions confirming E.ON’s position that such costs can be passed on to consumers and that such fees were not excessive. Adjusted EBIT for 2003 had also been negatively impacted by €124 million in payments settling accounts in control and balance areas based on unbundling requirements, including those due for prior years, whereas similar costs in 2004 totaled approximately €10 million. The positive effects of these factors on the business unit’s adjusted EBIT were partly offset by increased provisions for legal obligations in the grid business (approximately €160 million) and higher fuel costs (€56 million), primarily reflecting significantly higher prices for hard coal. In addition, the positive effect arising from the closing out of certain positions by EST’s trading unit in 2003 (€130 million), did not recur in 2004.

Adjusted EBIT of the Central Europe West Gas business unit grew by 9.0 percent to €315 million in 2004, compared with €289 million in 2003. The increase of €26 million was primarily the result of the effect on margins (€77 million), largely reflecting optimized procurement, the effect of which was partially offset by the impact of the largely weather-related decline in the volume of gas sales noted above (€40 million).

The Central Europe East business unit contributed adjusted EBIT of €235 million in 2004, a 36.6 percent increase from €172 million in 2003. This €63 million increase was primarily attributable to the inclusion of JME and JCE for the entire period under review (€44 million) and improved results at E.ON Hungária (€36 million), which were partly offset due to an impairment charge at one of the business unit’s shareholdings (€11 million).

In the Other/ Consolidation business unit, Central Europe recorded a €68 million improvement in adjusted EBIT, from adjusted EBIT of negative €12 million in 2003 to adjusted EBIT of €56 million in 2004. The primary reason was the release of provisions relating to E.ON Energie.

Pan-European Gas

Following its acquisition, Ruhrgas’ results were included in E.ON’s Consolidated Financial Statements from February 1, 2003. As a result of E.ON’s on.top project, a majority of E.ON Energie’s interest in Thüga and its interests in a number of smaller gas companies were transferred to E.ON Ruhrgas in late 2003 and early 2004. As explained above, all of the financial data for 2003 presented in this comparison have been reclassified to conform to the new market unit structure and therefore include the results of Thüga and the other transferred companies within those for the Pan-European Gas market unit for all of both 2003 and 2004. E.ON Ruhrgas was

149

consolidated for all of 2004. This first-time full-year consolidation effect is reflected in an increase in many of the market unit’s results for 2004, as compared to the reclassified results for 2003. In order to better present trends in the underlying business, this analysis also discusses certain changes in the market unit’s results for 2003 (including the former Ruhrgas activities for the eleven months beginning February 1 and Thüga and the other transferred activities for the full year) compared with figures for 2004 (the “adjusted 2004 figures”) prepared on the same basis (excluding the results of the former Ruhrgas activities for January). The adjusted 2004 figures are unaudited.

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 increased by 11.0 percent to €13,227 million (including €2,923 million of natural gas and electricity taxes and €556 million in intersegment sales) in 2004, compared with a total of €11,919 million (including €2,555 million of natural gas and electricity taxes and €389 million in intersegment sales) in 2003, with the increase reflecting sales increases at each of the business units that were primarily attributable to the full-year consolidation effect, as described in more detail below. On the basis of the adjusted 2004 figures, the market unit’s sales (including natural gas and electricity taxes and intersegment sales) decreased by €146 million or 1.2 percent, mainly due to lower sales in the Up-/ Midstream business unit, as described in more detail below.

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

Percent

2004

2003(1)

Change

(€ in millions)

Up-/ Midstream

9,274

8,360

+10.9

Downstream

1,358

1,326

+2.4

Other/ Consolidation

(328

)

(322

)

-1.9

Total

10,304

9,364

+10.0


(1)	Includes sales of the former Ruhrgas activities for the period from February 1 to December 31 and those of Thüga and the other transferred activities for the full year.

Sales in the Up-/ Midstream business unit increased by 10.9 percent from €8,360 million to €9,274 million, with the increase being entirely attributable to the full-year consolidation effect, which is amplified by the fact that January (which is included in the 2004 results, but excluded with respect to the former Ruhrgas activities from those for 2003) is traditionally a month of significantly higher than average sales. On the basis of the adjusted 2004 figures, the business unit’s sales decreased by €159 million or 1.9 percent, primarily due to a decline of approximately €230 million in gas sales in the midstream operations. This decrease reflected the combined effect of a decline in average prices (approximately €400 million) and the impact of lower temperature spikes (the fact that the coldest days of 2004 were warmer than those of 2003 was reflected in decreased demand for gas on those days and therefore a lower capacity charge for the period) (approximately €120 million), which were partially offset by positive volume and mix effects in the midstream operations (approximately €290 million). The business unit’s overall sales figure also benefited from the initial sales contribution from the exploration and production activities of E.ON Ruhrgas Norge (€45 million).

In the Downstream Shareholdings business unit, sales increased by 2.4 percent to €1,358 million in 2004 compared with €1,326 million in 2003, again due to the full-year consolidation effect. On the basis of the

150

adjusted 2004 figures, sales decreased by €36 million or 2.7 percent, reflecting the impact of the negative price effects described above on the unit’s operations, particularly Ferngas Nordbayern.

Sales volumes also reflected the impact of the first-time inclusion of the former Ruhrgas’ activities for the entire year. Total gas sold by E.ON Ruhrgas’ midstream operations increased by 20.0 percent to 641.4 billion kWh in 2004 from 534.5 billion kWh in the eleven months of 2003, with increases recorded in sales to each category of customer. Sales to domestic distributors increased by 16.6 percent from 282.0 billion kWh to 328.7 billion kWh. Sales to domestic municipal utilities increased by 14.5 percent from 136.3 billion kWh to 156.1 billion kWh. E.ON Ruhrgas sold 69.0 billion kWh of gas to domestic industrial customers, an increase of 16.4 percent from 59.3 billion kWh in 2003. Exports reached 87.6 billion kWh in 2004, a 54.0 percent increase from 56.9 billion kWh in 2003. E.ON Ruhrgas purchased approximately 83.2 percent of its gas supplies from outside Germany and approximately 16.8 percent from German producers in 2004, compared with 82.5 percent and 17.5 percent, respectively, in 2003. In the Downstream Shareholdings business unit, total gas sales volumes increased by 9.9 percent from 46.4 billion kWh in 2003 to 51.0 billion kWh in 2004. Thüga increased its sales volumes by 28.2 percent to 20.9 billion kWh from 16.3 billion kWh, primarily due to the inclusion of Thüga Italia. Sales volumes at ERI were stable at 30.1 billion kWh.

Adjusted EBIT of the Pan-European Gas market unit decreased by 4.1 percent to €1,344 million from a total of €1,401 million in 2003, as the positive full-year consolidation effect was more than offset by other factors, particularly negative price effects that contributed to a decline in adjusted EBIT 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

Percent

2004

2003(1)

Change

(€ in millions)

Up-/ Midstream

862

923

-6.6

Downstream Shareholdings

486

484

+0.4

Other/ Consolidation

)

+33.3

Total

1,344

1,401

-4.1


(1)	Includes results of the former Ruhrgas activities for the period from February 1 to December 31 and those of Thüga and the other transferred activities for the full year.

Adjusted EBIT in the Up-/ Midstream business unit decreased by €61 million or 6.6 percent from €923 million in 2003 to €862 million in 2004. On the basis of the adjusted 2004 figures, adjusted EBIT decreased by €247 million or 26.7 percent, reflecting the impact of the “time lag effect” (approximately €190 million) resulting from the fact that increases in market reference prices for gas and competing fuels are generally reflected in the prices E.ON Ruhrgas pays for gas under its long-term purchase contracts before they are reflected in the prices paid by customers under sales contracts (see “Item 3. Key Information — Risk Factors”), as well as that of the lower temperature spikes noted above (approximately €120 million). These negative factors were partially offset by the impact of increased sales volumes (approximately €70 million) and the contribution of E.ON Ruhrgas Norge (€19 million).

In the Downstream Shareholdings business unit, adjusted EBIT increased by €2 million or 0.4 percent to €486 million in 2004 from €484 million in 2003 due to the full-year consolidation effect. On the basis of the adjusted 2004 figures, adjusted EBIT decreased by €16 million or 3.3 percent. The fact that the 2003 result had included €24 million in adjusted EBIT from Bayerngas and VNG, which were disposed of in late 2003 and early 2004, as well as impairments to shareholdings, including Stadtwerke Chemnitz, of €30 million, more than offset the positive impact of improved results at a number of the business unit’s international shareholdings (€44 million), including SPP.

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	*U.K.*

Total sales of the U.K. market unit in 2004 increased by 7.2 percent to €8,490 million (including €10 million in intersegment sales) from €7,923 million (including €8 million in intersegment sales) in 2003, primarily as a result of significantly increased sales in the Regulated Business business unit reflecting the first-time inclusion of the results of Midlands Electricity following its consolidation as of January 16, 2004. The overall increase of €567 million reflected higher sales at each of U.K.’s business units, as described 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

Percent

2004

2003

Change

(€ in millions)

Non-regulated Business

7,788

7,682

+1.4

Regulated Business

941

438

+114.8

Other/ Consolidation

(239

)

(197

)

-21.3

Total

8,490

7,923

+7.2

Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and trading) and retail businesses in the U.K., increased by €106 million from €7,682 million in 2003 to €7,788 million in 2004. This 1.4 percent increase was primarily attributable to higher retail prices (€538 million) and positive exchange rate effects (€164 million), the effects of which were largely offset by a reduction in retail sales volumes and mix (€553 million) primarily arising in the industrial and commercial business.

Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, more than doubled, increasing to €941 million in 2004 from €438 million in 2003. The sales increase of €503 million was almost entirely attributable to the first-time inclusion of the results of Midlands Electricity.

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 €239 million in 2004 as compared to a negative impact of €197 million in 2003.

The volume of electricity sold by the U.K. market unit decreased by 9.5 billion kWh or 10.4 percent to 82.1 billion kWh, as compared with 91.6 billion kWh in 2003. Mass market sales decreased by 1.3 billion kWh or 3.4 percent to 36.2 billion kWh, while those to industrial and commercial customers decreased by 8.0 billion kWh or 23.2 percent to 26.5 billion kWh, reflecting the market unit’s focus in this segment on securing margins rather than volume. The decrease in sales was reflected in each of the sources of power. Own production decreased by 1.0 billion kWh or 2.7 percent from 35.9 billion kWh in 2003 to 34.9 billion kWh in 2004. Power purchased from other suppliers decreased by 6.5 billion kWh or 12.2 percent to 47.1 billion kWh from 53.6 billion kWh. In addition, the volume of power purchased from power stations in which E.ON UK has an interest of 50 percent or less decreased by 2.2 billion kWh or 52.3 percent as a result of the acquisition of remaining shares in the CDC power station. Gas sales increased by 5.2 billion kWh or 3.1 percent from 170.7 billion kWh in 2003 to 175.9 billion kWh in 2004, with the increase reflecting higher market sales (3.6 billion kWh) and higher sales to industrial and commercial customers (0.3 billion kWh), as well as an increase in gas used for the market unit’s own generation (1.9 billion kWh). E.ON UK satisfied its increased need for gas mainly through an increase of 10.8 billion kWh or 9.4 percent in market purchases, while the volume of gas being sourced under long-term gas supply contracts decreased by 5.6 billion kWh or 10.2 percent from 55.1 billion kWh in 2003 to 49.5 billion kWh in 2004.

Adjusted EBIT at the U.K. market unit increased by €407 million or 66.7 percent from €610 million in 2003 to €1,017 million in 2004, reflecting higher results of the Non-regulated Business and the Regulated Business, partially offset by a decrease at Other/ Consolidation, as described in more detail below.

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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

Percent

2004

2003

Change

(€ in millions)

Non-regulated Business

626

412

+51.9

Regulated Business

446

225

+98.2

Other/ Consolidation

(55

)

(27

)

-103.7

Total

1,017

610

+66.7

The Non-regulated Business contributed adjusted EBIT of €626 million in 2004. This €214 million or 51.9 percent increase from €412 million in 2003 mainly resulted from the realization of additional cost savings from the integration of the former TXU retail business (€91 million) and higher retail margins (€54 million), as the impact of higher retail prices was only partially offset by increased fuel costs. The overall increase also reflected lower retail gas transportation and metering costs (€47 million) and higher recycled benefits, i.e. receipts from the ROC buy-out fund (€22 million).

In the Regulated Business, E.ON UK almost doubled its adjusted EBIT, which increased from €225 million in 2003 to €446 million in 2004. This increase was almost entirely attributable to the first-time inclusion of Midlands Electricity.

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 €55 million in 2004, as compared with negative €27 million in 2003. The change was primarily attributable to the relative absence of positive offsetting factors in 2004 and reflected a lower contribution from property sales (€19 million) and the Asian Asset Management activities (€10 million) following the divestment of that business.

Nordic

Total sales of the Nordic market unit increased from €2,824 million in 2003 (including €324 million of electricity and natural gas taxes and €48 million in intersegment sales) to €3,347 million (including €395 million of electricity and natural gas taxes and €66 million in intersegment sales) in 2004. This 18.5 percent increase was primarily attributable to the first-time inclusion of a full year of results from Graninge, which was consolidated in November 2003.

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

Percent

2004

2003

Change

(€ in millions)

Sweden

2,714

2,216

+22.5

Finland

238

284

-16.2

Total

2,952

2,500

+18.1

Sales in Sweden increased by €498 million or 22.5 percent from €2,216 million to €2,714 million, primarily due to the first-time full-year inclusion of Graninge (€264 million) and increased sales volumes made possible by generation reflecting historically high availability of nuclear power production and an improved hydrological situation (€110 million).

153

Sales in Finland decreased from €284 million to €238 million. This 16.2 percent decrease was mainly attributable to a reduction in the sales volumes of E.ON Finland’s trading operations.

Total power supplied by E.ON Nordic (excluding physically settled trading activities) rose 22.0 percent to 49.5 billion kWh in 2004, compared with 40.5 billion kWh in 2003. The increase of 9.0 billion kWh reflected an increase in the volume of power sold to all customer segments. Sales to residential customers increased 38.1 percent from 6.6 billion kWh in 2003 to 9.1 billion kWh in 2004, primarily reflecting the inclusion of Graninge. Sales to commercial customers increased by 7.1 percent to 14.5 billion kWh in 2004 compared with 13.5 billion kWh in 2003, mainly due to the inclusion of Graninge. Sales to sales partners and Nordpool increased by 26.6 percent from 20.4 billion kWh in 2003 to 25.9 billion kWh in 2004, primarily resulting from increased generation in own and jointly owned power plants. E.ON Nordic’s own production rose by 29.4 percent from 25.6 billion kWh in 2003 to 33.1 billion kWh in 2004, mainly resulting from the increased hydro and nuclear power generation (4.3 billion kWh) and the first-time full-year inclusion of Graninge (3.2 billion kWh). E.ON Nordic purchased more power, primarily from jointly owned power stations (1.0 billion kWh) due to a higher availability in these plants. The total volume of gas sold to third parties increased slightly in 2004 to 7.1 billion kWh from 7.0 billion kWh in 2003, as the positive effect of the inclusion of Graninge (0.5 billion kWh) was largely offset by lower gas sales from existing operations (0.4 billion kWh), primarily reflecting lower consumption of selected industrial and commercial customers and slightly higher average temperatures in 2004.

Adjusted EBIT at the Nordic market unit increased by €155 million or 28.4 percent from €546 million to €701 million, reflecting higher results in Sweden that were partially offset by a decrease in Finland, 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

Percent

2004

2003

Change

(€ in millions)

Sweden

662

484

+36.8

Finland

+37.1

Total

701

546

+28.4

Adjusted EBIT in Sweden increased by €178 million from €484 million in 2003 to €662 million in 2004. This 36.8 percent increase reflected the impact of increased sales volumes reflecting greater availability of nuclear and hydroelectric generation assets (€89 million), as well as improved margins in E.ON Sverige’s retail electricity (€17 million) and heat (€15 million) businesses. In addition, the consolidation of Graninge for the full year was responsible for €63 million of the increase in adjusted EBIT.

In Finland, adjusted EBIT decreased by €23 million from €62 million in 2003 to €39 million in 2004. This 37.1 percent decrease mainly resulted from the combination of the reduction in trading volumes noted above and the fact that trading profits in the first half of 2003 had been exceptionally high.

U.S. Midwest

Total sales of the U.S. Midwest market unit amounted to €1,718 million in 2004, a decrease of 3.0 percent from €1,771 million in 2003. The decrease was attributable to the decline in the value of the U.S. dollar against the euro, which negatively affected the translation of the U.S. Midwest market unit’s dollar-denominated revenues into euro, E.ON’s reporting currency. In local currency, sales increased by 6.6 percent over the prior year.

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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

Percent

2004

2003

Change

(€ in millions)

Regulated Business

1,643

1,663

-1.2

Non-regulated Business

108

-30.6

Total

1,718

1,771

-3.0

Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, decreased by €20 million or 1.2 percent to €1,643 million in 2004, from €1,663 million in 2003. The decrease was attributable to the impact of unfavorable exchange rates, as sales increased by $164 million in dollar terms, from $1,880 million in 2003 to $2,044 million in 2004. This 8.7 percent increase in dollar-denominated sales was mainly attributable to higher retail prices following the rate increases that took effect in mid-2004 ($46 million), an increase in sales volumes resulting from warm spring weather ($36 million), the higher recovery of gas supply costs from customers ($34 million), higher revenues from off-system electric sales reflecting higher wholesale electric prices driven by higher gas prices ($21 million), higher environmental cost recoveries ($19 million), and the impact of an adjustment to the 2003 earnings sharing mechanism, which was approved by the KPSC during 2004 ($12 million). These effects were partially offset by the impact of a decline of approximately 1 billion kWh in gas sales, due largely to mild winter weather conditions in 2004 ($6 million).

Sales of the Non-regulated Business, which primarily consists of ECC and its subsidiaries, declined by €33 million or 30.6 percent from €108 million in 2003 to €75 million in 2004. In dollar terms, sales decreased by $29 million, from $122 million in 2003 to $92 million in 2004. This 23.8 percent decrease was primarily attributable to the completion of the Tiger Creek construction project, which had contributed $40 million in sales in 2003, the effect of which was partially offset by a $9 million increase in sales from the Argentine business, reflecting an increase in customer demand and more favorable exchange rates.

Adjusted EBIT at the U.S. Midwest market unit increased by 11.3 percent from €318 million in 2003 to €354 million in 2004. In dollar terms, adjusted EBIT grew by 22.6 percent to $440 million from $359 million in 2003.

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

Percent

2004

2003

Change

(€ in millions)

Regulated Business

339

306

+10.8

Non-regulated Business

+25.0

Total

354

318

+11.3

Adjusted EBIT at the Regulated Business increased by €33 million or 10.8 percent from €306 million in 2003 to €339 million in 2004. In dollar terms, adjusted EBIT increased by 21.7 percent. The increase was primarily attributable to the increase in sales in dollar terms resulting from increased retail electric and gas rates that went into effect July 1, 2004 and increased retail electric sales volumes due to unseasonably warm spring weather (€65 million). In addition, the contribution from off-system sales was higher (€14 million), as prices in the off-system wholesale electric market for 2004 were higher than 2003 due to high gas prices and strong demand during 2004. The impact of the increase in dollar-denominated sales more than offset the impact of the negative exchange rate effects (€34 million) and that of additional storm-related costs from the severe spring and summer storms that caused significant damage to the utility operation’s distribution network (€12 million).

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Adjusted EBIT at E.ON U.S.’s Non-regulated Business was generally consistent with 2003, increasing by €3 million or 25.0 percent, from €12 million in 2003 to €15 million in 2004. In dollar terms, adjusted EBIT increased by 46.2 percent.

Corporate Center

The Corporate Center reduced Group sales by €792 million in 2004, compared with reducing sales by €575 million in 2003. The reduction in adjusted EBIT attributable to the segment was €338 million in 2004, compared with €323 million in 2003. 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.

Other Activities

Effective February 1, 2003, Degussa has been accounted for using the equity method in line with E.ON’s minority shareholding in the company. Under the equity method, Degussa’s sales are not included in E.ON’s consolidated sales. From February 1, 2003, a percentage of Degussa’s earnings after taxes and minority interests equal to E.ON’s proportionate interest is recorded in E.ON’s financial earnings. After selling a further 3.6 percent interest, E.ON has owned 42.9 percent of Degussa since June 1, 2004 and 42.9 percent of Degussa’s earnings after taxes and minority interests are recorded in E.ON’s financial earnings. Degussa contributed €107 million to adjusted EBIT in 2004, compared with €176 million in 2003. In 2003, Degussa had contributed sales of €994 million for the one month of January.

INFLATION

The rates of inflation in Germany during 2005, 2004 and 2003 were 2.0 percent, 1.6 percent and 1.1 percent, respectively on chained prices base. The effects of inflation on E.ON’s operations have not been significant in recent years.

EXCHANGE RATE EXPOSURE AND CURRENCY RISK MANAGEMENT

Certain business activities within the E.ON Group result in foreign exchange rate exposures. Of the Group’s consolidated revenues in 2005, 2004 and 2003, 35 percent, 34 percent and 33 percent, respectively, were attributable to customers located outside of member states participating in the EMU.

To manage the Group’s exposure to exchange rate fluctuations, E.ON continually monitors its exposures to currency risks and pursues a systematic and Group-wide foreign exchange risk management policy. At the end of 2005, the Group’s consolidated foreign exchange rate exposure, which is calculated as its netted transaction risk exposure deriving from booked and forecasted transactions excluding any foreign exchange translation exposure from net investments in entities with a functional currency other than the euro, was approximately €2.2 billion, compared with approximately €1.8 billion at year-end 2004. The increase in the Group’s foreign exchange rate exposure was primarily due to the increased gas sales prices and an increase in gas volumes sold by the Pan-European Gas market unit in the U.K. The Group’s foreign exchange rate exposure is principally attributable to the market units Central Europe and U.K. (which have short positions in U.S. dollars), Pan-European Gas (which has a long position in British pounds) and Nordic (which has a long position in Norwegian krona). Due to the acquisition of the Powergen Group and the additional E.ON Sverige shares, the E.ON Group also has a net investment in assets denominated in British pounds, U.S. dollars and Swedish krona, which is continually monitored and partly hedged with foreign exchange instruments in accordance with the financial guidelines of the E.ON Group.

The principal derivative financial instruments used by E.ON to cover foreign currency exposures are foreign exchange forward contracts, cross currency swaps, interest rate cross currency swaps and currency options. As of December 31, 2005, the E.ON Group had entered into foreign exchange forward contracts with a nominal value of €12.4 billion, cross currency swaps with a nominal value of €16.3 billion, interest rate cross currency swaps with a nominal value of €0.4 billion and currency options with a nominal value of €0.4 billion. The currencies in

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which the Group’s derivative financial instruments are denominated reflect the currencies in which it is subject to transaction and translation risks. For further information, see “Item 11. Quantitative and Qualitative Disclosures about Market Risk” and Note 28 of the Notes to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

The principal source of liquidity for E.ON in 2005 was again cash provided by operating activities. Cash provided by operating activities amounted to €6,601 million in 2005, €5,840 million in 2004 and €5,307 million in 2003. The 13.0 percent increase in cash provided by operating activities in 2005 was primarily attributable to changes in tax payments, and in particular to the change in the VAT treatment of gas transactions in the Pan-European Gas market unit. Other positive effects were higher prepayments by customers in December at the Pan-European market unit, the increase in gross margin at the Central Europe market unit and effects resulting from the elimination of currency swaps in the Corporate Center. These improvements were partially offset by payments to pension funds at the U.K. market unit, increased pension contributions to the VKE fund (Versorgungskasse Energie) at the Central Europe market unit, and storm-related payments at the Nordic market unit.

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, other financial assets and intangible and fixed assets, amounted to €6,599 million in 2005, €2,606 million in 2004 and €5,598 million in 2003. In 2005, divestment proceeds were primarily attributable to the sale of Viterra and Ruhrgas Industries.

E.ON’s principal liquidity requirement in recent years has been for purchases of financial assets (including equity investments) and other fixed assets. Capital expenditures in 2005, 2004 and 2003 amounted to €4,337 million, €5,109 million and €9,013 million, respectively, and are reported in the Consolidated Statements of Cash Flows as the sum of purchases of equity investments, other financial assets and intangible and fixed assets. In 2005 and in 2004, investments in fixed and intangible assets exceeded purchases of equity investments and other financial assets. The relative decrease in capital expenditures in 2005 and 2004 reflected the relative absence of major acquisitions as compared to 2003. 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 2005 were for fixed and intangible assets at a number of the market units, particularly Central Europe and U.K., as well as for payments related to the acquisition of Distrigaz Nord, NRE, Electrica Moldova and Enfield. Proceeds from the divestitures of Viterra and Ruhrgas Industries, offset in part by 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 increased from €382 million cash used in 2004 to €399 million cash provided in 2005 (€39 million cash provided in 2003).

Cash used for financing activities totaled €6,465 million, with the increase from €4,766 million in 2004 primarily reflecting the increased repayment of financial liabilities in 2005 described below, as well as higher dividend distributions. In 2003, cash provided by financing activities had totaled €3,105 million.

As of December 31, 2005, the Group had cash and cash equivalents from continuing operations of €4,413 million, as compared with €3,801 million at December 31, 2004 (€3,169 million at year-end 2003).

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The following table shows the cash provided by operating activities and used for capital expenditures for each of the Group’s segments in 2005, 2004 and 2003 (in each case excluding the cash flows of discontinued operations, see “— Results of Operations — Business Segment Information” above).

E.ON BUSINESS SEGMENT CASH FLOW AND CAPITAL EXPENDITURES(1)


			2005					2004				2003

			Cash from		Capital			Cash from		Capital		Cash from			Capital
			Operations		Expenditures			Operations		Expenditures		Operations			Expenditures

			(€ in millions)
Central Europe(2)				3,020		2,177			2,938		2,527		4,081			2,126
Pan-European Gas(2)				1,999		531			903		614		942	(3)		611	(3)
U.K.				101		926			633		503		315			388
Nordic				746		538			957		740		773			1,265
U.S. Midwest(2)				214		227			152		247		154			411
Corporate Center(2)				521		(62	)		257		478		(865	)		4,176	(4)

	Core Energy Business			6,601		4,337			5,840		5,109		5,400			8,977
	Other Activities(2)			—		—			—		—		(93	)		36

		Total		6,601		4,337			5,840		5,109		5,307			9,013


(1)	For a detailed description of capital expenditures by purchases of financial assets and purchases of other fixed assets, see Note 27 of the Notes to Consolidated Financial Statements.

(2)	Excludes the cash from operations and capital expenditures of certain activities now accounted for as discontinued operations. For more details, see “— Acquisitions and Dispositions — Discontinued Operations” and Note 4 of the Notes to Consolidated Financial Statements.

(3)	Includes the cash flows of the former Ruhrgas activities for the period from February 1 to December 31 and those of Thüga and other transferred activities for the full year.

(4)	Includes the acquisition of shares of Ruhrgas in 2003.

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 acquisitions of equity investments in energy companies and other financial assets, as well as additions to property, plant and equipment and intangible assets. Capital expenditures at the Central Europe market unit decreased by 13.9 percent from €2,527 million in 2004 to €2,177 million in 2005. Investments in property, plant and equipment and intangible assets amounted to €1,519 million, mainly consisting of assets used in conventional, waste disposal and renewable power generation and in distribution. The Central Europe market unit invested €658 million in financial assets, of which €126 million were due to the acquisitions of interests in the Dutch NRE (€67 million) and the Romanian Electrica Moldova (now E.ON Moldova) (€59 million). Capital expenditures of the Central Europe market unit amounted to €2,527 million in 2004, with €1,388 million invested in property, plant and equipment and intangible assets primarily used in power generation and distribution. Investments in financial assets amounted to €1,139 million, with the largest single category being intra-Group acquisitions from the Pan-European Gas market unit in connection with the new market unit structure (€404 million), the largest of which was the acquisition of additional interests in Ferngas Salzgitter (€230 million). The investment in financial assets also included advance payments in connection with the acquisition of interests in Varna and Gorna Oryahovitza (€141 million), and the purchase of additional shares in Ferngas Salzgitter from third parties (€133 million) and increased stakes in a number of companies in the Czech Republic and Hungary (€106 million). Capital expenditures in the Central Europe market unit in 2003 amounted to €2,126 million. Of this amount, €1,255 million was attributable to investments in property, plant and equipment and intangible assets focused primarily on power generation and

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distribution assets. The largest equity investment was the acquisition of additional stakes in JME and JCE (€207 million).

The Pan-European Gas market unit’s level of capital expenditures decreased by 13.5 percent compared with 2004. In 2005, the Pan-European Gas market unit invested €531 million, of which €263 million was spent on property, plant and equipment and intangible assets, primarily in the transmission system and upstream activities. The remaining €268 million in capital expenditures was used for financial assets, with the largest single item being the €90 million spent acquiring the 51.0 percent stake in the Romanian gas distribution company Distrigaz Nord. In 2004, the Pan-European Gas market unit invested €614 million, of which €105 million was spent on property, plant and equipment and intangible assets, primarily in the transmission system. The majority of the remaining €509 million in capital expenditures was for financial assets, with the largest single item being the €223 million spent acquiring the remaining 3.4 percent stake in Thüga in the squeeze-out process. Capital expenditures in the Pan-European Gas market unit in 2003 amounted to €611 million, of which €442 million were for financial assets, most significantly the financing of the purchase of additional shares of Gazprom by the Russian entity in which E.ON Ruhrgas holds an interest. The remaining €169 million related to investments in property, plant and equipment and intangible assets, primarily for the improvement of the technical infrastructure.

Investments in the U.K. market unit increased by 84.1 percent to €926 million in 2005 compared with €503 million in 2004. Investments in property, plant and equipment and intangible assets amounted to €565 million, mainly in renewable generation, conventional power stations, and the regulated distribution business. The U.K. market unit invested €361 million in financial assets, primarily due to the acquisitions of Enfield and HGSL. In 2004, the U.K. market unit spent €511 million on fixed and intangible assets and negative €8 million was attributable to financial assets. The majority of the investments in fixed assets was attributable to expenditures in the distribution business (€320 million), and the maintenance of the generation portfolio (€185 million). Capital expenditures in the U.K. market unit in 2003 amounted to €388 million, primarily due to additions to property, plant and equipment and intangible assets.

The Nordic market unit invested €538 million in 2005, a decrease of 27.3 percent, with €407 million dedicated to property, plant and equipment and intangible assets primarily used to maintain production plants and to upgrade and expand its distribution network. Investments in financial assets amounted to €131 million with the largest single investment being the acquisition of district heating activities from the Danish utility Nesa A/ S. In 2004, the Nordic market unit’s capital expenditures amounted to €740 million. Of this amount, €390 million was attributable to investments in financial assets. The largest equity investment was the acquisition of additional Graninge shares (€307 million). The Nordic market unit also invested €350 million in property, plant and equipment and intangible assets in order to maintain its existing production facilities, as well as to upgrade and enhance the distribution network. Capital expenditures in 2003 amounted to €1,265 million. The largest equity investment was the acquisition of 42.7 percent of Graninge (€628 million).

Capital expenditures in the U.S. Midwest market unit decreased by 8.1 percent to €227 million in 2005, all of which was invested in property, plant and equipment and intangible assets. The decline reflected the fact that the regulated operations had completed a number of pollution control projects in 2004. In 2004, the total amount of €247 million was invested in property, plant and equipment and intangible assets, primarily in the regulated business. The decrease from 2003 principally reflected the fact that environmental control and combustion turbine equipment under construction in 2003 was placed into service in 2004. In 2003, all of the capital expenditures of €411 million were attributable to property, plant and equipment and intangible assets, mainly in the regulated business.

In the Corporate Center, capital expenditures decreased significantly to negative €62 million in 2005. The Corporate Center invested negative €71 million in financial assets. The Corporate Center segment’s level of capital expenditures in 2004 amounted to €478 million. The majority of this amount was invested in financial assets, primarily payments to holders of outstanding bonds of Midlands Electricity as part of its acquisition (€881 million) and in the Thüga squeeze-out (€223 million), with the impact of these investments on the segment’s total partially offset by the elimination of intersegment transactions. In 2003, capital expenditures at the Corporate Center segment reflected significant acquisition activity by E.ON AG, the impact of which was

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partially offset by consolidation effects. The total of €4,176 million in 2003 was primarily attributable to the purchase of the remaining shares of Ruhrgas in the first quarter.

In 2005 and 2004, E.ON did not record any capital expenditures at the Other Activities segment. Capital expenditures at the Other Activities segment in 2003 amounted to €36 million at Degussa.

Financial Liabilities. The financial liabilities of E.ON decreased to €14,362 million at year-end 2005 from €20,301 million at year-end 2004. The decrease of €5,939 million or 29.3 percent primarily resulted from a reduction in commercial paper outstanding (€3,631 million) and reductions in the outstanding amount of bank loans (€2,469 million), the overall effects of which were partially offset by an increase in bonds outstanding (€390 million). Bank loans decreased from €3,999 million at year-end 2004 to €1,530 million at year-end 2005, as a total of €1,348 million in loans were repaid, while €287 million were drawn down. €424 million (27.7 percent) of the amounts payable under bank loans at year-end 2005 are due in 2006, €183 million (12.0 percent) due in 2007, €116 million (7.6 percent) due in 2008, €74 million (4.8 percent) due in 2009, €356 million (23.3 percent) due in 2010 and €377 million (24.6 percent) due after 2010. Up to December 31, 2004, non-interest-bearing and low-interest liabilities of Viterra were reported net of the interest portion in the Consolidated Balance Sheet. Due to the disposal of Viterra in 2005, no deduction of the interest portion was reported as of December 31, 2005. For more detailed information on interest rates, maturities, significant covenants, cross-default provisions and E.ON’s compliance therewith, as well as other details of the Group’s financial liabilities, including the credit facilities and Commercial Paper and Medium Term Note programs of E.ON AG and certain of its subsidiaries, see Note 24 of the Notes to Consolidated Financial Statements.

E.ON follows a centralized financing policy. Most of the financing transactions of E.ON’s market units have been centralized and netted at the Group level to reduce the Group’s overall debt and interest expense. As a general rule, external financings will be undertaken at the E.ON AG level (or via finance subsidiaries under its guarantee) and on-lent as needed within the Group. In certain limited circumstances, future financings may also take place at the subsidiary level, e.g. for reasons of tax efficiency or regulatory compliance. E.ON’s aim is to maximize its financing efficiency and minimize structural subordination issues that would arise if significant external debt was held at the operating subsidiary level. Over time it is E.ON’s intention to refinance outstanding external subsidiary debt as it falls due with intercompany loans.

To support E.ON’s centralized financing policy, E.ON AG has a Commercial Paper program and a Medium Term Note program with aggregate authorized amounts of €10 million and €20 million, 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 €10 billion. For additional information on these programs, including amounts outstanding and available as of year-end 2005, see Note 24 of the Notes to Consolidated Financial Statements.

At year-end 2005, 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. On April 30, 2004, Moody’s upgraded its long-term rating for E.ON bonds from “A1” to “Aa3” with a stable outlook. On March 14, 2005, S&P confirmed E.ON’s “AA-” long-term rating for E.ON’s bonds and revised the outlook from stable to negative. Following E.ON’s announcement of the conditional all-cash offer for up to 100 percent of Endesa on February 21, 2006, S&P placed its “AA-” long-term and “A-1+” short-term ratings on credit watch with negative implications. In the same context, on February 22, 2006, Moody’s placed its “Aa3” long-term rating on review for possible downgrade but affirmed the “Prime-1” short-term rating.

Expected Investment Activity. E.ON currently plans to invest a total of approximately €18.6 billion over the three years from 2006 to 2008. Management believes that capital expenditure is intended above all, to reinforce security of supply in E.ON’s markets. The majority of these capital expenditures (€16.3 billion) is earmarked for property, plant and equipment. Most of these investments (€15.1 billion) are intended to serve the modernization or building of power stations and grids. The remaining €1.2 billion is budgeted for the production of energy on renewable sources. Investments in financial investments of approximately €2.3 billion are especially earmarked for expanding shareholdings in Eastern Europe and in the natural gas production sector. This investment plan does not include the impact of the proposed acquisition of Endesa.

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Expenditures of approximately €7.4 billion are planned at the Central Europe market unit. Of this amount, approximately €6.6 billion is budgeted for property, plant and equipment, with about 40 percent (€2.6 billion) for power generation. In Germany, a new 1,100 MW coal-fired power station at Datteln and two combined-cycle power plant units at Irsching are to be built. Another modern gas-fired power station is to be built by E.ON at Livorno Ferraris in Italy. A total of €3.7 billion is budgeted for the expansion of power and gas grids in central Europe. €2.8 billion of this amount is intended for grid maintenance and expansion in Germany alone, one priority being the expansion of power grids to connect wind generation facilities. At the Pan-European Gas market unit, E.ON plans to invest approximately €3.2 billion, including €1.9 billion in the extension of gas transmission pipelines, storage and upstream facilities. A further €1.3 billion is earmarked for financial investments, especially in the upstream sector. Investments at the U.K. market unit totaling approximately €3.7 billion are planned with the focus again being on grids and power stations, including a 1,200 MW gas-fired power station and a 450 MW coal-fuelled power station. Power generation from renewable energy sources, especially wind energy, is also expected to be expanded. In addition, approximately €300 million are budgeted for financial investments in wind park companies. Total investment at the Nordic market unit is expected to amount to €2.7 billion, primarily for the modernization and extension of power and gas grids, enhancement of power stations, construction of a cogeneration plant in Malmö and several wind parks. At the U.S. Midwest market unit, capital expenditures totaling approximately €1.7 billion are budgeted. The emphasis will be on environmental measures at existing power stations as well as the upgrading of power and gas grids. E.ON U.S. also plans the construction of Trimble County 2, a 750 MW coal-fired power station.

The investment plan summarized above only contains projects that are sufficiently probable from today’s perspective. The Group expects to be able to finance the total volume of budgeted capital investments through cash provided by operating activities. E.ON believes its strong financial situation gives the Company the flexibility to carry out additional growth initiatives if they make strategic sense and create value.

The following material transactions are expected to have a significant impact on E.ON’s cash flows in 2006. Proceeds from the sale of Degussa are expected to total approximately €2.8 billion and an equivalent amount is expected to be distributed to shareholders as an extra cash dividend in 2006; firm estimates of expected proceeds for the other expected dispositions are not currently available. The acquisition of the interests in the MOL companies is expected to result in cash outflows totaling approximately €450 million (excluding the assumption of external financial debt and any payments upon exercise of the put options).

In addition, on February 21, 2006, E.ON announced that it had decided to file a takeover offer for 100 percent of the share capital of Endesa. The aggregate purchase price is expected to amount to up to approximately €29.1 billion if all shares and ADSs were to be tendered. Should the offer be successful, E.ON would also expect to include Endesa’s net financial liabilities, provisions and minority interests equal to approximately €26.1 billion (according to the Endesa SEC Filings) in its financial statements, thus bringing the aggregate transaction value to approximately €55.2 billion. E.ON intends to finance the acquisition through a combination of its own resources and new financing in the form of a committed line of credit provided by a syndicate of international banks. No assurance can be given that E.ON will be able to complete the transaction successfully on the proposed terms or at all. If completed, the transaction would have a significant impact on E.ON’s liquidity and capital resources, however the nature and timing of any such impact is unknown due to difficult to predict events which may or may not occur. For more information on the proposed acquisition, see “Item 4. Information on the Company — History and Development of the Company — Proposed Endesa Acquisition.”

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”). The board resolution allows for a maximum contribution of €5.4 billion. No payments to the trusts had been made as of the end of 2005. On March 8, 2006, E.ON made an initial contribution of €2.6 billion by transferring existing deposits with an original maturity in excess of three months to the trusts. This contribution will result in a significant reduction of E.ON’s pension provision.

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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, EME, Midlands Electricity and TXU into a single pool.

E.ON expects that cash flow from operations and cash received from disposals will continue to be the primary source of funds for its capital expenditures and working capital requirements in 2006. E.ON believes that its cash flow and available liquid funds and credit lines will be sufficient to meet its anticipated cash needs. In addition, various means of raising share capital are available to E.ON as discussed in “Item 10. Additional Information — Memorandum and Articles of Association — Changes in Capital” and Note 17 of the Notes to Consolidated Financial Statements. However, if the proposed acquisition of Endesa is completed, E.ON intends to finance the acquisition through a combination of its own cash resources and financing in the form of a committed line of credit provided by a syndicate of international banks.

Fair Value of Derivatives. E.ON has established risk management policies that allow the use of foreign currency, interest rate, and commodity derivative instruments and other instruments and agreements to manage its exposure to market, currency, interest rate, commodity 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.

The estimated fair value of commodity contracts used in the Group’s trading activities for the year ended December 31, 2005 is presented below:

FAIR VALUE RECONCILIATION TABLE

(€ in millions)


Fair value of contracts outstanding at the beginning of the period	382.5
Change to scope of consolidation	20.6
Contracts realized or otherwise settled during the period	(166.0	)
Fair value of new contracts entered into during the period	175.2
Changes in fair values attributable to changes in valuation techniques and assumptions	4.7
Other changes in fair values	1,057.3

Fair value of contracts outstanding at the end of the period	1,474.3

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 “Item 4. Information on the Company — Business Overview,” “— Risk Management,” “Item 11. Quantitative and Qualitative Disclosures about Market Risk” and Notes 28 and 29 of the Notes to Consolidated Financial Statements.

E.ON estimated the gross mark-to-market value of its commodity contracts as of December 31, 2005 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, weighted average probability 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.

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The following table shows the sources of prices used to calculate the fair value of commodity contracts at December 31, 2005. 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

	Maturity									Maturity in
	less than			Maturity			Maturity			Excess of			Total Fair
Source of Fair Value	1 Year			1-3 Years			4-5 Years			5 Years			Value

	(€ in millions)
Prices actively quoted		710.8			877.7			106.8			0.1			1,695.4
Prices provided by other external sources		44.0			75.0			9.0			(18.0	)		110.0
Prices based on models and other valuation methods		(149.6	)		(180.6	)		(9.6	)		8.7			(331.1	)

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.

RESEARCH AND DEVELOPMENT

E.ON only performs minimal research and development (“R&D”) activities. In 2005, E.ON spent approximately €24 million on R&D, compared with €19 million in 2004 and €36 million in 2003. In each of 2005, 2004 and 2003, E.ON’s R&D expenditures as a percentage of sales were below one percent. E.ON does not anticipate any significant changes in its R&D expenditures in the near term. The 2005 expenditures were attributable to the Nordic, Pan-European and U.K. market units. The E.ON Group employs 1,185 R&D employees.

TREND INFORMATION

For information on the principal trends and uncertainties affecting the Company’s results of operations and financial condition, see “Item 3. Key Information — Risk Factors,” the respective market unit descriptions in “Item 4. Information on the Company — Business Overview,” “— Operating Environment,” and “— Results of Operations” and “— Liquidity and Capital Resources” above.

PROCESS OF TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS

In July 2002, the European Parliament and Council passed Regulation No. 1606/2002 on the adoption of IFRS by European companies. In accordance with the Regulation, companies whose securities are publicly traded on a regulated market in an EU country are generally required to prepare their consolidated financial statements in accordance with IFRS, as adopted by the EU, for fiscal years commencing on or after January 1, 2005. The Regulation allowed individual EU member states to defer the deadline for adopting IFRS until 2007 in certain circumstances, particularly with respect to those companies that apply internationally accepted standards other than IFRS due to the fact that their securities are listed on a market outside of the EU. Germany adopted this deferral option in implementing the regulation. E.ON currently prepares its consolidated financial statements in accordance with U.S. GAAP. Accordingly, it qualifies for the German deferral option and is therefore required to prepare its consolidated financial statements for the fiscal year ending December 31, 2007 in accordance with IFRS as adopted by the EU. E.ON expects to meet this statutory deadline and to prepare an opening balance sheet in accordance with IFRS as of January 1, 2006 as part of its transition process. Even after E.ON has adopted IFRS as its primary accounting principles, it will be required to present a reconciliation of net income and stockholders’ equity in accordance with U.S. GAAP in its Annual Report on Form 20-F.

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In order to prepare for the transition, E.ON has begun a project to determine the relevant differences between IFRS and U.S. GAAP. However, it is currently not possible to determine the impact on the Company’s financial reporting of the conversion to IFRS with any certainty. In addition to the fact that the transition project is ongoing and has yet to be completed, the IFRS principles that E.ON will adopt for the fiscal year ending December 31, 2007 will be those then in effect. As a result, new pronouncements from the International Accounting Standards Board (“IASB”) and the required endorsement process by the EU prior to such date could have an impact on E.ON’s consolidated financial statements.

OFF-BALANCE SHEET ARRANGEMENTS

E.ON uses certain off-balance sheet arrangements in the ordinary course of business, including financial guarantees, lines of credit, indemnification agreements and other guarantees. E.ON’s arrangements in each of these categories are described in more detail below. For additional information, see Note 25 of the Notes to Consolidated Financial Statements.

Financial Guarantees. E.ON’s financial guarantees 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. These guarantees include arrangements that are characterized as direct and indirect obligations under FASB Interpretation No. (“FIN”) 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Direct obligations are those that give the party receiving the guarantee a direct claim against E.ON; indirect obligations are those under which E.ON has agreed to provide the funds necessary for another party to satisfy an obligation, such as pursuant to a keepwell arrangement.

The Company’s financial guarantees as of December 31, 2005 included certain direct obligations relating to E.ON’s generation of electricity from nuclear power plants in Germany and Sweden, primarily those arising from solidarity agreements in connection with the requirement that German nuclear power plant operators provide nuclear accident liability coverage of up to €2.5 billion per accident. These obligations are described in more detail in “Item 4. Information on the Company — Environmental Matters — Germany: Electricity” and Note 25 of the Notes to Consolidated Financial Statements. E.ON’s direct obligations also include direct financial guarantees issued in favor of the creditors of related parties and third parties. The Company’s obligations under these direct financial guarantees with specified terms extend as far as 2022, and the maximum undiscounted amounts potentially payable in the future under these direct guarantees totaled €427 million at December 31, 2005, compared with €737 million at year-end 2004. Of these amounts, €304 million and €534 million, respectively, involved guarantees issued on behalf of related parties (including financing arrangements for the Interconnector undersea gas pipeline). E.ON’s indirect financial guarantees primarily include obligations in connection with cross-border leasing transactions entered into by E.ON Benelux and obligations to provide financial support, primarily to related parties. E.ON’s obligations under indirect financial guarantees with specified terms extend as far as 2023. The maximum undiscounted amounts potentially payable in the future under these indirect guarantees totaled €431 million at year-end 2005, compared with €459 million at December 31, 2004. Of these amounts, €67 million and €162 million, respectively, involved guarantees issued on behalf of related parties. As of December 31, 2005 and 2004, the Company had recorded provisions in accordance with U.S. GAAP of €25 million and €98 million, respectively, with respect to its obligations under all of these non-nuclear financial guarantees.

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. The Company’s obligations under these arrangements with specified terms extend as far as 2041. The maximum undiscounted amount potentially payable in respect of the circumstances expressly set forth in these agreements was €6,623 million as of December 31, 2005, as compared with €4,602 million at year-end 2004. In a number of cases, it is not possible to reliably estimate a maximum obligation because there is no maximum liability specified in the contract. A number of the contracts also require

164

the buyer to either share costs or cover a certain amount of costs before the Company 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. As of December 31, 2005 and 2004, the Company had recorded provisions in accordance with U.S. GAAP of €296 million and €86 million, respectively, with respect to all indemnities and other guarantees included in the relevant agreements. Indemnification agreements entered into 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, and are therefore no longer obligations of E.ON.

Other Guarantees. E.ON’s obligations under “other guarantees” primarily include those relating to market value guarantees and warranties. These warranty obligations primarily relate to E.ON Energie business, while those for market value guarantees primarily arise from assurances as to the future value of securities pledged in connection with cross-border leasing transactions. As of December 31, 2005, the maximum potential undiscounted future payments potentially payable in respect of these warranties and market value guarantees amounted to €130 million. As of December 31, 2004, E.ON had also recorded provisions in accordance with U.S. GAAP in the amount of €25 million in respect of its own product warranties. As of December 31, 2005, due to the disposal of Viterra and Ruhrgas Industries, these product warranties no longer exist and the corresponding provisions have been eliminated.

Variable Interest Entities. The Company holds variable interests in various Variable Interest Entities (“VIEs”), which are not significant either individually or in the aggregate. As a result of the first-time application of FIN 46, two jointly managed electricity generation companies, two real estate leasing companies and two companies managing investments were fully consolidated in the Consolidated Financial Statements effective July 1, 2003. Another VIE for the management and disposal of real estate has been fully consolidated since the underlying contractual relationship became effective in 2003. Following the termination of all contractual relationships with this VIE in August 2005, which was presented as a discontinued operation as of December 31, 2005, FIN 46R no longer applies to this company. Following E.ON’s acquisition of additional interests in one of the previously jointly managed electricity companies and one of the companies managing investments noted above in 2004, the revised FIN 46 ceased to apply to such entities. As of October 1, 2004, one other electricity company was fully consolidated into the E.ON Group for the first time in accordance with the provisions of FIN 46R. As of December 31, 2005, the VIEs consolidated within the E.ON Group had total assets of €795 million and recorded earnings for 2005 of €17 million before consolidation. At December 31, 2005, €127 million in fixed and other assets of these entities served as collateral for financial leasing and bank credits. The recourse of creditors of the consolidated VIEs to the assets of the primary beneficiaries is generally limited. Two VIEs have no such limitation of recourse. The primary beneficiary was liable for €82 million in respect of these two entities as of December 31, 2005.

In addition, E.ON has had contractual relationships with one leasing company in the energy sector since July 1, 2000. The Company is not the primary beneficiary of this VIE. The entity is currently in liquidation pursuant to a shareholder resolution. This entity had total assets of €120 million as of the end of the 2004 fiscal year, and recorded earnings for 2004 of €29 million. The E.ON Group’s maximum exposure to loss related to its association with this VIE is approximately €15 million. Neither the relationship to this entity nor its liquidation is expected to result in the realization of losses by E.ON.

The extent of E.ON’s interest in another VIE, which has been in existence since 2001 and was expected to terminate in 2005, cannot be assessed in accordance with the FIN 46R criteria due to insufficient information. The significant transactions between this entity and the E.ON Group took place in the fourth quarter of 2005. However, the entity’s liquidation remains outstanding. The entity handled the liquidation of assets from operations that had already been sold. Originally, its total assets were €127 million. The termination of the relationship with this entity is not expected to result in any significant effects on E.ON’s earnings.

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CONTRACTUAL OBLIGATIONS

The following table summarizes E.ON’s contractual obligations as of December 31, 2005 and the related amounts falling due in each of the periods presented:


	Payments Due by Period

			Less than						More than
Contractual Obligations	Total		1 Year		1-3 Years		3-5 Years		5 Years

	(€ in millions)
Financial Liabilities(1)		14,205		3,770		915		5,148		4,372
Capital Lease Obligations		157		37		71		9		40
Operating Leases		577		99		157		125		196
Purchase Obligations		175,703		18,563		29,309		36,302		91,529
Asset Retirement Obligations		9,661		199		364		262		8,836
Pension Payments		9,577		865		1,804		1,899		5,009
Other Long-Term Obligations		5,431		601		3,874		219		737

Total Contractual Obligations		215,311		24,134		36,494		43,964		110,719


(1)	Excludes capital lease obligations.

As of December 31, 2005, the majority of the Company’s 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 24 and 25 of the Notes to Consolidated Financial Statements. For information on pension obligations, see Note 22 of the Notes to Consolidated Financial Statements. Pension payments in the table above do not include planned payments to the CTA model.

Purchase Obligations. E.ON’s purchase obligations primarily relate to the procurement of gas (€165 billion) and electricity (€4 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 “Item 4. Information on the Company — Business Overview — 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 re-calculated 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.

Contractual obligations for the purchase of electricity primarily arise 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 storage of spent nuclear fuel elements delivered through June 30, 2005. For additional details on these obligations, see “Item 4. Information on the Company — Business Overview — Central Europe — Power Generation.”

Asset Retirement Obligations. In accordance with SFAS 143, 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, environ-

166

mental 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 23 of the Notes to Consolidated Financial Statements.

Other Long-Term Obligations. E.ON’s other contractual obligations consist primarily of obligations arising out of option agreements that would require the Company to purchase shares from third parties.

As of December 31, 2005, E.ON is a party to put option agreements related to certain of its acquisitions, including one that allows the minority shareholder in E.ON Sverige to sell its remaining stake in that company to E.ON at any time through December 15, 2007 at an agreed price, and others that allow minority shareholders in other companies controlled by E.ON Energie to exercise similar rights. As of December 31, 2005, the total amount potentially payable in connection with such obligations was approximately €3.3 billion.

For more information with regard to E.ON’s contractual obligations, see Notes 24 and 25 of the Notes to Consolidated Financial Statements.


Item 6.	Directors, Senior Management and Employees.

DIRECTORS AND SENIOR MANAGEMENT

GENERAL

In accordance with the 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. For information on differences between E.ON’s corporate governance standards and those applicable to U.S. companies listed on the NYSE, see “Item 10. Additional Information — Memorandum and Articles of Association — Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the New York Stock Exchange Listed Company Manual (the “NYSE Manual”).”

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 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

167

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.

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, 2005, as well as the year in which they were first elected to the Supervisory Board are as follows:


				Year First
Name and Position Held	Age		Principal Occupation	Elected

Ulrich Hartmann(1)(2)(3) Chairman of the Supervisory Board		67	Retired Co-Chief Executive Officer of E.ON AG; formerly Chairman of the Board of Management and Chief Executive Officer of VEBA AG		2003

			Supervisory Board Memberships/Directorships:


			Deutsche Bank AG, Deutsche Lufthansa AG, Hochtief AG, IKB Deutsche Industriebank AG (Chairman), Münchener Rückversicherungs- Gesellschaft AG, Arcelor(4), Henkel KGaA(4)

Hubertus Schmoldt(2)(3)(5) Deputy Chairman of the Supervisory Board		60	Chairman of the Board of Management of Industriegewerkschaft Bergbau, Chemie, Energie		1996

			Supervisory Board Memberships/Directorships:


			Bayer AG, BHW AG, DOW Olefinverbund GmbH, Deutsche BP AG, RAG Aktiengesellschaft

Günter Adam(5) Member of the Supervisory Board		47	Chairman of the Central Works Council, Degussa AG		2002
			Supervisory Board Memberships/Directorships:


			Degussa AG

Dr. Karl-Hermann Baumann(1)* Member of the Supervisory Board		70	Formerly Chairman of the Supervisory Board of Siemens AG; formerly member of the Board of Management of Siemens AG		2000

			Supervisory Board Memberships/Directorships:


			Linde AG, Schering AG

Dr. Rolf-E. Breuer Member of the Supervisory Board		68	Chairman of the Supervisory Board of Deutsche Bank AG; formerly Spokesman of the Board of Management of Deutsche Bank AG		1997

			Supervisory Board Memberships/Directorships:


			Landwirtschaftliche Rentenbank(4)

Dr. Gerhard Cromme(3) Member of the Supervisory Board		62	Chairman of the Supervisory Board of ThyssenKrupp AG		1993

			Supervisory Board Memberships/Directorships:


			Allianz AG, Axel Springer AG, Deutsche Lufthansa AG, Hochtief AG, Siemens AG, Volkswagen AG, Suez S.A.(4), BNP Paribas S.A.(4), Compagnie de Saint-Gobain

168


				Year First
Name and Position Held	Age		Principal Occupation	Elected


Gabriele Gratz(5)(6) Member of the Supervisory Board		57	Chairwoman of the Works Council of E.ON Ruhrgas AG		2005

			Supervisory Board Memberships/Directorships:


			E.ON Ruhrgas AG

Wolf-Rüdiger Hinrichsen(2)(3)(5) Member of the Supervisory Board		50	Chairman of the Group Workers’ Council of E.ON AG		1998

Ulrich Hocker Member of the Supervisory Board		55	General Manager of the German Investor Protection Association		1998

			Supervisory Board Memberships/Directorships:


			Feri Finance AG, Gildemeister AG, Karstadt Quelle AG, ThyssenKrupp Stainless AG, Gartmore SICAV(4), Phoenix Mecano AG(4) (Chairman)

Eva Kirchhof(5) Member of the Supervisory Board		48	Diploma-Physicist, Degussa AG		2002

Seppel Kraus(5) Member of the Supervisory Board		52	Secretary of Labor Union		2003

			Supervisory Board Memberships/Directorships:


			Wacker-Chemie AG, UPM-Kymmene Beteiligungs GmbH

Prof. Dr. Ulrich Lehner Member of the Supervisory Board		59	President and Chief Executive Officer, Henkel KGaA		2003

			Supervisory Board Memberships/Directorships:


			HSBC Trinkaus & Burkhardt KGaA, Ecolab Inc.(4), Novartis AG(4), The DIAL Corporation(4) (Chairman)

Dr. Klaus Liesen Member of the Supervisory Board		74	Honorary Chairman of the Supervisory Board of E.ON Ruhrgas AG; formerly Chairman of the Supervisory Board of E.ON Ruhrgas AG		1991

			Supervisory Board Memberships/Directorships:


			TUI AG, Volkswagen AG

Erhard Ott(5)(6) Member of the Supervisory Board		52	Member of the Board of Management, Unified Services Sector Union (ver.di)		2005

Ulrich Otte(1)(5) Member of the Supervisory Board		56	Chairman of the Central Works Council, E.ON Energie AG		2001

			Supervisory Board Memberships/Directorships:


			E.ON Energie AG, E.ON Kraftwerke GmbH

Klaus-Dieter Raschke(1)(5) Member of the Supervisory Board		52	Chairman of the Combined Works Council, E.ON Energie AG		2002

			Supervisory Board Memberships/Directorships:


			E.ON Energie AG, E.ON Kernkraft GmbH

Dr. Henning Schulte-Noelle(2) Member of the Supervisory Board		63	Chairman of the Supervisory Board of Allianz AG; formerly Chairman of the Board of Management of Allianz AG		1993

			Supervisory Board Memberships/Directorships:


			Siemens AG, ThyssenKrupp AG

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				Year First
Name and Position Held	Age		Principal Occupation	Elected


Prof. Dr. Wilhelm Simson Member of the Supervisory Board		67	Retired Co-Chief Executive Officer of E.ON AG; formerly Chairman of the Board of Management and Chief Executive Officer of VIAG AG		2003

			Supervisory Board Memberships/Directorships:


			Frankfurter Allgemeine Zeitung GmbH, Merck KGaA (Chairman since January 1, 2006), Freudenberg & Co.(4), Jungbunzlauer Holding AG(4), E. Merck OHG(4)

Gerhard Skupke(5) Member of the Supervisory Board		56	Chairman of the Central Works Council, E.ON edis Aktiengesellschaft		2003

			Supervisory Board Memberships/Directorships:


			E.ON edis Aktiengesellschaft

Dr. Georg Freiherr von Waldenfels Member of the Supervisory Board		61	Former Minister of Finance of the State of Bavaria; Attorney		2003

			Supervisory Board Memberships/Directorships:


			Georgsmarienhütte Holding GmbH, GI Ventures AG (Chairman)


*	Chairman of the respective Supervisory Board committee.


(1)	Member of E.ON AG’s Audit Committee. For more information, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance — The Supervisory Board Committees.”

(2)	Member of E.ON AG’s Executive Committee, which covers the functions of a remuneration committee. For more information, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance — The Supervisory Board Committees.”

(3)	Member of E.ON AG’s Finance and Investment Committee. For more information, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance — The Supervisory Board Committees.”

(4)	Membership in comparable domestic or foreign supervisory body of a commercial enterprise.

(5)	Elected by the employees.

(6)	Member since July 1, 2005. Gabriele Gratz was elected to the position held prior to that date by Ralf Blauth; Erhard Ott was elected to that formerly held by Peter Obramski.

The current members of the Supervisory Board are subject to reelection in 2008.

BOARD OF MANAGEMENT (VORSTAND)

As of December 31, 2005, 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. For more information, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance.”

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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.

The members of the Board of Management, their respective ages and their positions and experience, each as of December 31, 2005, 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
Chairman of the Board of Management

Chief Executive Officer; Corporate Communications, Corporate and Public Affairs, Investor Relations, Supervisory Board Relations, Strategy, Executive Development, Audit; formerly Chairman of the Board of Management of Stinnes AG

2003

2008

Supervisory Board Memberships/Directorships:

E.ON Energie AG(1) (Chairman), E.ON Ruhrgas AG(1) (Chairman), Allianz AG, Metro AG, RAG Aktiengesellschaft (Chairman), 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
Member of the Board of Management

Upstream Business, Market Management, Group Regulatory Management; Chairman of the Board of Management and Chief Executive Officer of E.ON Ruhrgas AG

2003

2008

Supervisory Board Memberships/Directorships:

E.ON Ruhrgas International AG(1) (Chairman), Thüga AG(1) (Chairman), Allianz Lebensversicherungs-AG, MAN Ferrostaal AG, Jaeger Akustik GmbH & Co.(2) (Chairman), Mitteleuropäische Gasleitungsgesellschaft mbH (MEGAL)(2)(3) (Chairman), OAO Gazprom(2), E.ON Ruhrgas E & P GmbH(2)(3) (Chairman), Trans Europe Naturgas Pipeline GmbH(2)(3) (Chairman), E.ON Ruhrgas Transport Management GmbH(2)(3) (Chairman), E.ON UK plc(2)(3), ZAO Gerosgaz(2)(3) (Chairman; in alternation with a representative of the foreign partner)

Dr. Hans Michael Gaul
Member of the Board of Management

Controlling/Corporate Planning, M&A, Legal Affairs; formerly Member of the Board of Management of VEBA AG

1990

2007

Supervisory Board Memberships/Directorships:

Degussa AG(1), E.ON Energie AG(1), E.ON Ruhrgas AG(1), Allianz Versicherungs-AG, DKV AG, RAG Aktiengesellschaft, STEAG AG, Volkswagen AG, E.ON Nordic AB(2)(3), E.ON Sverige AB(2)(3)

Dr. Manfred Krüper
Member of the Board of Management

Labor Relations, Personnel, Infrastructure and Services, Procurement, Organization; formerly Member of the Board of Management of VEBA AG

1996

2006

171

Year First

Year Current

Name and Title

Age

Business Activities and Experience

Appointed

Term Expires

Supervisory Board Memberships/Directorships:

E.ON Energie AG(1), Degussa AG(1), equitrust Aktiengesellschaft (Chairman), RAG Aktiengesellschaft, RAG Immobilien AG, Victoria Versicherung AG, Victoria Lebensversicherung AG, E.ON US Investments Corp.(2)(3), E.ON North America, Inc.(2)(3) (Chairman)

Dr. Erhard Schipporeit
Member of the Board of Management

Chief Financial Officer; Finance, Accounting, Taxes, IT; formerly Member of the Board of Management of VIAG AG (appointed in 1997)

2000

2009

Supervisory Board Memberships/Directorships:

E.ON Ruhrgas AG(1), Degussa AG(1), Commerzbank AG, Deutsche Börse AG, SAP AG, Talanx AG, E.ON Audit Services GmbH(2)(3) (Chairman), E.ON IS GmbH (2)(3), E.ON Risk Consulting GmbH(2)(3) (Chairman), E.ON UK plc(2)(3), E.ON US Investments Corp.(2)(3), HDI V.a.G.(2)

Dr. Johannes Teyssen
Member of the Board of Management

Downstream Business, Market Management, Group Regulatory Management; Chairman of the Board of Management and Chief Executive Officer of E.ON Energie AG

2004

2008

Supervisory Board Memberships/Directorships:

E.ON Bayern AG(1) (Chairman), E.ON Hanse AG(1) (Chairman), Salzgitter AG, E.ON Nordic AB(2)(3), E.ON Sverige AB(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).

The members of the Supervisory Board and Board of Management hold, in aggregate, less than 1 percent of E.ON’s outstanding Ordinary Shares.

COMPENSATION

SUPERVISORY BOARD


	*The Compensation System for Members of the Supervisory Board*

Pursuant to E.ON AG’s Articles of Association, members of the Supervisory Board receive an annual compensation. By virtue of a resolution adopted at the annual shareholders meeting on April 27, 2005, a new basic concept was introduced for the compensation system, effective as of January 1, 2005. In accordance with statutory provisions and in line with the recommendations of the German Corporate Governance Code (Deutscher Corporate Governance Kodex, the “Code”), the revised compensation system takes into consideration the responsibility and the scope of activities of Supervisory Board members, as well as the financial situation and the business performance of the Company. In accordance with the Code, members of the Supervisory Board receive a fixed annual compensation, as well as two variable, performance-based compensation components: a short-term component that is linked to dividends and a long-term component that is tied to the three-year average of the E.ON Group’s consolidated net income.

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Fixed compensation: In addition to being reimbursed for their expenses, which also include the value-added tax due on their compensation, members of the Supervisory Board receive a fixed amount of €55,000.00 for each fiscal year.

Short-term variable compensation: In addition, members of the Supervisory Board receive a variable compensation of €115.00 for each €0.01 of dividend paid out to shareholders in excess of €0.10 per share for the previous fiscal year.

Long-term variable compensation: Furthermore, members of the Supervisory Board receive a variable compensation of €70.00 for each €0.01 of the three-year average of the E.ON Group’s consolidated net income per share in excess of €2.30.

Individuals who were members of the Supervisory Board or any of its committees for a period of less than a full fiscal year receive a pro-rata compensation for each full or partial month of membership. The fixed compensation is payable after the end of a fiscal year. Variable compensation components are payable after the annual shareholders meeting, which votes to formally approve the acts of the members of the Supervisory Board in the previous fiscal year.

The Chairman of the Supervisory Board receives three times the above-mentioned compensation; the Deputy Chairman as well as every chairman of a Supervisory Board committee receive a total of twice the above-mentioned amount; and each committee member receives a total of one-and-a-half times the above-mentioned compensation.

In addition, members of the Supervisory Board are paid an attendance fee of €1,000.00 per day for meetings of the Supervisory Board or any of its committees. Finally, the Company has taken out liability insurance for the benefit of Supervisory Board members to cover the statutory liability of Supervisory Board members for their activity. For information about the Supervisory Board committees, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance — The Supervisory Board Committees.”

Compensation Paid to Members of the Supervisory Board

Provided that E.ON’s annual shareholders meeting on May 4, 2006 approves the proposed dividend, the total compensation paid to members of the Supervisory Board for 2005 will amount to €3.8 million (2004: €3.3 million).

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The following table sets forth details of the compensation of each member of E.ON’s Supervisory Board (in the capacities indicated) in 2005, presented in accordance with the recommendations of the German Corporate Governance Code:


				Variable		Variable
		Fixed		Short-Term		Long-Term		Compensation
		Compensation		Compensation		Compensation		for Supervisory
		for Service on		for Service on		for Service on		Board
		E.ON’s		E.ON’s		E.ON’s		Memberships
		Supervisory		Supervisory		Supervisory		at Affiliated
Name		Board		Board		Board		Companies		Total

		(€)
Ulrich Hartmann			165,000		91,425		126,420		—		382,845
Hubertus Schmoldt			110,000		60,950		84,280		—		255,230
Günter Adam			55,000		30,475		42,140		—		127,615
Dr. Karl-Hermann Baumann			110,000		60,950		84,280		—		255,230
Ralf Blauth (until June 30, 2005)			41,250		22,856		31,605		—		95,711
Dr. Rolf-E. Breuer			55,000		30,475		42,140		—		127,615
Dr. Gerhard Cromme			82,500		45,713		63,210		51,500		242,923
Gabriele Gratz (from July 1, 2005)			27,500		15,237		21,070		50,750		114,557
Wolf-Rüdiger Hinrichsen			82,500		45,713		63,210		—		191,423
Ulrich Hocker			55,000		30,475		42,140		—		127,615
Eva Kirchhof			55,000		30,475		42,140		—		127,615
Seppel Kraus			55,000		30,475		42,140		—		127,615
Prof. Dr. Ulrich Lehner			55,000		30,475		42,140		—		127,615
Dr. Klaus Liesen			55,000		30,475		42,140		—		127,615
Peter Obramski (until June 30, 2005)			27,500		15,237		21,070		29,320		93,127
Erhard Ott (from July 1, 2005)			27,500		15,237		21,070		—		63,807
Ulrich Otte			66,458		36,824		50,919		66,850		221,051
Klaus-Dieter Raschke			82,500		45,713		63,210		44,640		236,063
Dr. Henning Schulte-Noelle			82,500		45,713		63,210		—		191,423
Prof. Dr. Wilhelm Simson			55,000		30,475		42,140		—		127,615
Gerhard Skupke			55,000		30,475		42,140		10,750		138,365
Dr. Georg Freiherr von Waldenfels			55,000		30,475		42,140		—		127,615

	Subtotal		1,455,208		806,318		1,114,954		253,810		3,630,290
Attendance fees and meeting-related reimbursements(1)											128,816

	Total		1,455,208		806,318		1,114,954		253,810		3,759,106


(1)	Attendance fees and meeting-related reimbursements are given as an aggregate for all Supervisory Board members.

In calculating the variable short-term compensation, the proposed extra dividend of €4.25 was not considered in accordance with a resolution of the Supervisory Board.

No loans were outstanding or granted to members of the Supervisory Board in fiscal 2005. For details of the members of the Supervisory Board, see the table under “— Supervisory Board (Aufsichtsrat)” above.

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BOARD OF MANAGEMENT

The Compensation System for Members of the Board of Management

The compensation of the members of the Board of Management is currently composed of a fixed annual base salary, an annual bonus the amount of which depends on the degree to which certain company-based and personal performance targets were achieved, and a long-term variable compensation component.

The base salary is paid on a monthly basis and is reviewed regularly to determine whether it is in line with market salaries and whether it is fair and reasonable. The last date on which salaries were adjusted was July 1, 2004. The amount of the annual bonus is determined by a target-setting system, 70 percent of which is related to company-based performance targets and 30 percent of which is related to personal performance targets. The company-based performance targets reflect, in equal shares, operating performance (as measured by adjusted EBIT) and the achieved return on capital employed (ROCE). Individual targets relate to members’ areas of responsibility, functions and projects. Members of the Board of Management who fully achieve their performance target receive the target bonus agreed in their contracts. The maximum bonus that can be achieved is 200 percent of the target bonus. Any compensation received for board memberships at Group companies is set off against the bonus or repaid to the Company.

The long-term variable compensation component that members of the Board of Management receive is stock-based compensation. This compensation is designed to reward members of the Board of Management (and other key executives) for their contributions to increasing the Company’s shareholder value, as well as to promote E.ON’s long-term corporate growth. This variable pay component, which combines incentives for long-term growth with a risk component, effectively aligns the interests of the management with those of the shareholders. In 1999, E.ON introduced annual stock appreciation rights (SARs) in the framework of its stock option program.

In fiscal 2006, a new long-term variable compensation component (stock performance plan) will be introduced, the amount of which will depend on the performance of E.ON’s stock price, both in absolute terms and relative to an industry index. This new compensation component will replace the SAR program. Board members who have already been granted SARs can continue to exercise these options in accordance with the agreed terms and conditions. See also “Stock Incentive Plans” below and Note 9 of the Notes to Consolidated Financial Statements.

The total compensation paid to members of the Board of Management therefore includes both fixed and variable components, as recommended in the German Corporate Governance Code. Criteria applied to determine the amount of compensation include in particular the scope of responsibilities of a member of the Board of Management, his or her personal performance, and the performance of the Board as a whole, as well as the Company’s financial situation, its success and its future prospects relative to a benchmark environment.

The variable compensation components contain an element of risk, i.e. this compensation is not guaranteed. The stock-based compensation systems are based on challenging, relevant benchmark parameters. Under the terms of these systems, it is not possible to change performance targets or benchmark parameters at a later stage. The Executive Committee of the Supervisory Board is responsible for decisions on compensation. The Supervisory Board recently discussed the compensation system for the Board of Management at its meeting on December 19, 2005.

E.ON has service agreements with the members of its Board of Management. In the event of a premature loss of a Board position due to a change-in-control event, the members of the Board of Management are entitled under their service agreements to receive a payment equal to a maximum of five years’ annual target compensation, depending on the length of the remaining term of the individual service agreement. In any other case, severance pay is only payable if it has been agreed in a personal termination contract.

Following the end of their service for the Company, members of the Board of Management are entitled to receive pension payments in three cases: (1) if they reach the regular retirement age of currently 60 years, (2) if they are permanently incapacitated, and — providing that certain requirements are met — (3) if their service agreement is terminated prematurely or not extended. Depending on the length of service of the member of the

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Board of Management, the annual pension entitlement is equal to between 50 percent and 75 percent of their last annual base salary. Pension payments are adjusted on an annual basis to reflect changes in the German consumer price index. The annual pension of one member of the Board of Management is a fixed amount that is also adjusted on an annual basis to reflect changes in the consumer price index plus an additional 0.7 percent per year.

Following the death of an active or former member of the Board of Management, a reduced amount of his or her pension is paid as a survivors’ pension to the family. A Board member’s widow is entitled to lifelong payment of a maximum of 60 percent of the pension. A Board member’s children who have not reached a specified age are entitled to an annual payment equal to 20 percent of his or her pension.

Compensation Paid to Members of the Board of Management

The total compensation paid to the members of the Board of Management in 2005 amounted to €22.5 million (2004: €17.3 million). The following table sets forth the details of the compensation of each member of E.ON’s Board of Management in 2005, presented in accordance with the recommendations of the German Corporate Governance Code:


								Fair Value
								of SARs				SARs
								Granted in				Granted in
		Fixed Annual		Annual		Other		7^thTranche				7^thTranche
Name		Compensation		Bonus		Compensation(1)		in 2005		Total		in 2005

		(€)		(€)		(€)		(€)		(€)		(No. of SARs)
Dr. Wulf H. Bernotat			1,150,000		3,180,000		41,412		1,350,000		5,721,412		97,472
Dr. Burckhard Bergmann			700,000		1,800,000		28,174		800,000		3,328,174		57,761
Dr. Hans Michael Gaul			700,000		2,100,000		31,113		800,000		3,631,113		57,761
Dr. Manfred Krüper			700,000		1,850,000		31,313		800,000		3,381,313		57,761
Dr. Erhard Schipporeit			700,000		1,620,000		41,780		800,000		3,161,780		57,761
Dr. Johannes Teyssen			700,000		1,700,000		43,135		800,000		3,243,135		57,761

	Total		4,650,000		12,250,000		216,927		5,350,000		22,466,927		386,277


(1)	Other compensation amounting to approximately €0.2 million (2004: €0.5 million) includes benefits in kind, primarily related to the private use of company cars, and attendance fees for Supervisory Board memberships at affiliated companies.

The table above includes an estimate of the fair value of SARs granted in 2005 as of the date of their issuance. This fair value is determined by means of a recognized option pricing model. The model simulates a large number of different scenarios for E.ON AG stock and the benchmark index, i.e. the Dow Jones STOXX Utilities Index (price EUR), and determines the intrinsic value of the SARs according to each scenario. The fair value included in the table above is equivalent to the discounted average of these intrinsic values. For more information and a description of the SAR plan, see Note 9 of the Notes to Consolidated Financial Statements.

The following table shows the exercise gains paid out to members of the Board of Management due to their exercise during 2005 of SARs granted in tranches two to five of the SAR plan in 2000 to 2003:


	Tranche 5 in 2003				Tranche 4 in 2002				Tranche 3 in 2001				Tranche 2 in 2000

	Exercised		Exercise		Exercised		Exercise		Exercised		Exercise		Exercised		Exercise
	SARs		Gains (1)		SARs		Gains (1)		SARs		Gains (1)		SARs		Gains (1)
Name	No. of SARs		(€)		No. of SARs		(€)		No. of SARs		(€)		No. of SARs		(€)

Dr. Wulf H. Bernotat		40,000		1,547,600		—		—		—		—		—		—
Dr. Burckhard Bergmann		15,000		384,150		—		—		—		—		—		—
Dr. Hans Michael Gaul		10,000		384,700		40,000		698,200		25,000		399,450		10,500		201,810
Dr. Manfred Krüper		—		—		25,000		658,250		25,000		355,500		21,000		403,620
Dr. Erhard Schipporeit		30,000		803,900		40,000		439,100		25,000		407,150		—		—
Dr. Johannes Teyssen		37,209		1,032,178		—		—		16,500		244,200		—		—

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(1)	The amount paid upon exercise of any SARs is the difference between the E.ON AG stock price at the time of exercise and the E.ON AG stock price at the time of the SAR issuance, multiplied by the number of SARs exercised.

Total pension payments made to former members of the Board of Management and their beneficiaries amounted to €5.4 million in 2005 (2004: €5.2 million). In addition, in 2005 former members of the Board of Management received exercise gains totaling €4.3 million (2004: €0.8 million) from SARs granted in previous years. Provisions of €89.0 million (2004: €83.5 million) were accrued in 2005 to cover pension obligations to former members of the Board of Management and their beneficiaries.

No loans were outstanding or granted to members of the Board of Management in 2005.

For details of the members of the Board of Management, see the table under “— Board of Management (Vorstand)” above.

EMPLOYEES

As of December 31, 2005, E.ON had 79,947 employees. This increase of 33 percent from year-end 2004 is mainly due to the addition of Distrigaz Nord, a Romanian gas distribution company, at the Pan-European Gas market unit and the various acquisitions in eastern Europe at the Central Europe market unit. Of the total number of employees, 42.7 percent were based in Germany. The following table sets forth information about the number of employees of E.ON as of December 31, 2005, 2004 and 2003, not including apprentices and managing directors or board members:


	Employees at						Employees at						Employees at
	December 31, 2005						December 31, 2004						December 31, 2003

	Total		Germany		Foreign		Total		Germany		Foreign		Total		Germany		Foreign

Central Europe		44,476		30,307		14,169		36,811		29,208		7,603		36,576		28,611		7,965
Pan-European Gas		13,366		3,411		9,955		4,001		3,432		569		4,357		3,885		472
U.K.		12,891		10		12,881		10,397		6		10,391		6,541		—		6,541
Nordic		5,801		2		5,799		5,530		2		5,528		6,294		—		6,294
U.S. Midwest		3,002		2		3,000		2,997		1		2,996		3,080		—		3,080
Corporate Center		411		395		16		420		403		17		597		390		207

Total		79,947		34,127		45,820		60,156		33,052		27,104		57,445		32,886		24,559

In addition, E.ON employed 2,471, 2,289 and 2,358 apprentices with limited contracts in Germany at year-end 2005, 2004 and 2003, respectively.

Personnel expenses totaled €4.6 billion in 2005 compared with €4.2 billion in 2004. This increase of 9.5 percent primarily reflected the inclusion of the newly-acquired company Distrigaz Nord at the Pan-European Gas market unit and the various acquisitions in eastern Europe at the Central Europe market unit.

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.

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 services. E.ON U.K. has in place a company level framework for collective bargaining that has been jointly agreed with the five recognized trade unions. This framework provides for arrangements for negotiation and consultation at the

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company level and the individual business level. At company level, a range of common standards is negotiated with the trade unions for company-wide application. 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. Many of the Group’s employees in Finland are also members of trade unions. In Finland, union representatives are members of the E.ON Finland management group, not the board of directors. In Finland, the collective labor agreement, also called the Agreement of Income Policy, in force is determined on the national level or on a union level between the relevant trade unions and employers’ association. Local agreements are negotiated between the company chief executive officer, the human resources manager and representatives of the relevant trade unions on the basis of this general agreement. Management believes its relations with the Swedish and Finnish 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 und cooperative relationship is of great importance for the successful integration of the Company’s newly-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.

Since 1984, E.ON has had an employee share purchase program under which employees in Germany may purchase Ordinary Shares at a discount to the extent provided under German tax laws (according to Section 19a of the German Income Tax Law, in 2005 employees were eligible for a total discount per employee of €135). Since 2005, E.ON provides an additional discount per employee of up to €320, which is subject to income tax

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and depends on the Company’s performance. In 2005, this additional discount amounted to €252 per employee. In 2005, 17,610 employees purchased 308,555 Ordinary Shares under this program.

Since 2003, E.ON UK operates an HM Revenue and Customs-approved share incentive plan that allows employees to buy Ordinary Shares of E.ON AG out of their pre-tax salary (“partnership shares”) and receive additional shares for every partnership share purchased (“matching shares”). As of December 31, 2005, 4,715 E.ON UK employees were participating in the plan. In 2005, participants purchased 97,412 partnership shares and received approximately 120,734 matching shares under the plan.

STOCK INCENTIVE PLANS

Since 1999, E.ON AG has run a SAR plan for key executives of the Group. The purpose of this plan is to focus key executives on long-term corporate growth. The SAR plan is based on the performance of E.ON AG’s Ordinary Shares. E.ON AG granted approximately 2.9 million SARs to 357 top-level executives worldwide in 2005, including members of the Board of Management, as part of their compensation. See also “— Compensation” above. For more information about this plan, see Note 9 of the Notes to Consolidated Financial Statements.

In 2006, E.ON will adopt a new long-term incentive program for senior executives (including the members of the Board of Management of E.ON AG) to replace the existing SAR program. The new program, the specific terms of which will be set during 2006, is based on annual grants of “performance share units,” with the grantee being entitled to receive a cash payment equal to the product of the number of “performance share units” granted and the E.ON AG Ordinary Share price at the end of a three year reference period. The number of “performance share units” used in the final calculation will be adjusted to reflect the performance of E.ON AG Ordinary Shares relative to a reference index and can be reduced to zero in the event that E.ON AG Ordinary Shares severely underperform the index.


Item 7.	Major Shareholders and Related Party Transactions.

MAJOR SHAREHOLDERS

As of December 31, 2005, E.ON AG had an aggregate number of 659,153,552 Ordinary Shares with no par value outstanding. Under the Articles of Association, each Ordinary Share represents one vote.

Based on information available to E.ON, including filings with the SEC, there were no shareholders who beneficially owned more than five percent of the Ordinary Shares as of December 31, 2005. Holders of voting securities of listed German corporations (including E.ON) whose shareholding reaches, passes or falls below certain thresholds are subject to certain notification requirements under German law. These thresholds are 5, 10, 25, 50 and 75 percent of a company’s voting rights. For more information, see “Item 10. Additional Information — Memorandum and Articles of Association — Disclosure of Shareholdings” and Note 17 of the Notes to Consolidated Financial Statements.

In addition, as of December 31, 2005 E.ON directly and indirectly held a total of 32,846,448 of its own Ordinary Shares in treasury stock, representing 4.7 percent of its share capital. E.ON cannot vote these shares. For more information, see Note 17 of the Notes to Consolidated Financial Statements.

Although E.ON is unable to determine the exact number of its Ordinary Shares held in the United States, it believes that as of December 31, 2005, approximately 21.8 percent of its outstanding share capital was held by shareholders in the United States, and approximately 1.7 percent was held in the form of ADSs. For more information, see “Item 9. The Offer and Listing — General.”

RELATED PARTY TRANSACTIONS

In the ordinary course of its business, E.ON enters into transactions with numerous businesses, including firms in which the Group holds ownership interests and those with which some of E.ON’s Supervisory Board members hold positions of significant responsibility.

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Allianz AG was a major shareholder of E.ON in 2002 and prior years. Allianz AG provides the Group with insurance coverage in the ordinary course of business for which it was paid reasonable and customary fees. E.ON also has ongoing banking relations with Deutsche Bank AG, previously a major shareholder, in the ordinary course of business.

E.ON directly and indirectly holds a 39.2 percent interest in RAG. In February 2003, E.ON sold 37.2 million of its shares in Degussa (approximately 18 percent of Degussa’s outstanding shares) to RAG for €1.4 billion. Subsequent to this transaction, both E.ON and RAG held a 46.5 percent interest in Degussa. In the second step, E.ON sold a further 3.6 percent of Degussa stock to RAG as of May 31, 2004. Effective June 1, 2004, E.ON owns 42.9 percent of Degussa. On December 19, 2005, E.ON and RAG signed a framework agreement on the sale of E.ON’s remaining Degussa shares to RAG for approximately €2.8 billion. The transaction is expected to be completed by July 1, 2006, subject to the approval of the federal government and the state of North-Rhine Westphalia. Until completion of this transaction, E.ON and RAG operate Degussa under joint control. For more information on these transactions, see “Item 4. Information on the Company — History and Development of the Company — Ruhrgas Acquisition” and “Item 5. Operating and Financial Review and Prospects — Overview” and “— Acquisitions and Dispositions.”

From time to time E.ON may make loans to companies in which the Group holds ownership interests. At year-end 2005, E.ON had aggregate outstanding loans to companies in which the Group holds ownership interests amounting to €544 million, with one of the largest single such loan being to ONE (€162 million). For information, see Note 30 of the Notes to Consolidated Financial Statements.

For a discussion of off-balance sheet arrangements, see “Item 5. Operating and Financial Review and Prospects — Off-Balance Sheet Arrangements.”


Item 8.	Financial Information.

CONSOLIDATED FINANCIAL STATEMENTS

See “Item 18. Financial Statements” and pages F-1 to F-83.

LEGAL PROCEEDINGS

Various legal actions, including lawsuits for product liability or for alleged price fixing agreements, governmental investigations, proceedings and claims are pending or may be instituted or asserted in the future against the Company. These include lawsuits pending in the United States and Germany against E.ON and certain subsidiaries in connection with the sale of VEBA Electronics in 2000 as well as arbitration proceedings against E.ON Nordic. For more information on the E.ON Nordic arbitration proceedings, see “Item 4. Information on the Company — Business Overview — Nordic — Overview.” Since such litigation or claims are subject to numerous uncertainties, their outcome cannot be ascertained; however, in the opinion of management, the outcome of these matters and those discussed in this section will not have a material adverse effect upon the financial condition, results of operations or cash flows of the Company.

In the wake of the various corporate restructurings of the past several years, shareholders have filed a number of claims (Spruchstellenverfahren). The claims contest the adequacy of share exchange ratios or cash settlements. The claims impact certain E.ON Energie and E.ON Ruhrgas subsidiaries, as well as the VEBA-VIAG merger. In connection with the VEBA-VIAG merger, certain shareholders of the former VIAG have filed claims with the district court in Munich, contesting the adequacy of the share exchange ratio used in the merger. The claims challenge in particular the valuation used for VIAG’s telecommunications shareholdings, which were valued at the earnings value of the businesses. The plaintiffs claim that a divestiture of these shareholdings was anticipated, and therefore the holdings should have been valued at fair market value as if sold as of the merger date. Because the share exchange ratios and settlements were determined by outside experts and reviewed by independent auditors, E.ON believes that the exchange ratios and settlements are correct.

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The U.S. Securities and Exchange Commission has requested that the Company provide them with information for an investigation focusing in particular on the preparation of its Annual Reports on Form 20-F and financial statements for the years from 2000 through 2003, including, with respect to all or a portion of such period, the accounting treatment and depreciation of its power plant assets, its accounting for and consolidation of certain former subsidiaries (Degussa and Viterra) and their shareholdings, the nature of the services performed by its auditors, disclosures with regard to its long-term commitments (including fuel procurement contracts), and the process of such documents’ preparation and conformity with U.S. GAAP. The Company is in close contact with the SEC and has been cooperating fully with the investigation. A similar request that also covers additional items has been made to the Company’s independent public accountants.

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 “Item 4. Information on the Company — History and Development of the Company — Ruhrgas Acquisition.”

For information about proceedings instituted by German antitrust authorities affecting E.ON Ruhrgas, E.ON Energie and certain of their subsidiaries, see “Item 3. Key Information — Risk Factors.”

For information about the E.ON U.S. electricity and gas rate cases, see “Item 4. Information on the Company — Regulatory Environment — U.S. Midwest.”

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 “Item 4. Information on the Company — Environmental Matters.”

DIVIDEND POLICY

The Supervisory Board and the Board of Management jointly propose the Company’s dividends based on E.ON AG’s unconsolidated financial statements. The dividends are officially declared at the annual general meeting of shareholders which is usually convened during the second quarter of each year. The shareholders approve the dividends. Holders of E.ON’s Ordinary Shares on the date of the annual general meeting of shareholders are entitled to receive the dividend, less any amounts required to be withheld on account of taxes or other governmental charges. See also “Item 10. Additional Information — Taxation.” Cash dividends payable to holders of Ordinary Shares are distributed by HypoVereinsbank as paying agent. In Germany, the payment will be made to the holder’s custodian bank or other institution holding the shares for the shareholder which will credit the payment to the shareholder’s account. For purposes of distribution in the United States, the dividend will be paid to JPMorgan Chase Bank N.A. as U.S. transfer agent. For ADS holders in the United States, the payment will be converted from euros to U.S. dollars unless the ADS holder instructs otherwise. The U.S. dollar amounts of dividends may be affected by fluctuations in exchange rates. See “Item 3. Key Information — Exchange Rates.”

E.ON AG expects to continue to pay dividends, although there can be no assurance as to the particular amounts that may be paid from year to year. The payment of future dividends will depend upon E.ON’s earnings, financial condition (including its cash needs), future earnings prospects and other factors. In March 2005, E.ON AG announced that it is committed to achieving a payout ratio of between 50 and 60 percent of net income excluding exceptional items by 2007.

E.ON’s Supervisory Board and Board of Management have proposed an extra dividend for 2005 of €4.25 per Ordinary Share, resulting from the proceeds from the sale of E.ON’s remaining 42.9 percent stake in Degussa. For details on this transaction, see “Item 5. Operating and Financial Review and Prospects — Overview.” The extra dividend has not yet been approved by E.ON’s shareholders. Prior to the payment of this dividend, a resolution approving such amount must be passed by E.ON’s shareholders at the annual general meeting to be held on May 4, 2006. See also “Item 3. Key Information — Dividends.”

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SIGNIFICANT CHANGES

For information about significant changes following December 31, 2005, see “Item 4. Information on the Company — History and Development of the Company.”


Item 9.	The Offer and Listing.

GENERAL

The principal trading market for the Ordinary Shares is the Frankfurt Stock Exchange together with XETRA, as described below. The Ordinary Shares are also traded on the other German stock exchanges in Berlin-Bremen, Düsseldorf, Hamburg, Hanover, Munich and Stuttgart. Options on Ordinary Shares are traded on the German derivatives exchange (Eurex Deutschland). E.ON believes that as of December 31, 2005, it had close to 478,000 stockholders worldwide.

E.ON shares are listed on the NYSE in the form of ADSs and are traded under the symbol “E.ON.” In the past, the exchange ratio between E.ON ADSs and E.ON shares was 1:1. E.ON decided to change this ratio to 3:1 effective March 29, 2005. As of this date, three times as many ADSs are tradable on the NYSE, with three ADSs representing one Ordinary Share with a pro rata amount of the registered capital of E.ON AG calculated on a €2.60 share-equivalent basis. The depositary for the ADSs is JPMorgan Chase Bank N.A.

TRADING ON THE NEW YORK STOCK EXCHANGE

The table below sets forth, for the periods indicated, the high and low closing sales prices for the ADSs on the NYSE, as reported on the NYSE Composite Tape.


		Price per ADS
		($)(1)

		High		Low

2001			60.50		42.03
2002			58.02		39.80
2003			65.44		38.52
2004			91.15		61.72
First Quarter			68.95		61.72
Second Quarter			72.54		63.15
Third Quarter			75.17		69.22
Fourth Quarter			91.15		73.90
2005			35.01		27.67
First Quarter			31.01		28.21
Second Quarter			29.97		27.67
Third Quarter			33.73		29.14
Fourth Quarter			35.01		29.15
	September		33.73		30.58
	October		31.31		29.15
	November		31.96		29.50
	December		35.01		31.68
2006
	January		37.33		35.60
	February		38.13		36.58


(1)	One E.ON ADS equaled one Ordinary Share until March 28, 2005.

On March 6, 2006, the closing sale price per ADS on the NYSE as reported on the NYSE Composite Tape was $36.36.

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TRADING ON THE FRANKFURT STOCK EXCHANGE

The Frankfurt Stock Exchange is by far the most significant of the seven German stock exchanges. By the end of December 2005, it accounted for approximately 90 percent of the total securities orderbook turnover in Germany. As of the end of 2005, the equity securities of 6,823 corporations, including 5,988 foreign corporations, were traded on the Frankfurt Stock Exchange.

The Exchange Council of the Frankfurt Stock Exchange (Frankfurter Wertpapierbörse) approved a new segmentation of the Exchange’s equity markets on November 19, 2002, with the goal of increasing transparency, liquidity and integrity. The new structure, which took effect on January 1, 2003, consists of the Prime Standard Segment and the General Standard Segment.

The Prime Standard segment is designed for companies that wish to target international investors. Accordingly, Prime Standard companies are required to meet transparency criteria over and above those required for General Standard companies. These criteria, which are based on international practice, include:


	•	Quarterly reporting;

	•	Application of international accounting standards (either IAS or U.S. GAAP);

	•	Publication of a financial calendar listing the most important corporate events;

	•	At least one analysts’ conference per year; and

	•	Provision of English language versions of all current reports and ad-hoc disclosures required under the German Securities Trading Act (Wertpapierhandelsgesetz, or “Securities Trading Act”).

Issuers are admitted to the Prime Standard segment upon application, subject to approval by the Admission Board of the Frankfurt Stock Exchange. E.ON’s Ordinary Shares have been admitted to the Prime Standard segment.

Prices are continuously quoted on the Frankfurt Stock Exchange floor each business day between 9:00 a.m. and 8:00 p.m. Central European Time (“CET”) and on XETRA between 9:00 a.m. and 5:30 p.m. CET for E.ON Ordinary Shares, as well as for other actively traded shares. The Frankfurt Stock Exchange publishes a daily official list (Orderbuchstatistik) which includes the volume of recorded transactions in the shares comprising the Deutsche Aktienindex or DAX 30 Index (a performance index comprising the shares of the 30 largest German companies included in the Prime Standard, of which E.ON is one, and the key benchmark of trading on the Frankfurt Stock Exchange), together with the prices of the highest and lowest recorded trades of the day. The list reflects price and volume information for trades completed by members on the floor during the day as well as for interdealer trades completed off the floor.

XETRA (Exchange Electronic Trading System) is a computerized trading platform that can be accessed by all market participants regardless of their geographical location. It is administered by Deutsche Börse AG and integrated into the Frankfurt Stock Exchange, and is subject to the Exchange’s rules and regulations. Unlike exchange floor-trading, electronic order processing makes it possible for orders to be entered in the system and matched up to the end of the trading day. Almost all of the equity securities listed on the Frankfurt Stock Exchange are traded on XETRA.

The trading supervisory offices (Handelsüberwachungsstellen) at the stock exchanges and the local state stock market supervisory authorities (Börsenaufsichtsbehörden) of the German federal states monitor trading activities on the German stock exchanges. The German Federal Financial Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht, or “BAFin”) monitors compliance with insider trading rules.

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The table below sets forth, for the periods indicated, the high and low closing sales prices (Schlusskurse) for the Ordinary Shares on XETRA, as reported by the Frankfurt Stock Exchange, together with the highs and lows of the DAX 30 Index.

See the discussion under “Item 3. Key Information — Exchange Rates” for rates of exchange between the dollar and the euro applicable during the periods set forth below.


		Price Per
		Ordinary Share				DAX 30 Index(1)

		High		Low		High		Low

		(€)				(€ in thousands)
2001			64.50		64.91		6,795.14		3,787.23
2002			59.97		38.16		5,462.55		2,597.88
2003			51.74		34.67		3,965.16		2,202.96
2004			67.06		49.27		4,261.79		3,646.99
First Quarter			56.16		49.27		4,151.83		3,726.07
Second Quarter			59.63		53.45		4,134.10		3,754.37
Third Quarter			60.83		56.85		4,035.02		3,646.99
Fourth Quarter			67.06		60.05		4,261.79		3,854.41
2005			88.92		64.50		5,458.58		4,178.10
First Quarter			71.70		64.50		4,428.09		4,201.81
Second Quarter			73.68		69.60		4,627.48		4,178.10
Third Quarter			80.80		72.59		5,048.74		4,530.18
Fourth Quarter			88.92		72.25		5,458.58		4,806.05
	September		80.80		75.69		5,048.14		4,837.81
	October		78.19		72.25		5,138.02		4,806.05
	November		81.29		74.68		5,199.48		4,922.55
	December		88.92		80.44		5,458.58		5,266.55
2006
	January		91.93		87.07		5,674.15		5,334.30
	February		96.10		91.95		5,915.15		5,649.60

(1)

The DAX 30 Index is a continuously updated, capital-weighted performance index of 30 German blue chip companies. E.ON represented approximately 10.23 percent of the DAX 30 Index as of March 6, 2006. In principle, the shares included in the DAX 30 Index were selected on the basis of their stock exchange turnover and their market capitalization. Adjustments of the DAX 30 Index are made for capital changes, subscription rights and dividends.

On March 6, 2006, the closing sale price per Ordinary Share on XETRA, as reported by the Frankfurt Stock Exchange, was €91.28, equivalent to $109.85 per Ordinary Share, translated at the euro Foreign Exchange Rate as published on Reuters page EUROFX/1 on such date.


Item 10.	Additional Information.

MEMORANDUM AND ARTICLES OF ASSOCIATION

Organization, Register and Entry Number

E.ON AG is a stock corporation organized under the laws of the Federal Republic of Germany. It is entered in the Commercial Register maintained by the local court of Düsseldorf, Germany, under the entry number HRB 22315.

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Objects and Purposes

The purposes of the Company, described in Section 2 of E.ON AG’s Articles of Association (Satzung), are the supply of energy (primarily electricity and gas) and water as well as the provision of disposal services. The Company’s activities may encompass generation and/or production, transmission and/or transport, purchasing, selling and trading. Plants of all kinds may be built, purchased and operated; services and cooperations of all kinds may be performed.

Furthermore, the Company is entitled to run businesses in the chemicals sector, primarily in the special and constructional chemistry areas, as well as in the real estate industry and telecommunications sector.

Further, its Articles of Association authorize E.ON AG to conduct business itself or through subsidiaries or associated companies in these or related areas. The Company is entitled to take all actions and measures related to its purpose or suited to serve its purpose, directly or indirectly.

E.ON may also establish and purchase other companies, and may acquire shareholdings in other companies, particularly companies active, in whole or in part, in the business areas set forth above. The Articles of Association further authorize E.ON to acquire interests in companies of all kinds with the primary objective of investing financial resources, regardless of whether the company operates within one of E.ON’s stated business sectors.

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.

In February 2002, a government commission appointed by the German Minister of Justice presented the new German Corporate Governance Code, which is described in more detail below. A new Transparency and Publicity Act (Transparenz- und Publizitätsgesetz) came into effect in July 2002. A new Article 161 was also added to the Stock Corporation Act, stipulating that the board of management and supervisory board of German listed companies shall declare once a year that the recommendations of the Code have been and are being complied with, or identify which of the Code’s recommendations have not been or are not being applied. E.ON has submitted this declaration each year since 2002 as required. For more information, see “— Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the New York Stock Exchange Listed Company Manual (the “NYSE Manual”)” below.

E.ON has always welcomed the creation of uniform corporate governance standards. E.ON believes that the Code will make the German system of corporate governance more transparent and promote the trust of international and national investors and the general public in the management and supervision of German listed companies. Taking the Code as a basis, in 2002 E.ON reviewed its internal rules and procedures relating to

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shareholders’ meetings, the interaction between the Board of Management and the Supervisory Board and the transparency of its financial reporting, as well as the Company’s procedures for accounting and auditing. E.ON concluded from this review that the Company had already been following a majority of the Code’s recommendations for some time before the Code was published, reflecting E.ON’s value-oriented corporate governance principles and capital markets-oriented accounting and reporting policies. In order to promote the transparency and efficiency of the Supervisory Board’s activities, rules of procedure for the Supervisory Board were adopted on December 19, 2002 and it was decided to set up an audit committee, as well as a finance and investment committee, in addition to the already existing committees.

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. This includes, in particular, the management of the Group and its financial resources, the development of its human resources strategy, the appointment of persons to management posts within the Group and the development of its managerial staff, as well as the presentation of the Group to the capital markets and to the public at large. In addition, the Board of Management is responsible for coordinating and supervising the Group’s market units in accordance with the Group’s established strategy.

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. It also submits the Group’s investment, finance and personnel plan for the coming fiscal year (as well as the medium-term plan) to the Supervisory Board for its approval at the last meeting of each fiscal year.

The Chairperson of the Board of Management informs the Chairperson of the Supervisory Board of important events that are of fundamental significance in assessing the condition, development and management of the Company and of any defects that have arisen in the Company’s monitoring systems without undue delay. Transactions and measures requiring the approval of the Supervisory Board are also submitted to the Supervisory Board without delay.

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 members of the Supervisory Board. Supervisory Board members may also not hold a corporate office or perform any advisory services for key competitors of the Company. Supervisory Board members are required to disclose any information concerning conflicts of interest to the full Supervisory Board, particularly if the conflict arises from their advising or holding a corporate office with one of E.ON’s customers, suppliers, creditors or other business partners. 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. No conflicts of interest involving any members of the Supervisory Board were reported during 2005. In addition, any consulting or other service agreements between the Company and a member of the Supervisory Board require the prior consent of the full Supervisory Board. No such agreements existed during 2005.

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. Members of the Board of Management may only assume other corporate positions, particularly appointments to the supervisory boards of non-Group companies, with the consent of the Executive Committee. Any material transactions between the Company and members of the Board of Management, their relatives or entities with which they have close personal ties require the consent of the Executive Committee, and all transactions must be conducted on an arm’s-length basis. No such transactions took place during 2005.

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 the following committees from among its members.

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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.

In particular, the Executive Committee prepares the Supervisory Board’s personnel decisions and deals with issues of corporate governance. It reports to the Supervisory Board at least once a year on the status, effectiveness and possible ways of improving the Company’s corporate governance and on new requirements and developments in this field.

The Audit Committee consists of four members who have special knowledge in the field of accounting or business administration. The Company believes that two of the Audit Committee’s members — Dr. Karl-Hermann Baumann and Ulrich Hartmann — meet all of the requirements for being considered an “audit committee financial expert” within the meaning of Section 407 of Sarbanes-Oxley and the rules enacted thereunder, given their extensive experience in accounting and auditing matters, including the application of U.S. GAAP. E.ON relies on the exemption afforded by Rule 10A-3(b)(1)(iv)(C) under the Securities Exchange Act with respect to the independence of two of its members, Ulrich Otte and Klaus-Dieter Raschke. The Company believes that such reliance does not materially adversely affect the ability of the Audit Committee to act independently or to satisfy the other requirements of Rule 10A-3.

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. It also inspects the Company’s Annual Report on Form 20-F and its quarterly reports and discusses the financial statements and the quarterly reports with the Company’s independent auditors. For additional information, see “Item 16C. Principal Accountant Fees and Services.”

The Audit Committee also prepares the proposal on the selection of the Company’s external auditors for the annual general meeting of shareholders. In order to ensure the auditors’ independence, the Audit Committee secures a statement from the auditors proposed detailing any facts that could lead to the firm being excluded for independence reasons or otherwise conflicted. As a condition of their appointment, the external auditors agree to promptly inform the chair of the Audit Committee should any such facts arise during the course of the audit. The auditors also agree to promptly inform the Supervisory Board of anything arising during the course of their audit that is of relevance to the Supervisory Board’s duties, and to inform the chair of the Audit Committee of, or to note in their audit report, any facts determined during the audit that contradict statements submitted by the Board of Management or Supervisory Board in connection with the requirements of the Code.

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.

Measures Relating to the Sarbanes-Oxley Act. As a company whose ADSs are listed on the NYSE, E.ON is subject to the U.S. federal securities laws and the jurisdiction of the U.S. securities regulator, the SEC. In particular, E.ON is subject to the provisions of Sarbanes-Oxley. The aim of Sarbanes-Oxley is to increase the monitoring, quality and transparency of financial reporting in light of recent corporate and accounting scandals in the United States, and its provisions generally apply to both U.S. and non-U.S. issuers with securities listed in the United States. E.ON has complied with all of the Sarbanes-Oxley requirements currently applicable to the Company. See “Item 15. Controls and Procedures,” “Item 16A. Audit Committee Financial Expert,” “Item 16B. Code of Ethics,” “Item 16C. Principal Accountant Fees and Services,” “Item 16E. Purchases of Equity

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Securities by the Issuer and Affiliated Purchasers” and the certifications appearing as exhibits at the end of this annual report. E.ON has instituted the following measures to improve further 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 annual report. 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 SEC and in its other corporate publications.

	•	In accordance with an SEC recommendation, E.ON has established a Disclosure Committee that is responsible for ensuring that effective procedures and control mechanisms for financial reporting are in place and for providing a correct and timely presentation of information to the financial markets. The committee is comprised of seven members from various sectors of E.ON AG who have a good overview of the Group and the processing of information relating to the quarterly reports and annual financial statements.

The SEC has adopted rules under Section 404 of Sarbanes-Oxley that will require management of a public company to assess annually the effectiveness of the company’s internal control over financial reporting and to report its assessment in the company’s annual report. Under the current rules applicable to E.ON, the first internal control report will be required in its Annual Report on Form 20-F for the fiscal year ended December 31, 2006. To ensure compliance with these requirements, E.ON launched a “SOA 404 Readiness” project in 2003 under the supervision of the Board of Management. The project provides a standardized methodology to document, evaluate and test relevant key controls, and to provide for the remediation of control deficiencies. E.ON has adopted the Internal Control — Integrated Framework published by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO framework”) as a suitable framework to evaluate the effectiveness of its internal controls, and has rolled out the SOA 404 Readiness project to each of the market units.

Certain Provisions with Respect to Board Members

As a member of the Supervisory Board or Board of Management, a person is not permitted to vote on resolutions relating to transactions between himself and the Company. Further, contracts between members of the Supervisory Board and the Company require consent of the entire Supervisory Board, unless the contract establishes an employment relationship or relates to the member’s services on the Board. Members of both Boards are prohibited from voting on resolutions relating to the initiation or settlement of litigation between themselves and the Company. There are no age limit requirements for the retirement of Board members. Compensation of Board of Management members is determined by the Supervisory Board while compensation for the Supervisory Board is stipulated in E.ON AG’s Articles of Association. For more information about E.ON’s Board of Management and Supervisory Board, see “Item 6. Directors, Senior Management and Employees.”

Ordinary Shares

The share capital of E.ON AG consists of Ordinary Shares with no par value. Certain provisions with respect to the Ordinary Shares under German law and E.ON AG’s Articles of Association may be summarized as follows:

Dividends. Dividends in respect of Ordinary Shares are declared once a year at the annual general meeting of shareholders. For each fiscal year, the Board of Management approves E.ON AG’s unconsolidated financial statements and submits them together with a proposal regarding the distribution of profits to the Supervisory Board for its approval. After examining the financial statements and proposal for profit distribution, the Supervisory Board presents a report in writing at the annual general shareholders’ meeting. On the basis of the Supervisory Board’s report, the shareholders vote on the Board of Management’s proposal regarding the disposition of all unappropriated profits, including the amount of net profits to be distributed as a dividend. E.ON’s shareholders participate in the distribution of dividends of the Company in proportion to their ownership

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of the outstanding share capital. Prior to dissolution of E.ON AG, the only amounts that may be distributed to shareholders under the Stock Corporation Act are the distributable profits (Bilanzgewinn).

Notice of the dividends to be paid will be published in the electronic form of the German Federal Official Gazette (elektronischer Bundesanzeiger). For further information regarding E.ON dividends, see “Item 3. Key Information — Dividends” and “Item 8. Financial Information — Dividend Policy.”

Voting Rights. Each Ordinary Share entitles its holder to one vote. The members of the Supervisory Board are each elected for the same fixed term of approximately five years; they are not elected at staggered intervals. Cumulative voting is not permitted under German law. E.ON AG’s Articles of Association require that resolutions of shareholders’ meetings be adopted by a simple majority of votes and, in certain circumstances, by a simple majority of the share capital of the Company, unless a higher vote is required by German law. Under German law, certain corporate actions require approval by 75 percent of the shares represented at the shareholders’ meeting at which the matter is proposed. Such actions include, among others:


	•	amending the articles of association to alter the objects and purposes of the company;

	•	increasing or reducing the share capital;

	•	excluding preemptive rights of shareholders to subscribe for new shares;

	•	dissolving the corporation;

	•	merging the corporation into, or consolidating the corporation with, another company;

	•	transferring all or virtually all of the corporation’s assets; and

	•	changing corporate form.

Shareholder Rights in Liquidation. In accordance with German law, in the event of liquidation, the assets of E.ON remaining after discharge of its liabilities would be distributed to its shareholders in proportion to their shareholdings.

Redemption. Under German law, the share capital of E.ON AG may be reduced by a shareholder resolution amending the Articles of Association, passed by at least 75 percent of the share capital represented at the shareholders’ meeting. See “— Changes in Capital” below.

Preemptive Rights. Pursuant to E.ON AG’s Articles of Association, the preemptive right (Bezugsrecht) of shareholders to subscribe for any issue of additional shares in proportion to their shareholdings in the existing capital may be excluded under certain circumstances.

Due to the restrictions on the offer and sale of securities in the United States under U.S. securities laws and regulations, there can be no assurance that any offer of new shares to existing shareholders on the basis of their preemptive rights will be open to U.S. holders of ADSs or Ordinary Shares.

Changes in Rights of Shareholders

Under German law, the rights of holders of E.ON shares may only be changed by a shareholder resolution amending the Articles of Association. The resolution must be passed by at least 75 percent of the share capital represented at the shareholders’ meeting at which the issue was voted upon.

Shareholders’ Meetings

The annual general meeting of shareholders is convened by E.ON’s Board of Management or, when required by law, by its Supervisory Board, and must be held during the first eight months of the fiscal year. In addition, an extraordinary meeting of the shareholders may be called by the Board of Management, the Supervisory Board or shareholders owning in the aggregate at least 5 percent of the Company’s issued share capital. There is no minimum quorum requirement for shareholder meetings. Each shareholder may be represented by a proxy by means of a written or electronic power of attorney. In Germany, non-institutional shareholders typically deposit their shares with a German bank (Depotbank). Such a bank may exercise the voting rights in relation to the

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deposited shares only if authorized to do so by a proxy of the shareholder. Such proxies are revocable at any time. If a shareholder giving a proxy does not give the bank instructions on how to exercise the voting rights, the bank will exercise the voting rights in accordance with its own proposals as previously communicated to the shareholder. Holders of ADSs may vote their shares by proxy by signing and returning the proxy card mailed to them by JPMorgan Chase Bank N.A. (the “Depositary”) in advance of the meeting. The Depositary will, to the extent permitted by law, the Articles of Association and the provisions of the ADSs, vote or cause to be voted all ADSs for which it receives signed proxies by the applicable record date.

At the annual general meeting, shareholders are called upon to approve the distribution of Company profits, to ratify the actions of the Board of Management and the Supervisory Board taken during the prior year, and to appoint the Company’s auditors. When necessary, other matters shall be resolved at shareholders’ meetings in accordance with the relevant provisions of German law, including:


	•	election of members of the Supervisory Board (other than those elected by the employees);

	•	amendment of the Articles of Association;

	•	measures to increase or reduce share capital;

	•	mergers and similar transactions; and

	•	resolutions regarding the dissolution of the Company.

Notice of any shareholders’ meeting, including an agenda describing items to be voted upon, shall be published in the electronic form of the German Federal Official Gazette (elektronischer Bundesanzeiger) and in one other major daily German newspaper no later than thirty days before the deadline for registration as described below. Holders of ADRs will be notified of any shareholders’ meeting by the Depositary.

At the annual general meeting of shareholders in 2005, E.ON AG’s Articles of Association were amended with respect to the requirements that shareholders must comply with in order to be eligible to participate in, and vote at, any E.ON shareholders’ meeting. The amendment became effective by registration in the companies’ register in January 2006 and therefore applies for the first time to the annual general meeting of shareholders to be held on May 4, 2006. Specifically, shareholders are required to:


	•	register in text form in the German or English language no later than the end of the seventh day prior to the day of the shareholders’ meeting; and

	•	prove their right to participate in the shareholders’ meeting and to exercise the voting right. This must occur by the end of the seventh day prior to the day of the shareholders’ meeting by presenting proof of the shareholding in text form in the German or English language issued by the institution where the shares are deposited. Such proof of shareholding must relate to the beginning of the twenty-first day prior to the shareholders’ meeting.

The registration of the shareholders as well as the proof of the shareholding must be received by the Company at an address specified in the notice of the shareholders’ meeting.

Pursuant to a shareholder resolution approved at the former VEBA extraordinary shareholders’ meeting held on February 10, 2000, the Company excluded share certification in order to save the Company and its shareholders the high costs of printing and distributing share certificates. The shareholders’ right to share certificates and profit-sharing coupons is thus excluded except as provided by the rules governing stock exchanges on which the shares are listed. E.ON has not issued and does not intend to issue share certificates.

Transparency and Corporate Reporting

The Board of Management and Supervisory Board of E.ON AG place a great deal of value on the transparency of corporate governance. E.ON’s shareholders, capital markets participants, financial analysts, shareholder groups and the media are regularly and promptly informed of the condition of, and any material changes in, the Company’s business. E.ON makes particular use of the Internet in communicating with its shareholders and the financial markets in general.

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In particular, the Company produces the following financial reporting materials on a regular basis:


	•	Quarterly reports;

	•	Annual reports prepared in accordance with German law (in both German and English);

	•	The Annual Report on Form 20-F;

	•	A press conference at the time of release of the German annual report; and

	•	Telephone conferences for analysts following the release of quarterly or annual results, as well as other investor relations presentations.

The expected dates of issue for the Company’s financial reports are summarized in the financial calendar, which is available on the Internet at www.eon.com. Material appearing on the website is not incorporated by reference in this annual report.

In addition to its regularly scheduled financial reporting, announcements of material events are published by the Company through the German ad hoc disclosure system, released to the press and submitted to the SEC on Form 6-K.

Foreign Share Ownership

There are no limitations on the right to own Ordinary Shares, including the right of non-resident or foreign owners to hold or vote the Ordinary Shares, imposed by German law or the Articles of Association of E.ON AG.

Change of Control Provisions

There are no provisions in E.ON AG’s Articles of Association that would have an effect of delaying, deferring or preventing a change in control of E.ON and that would only operate with respect to a merger, acquisition or corporate restructuring involving it or any of its subsidiaries. German law does not specifically regulate business combinations with interested shareholders. However, general principles of German law may restrict business combinations under certain circumstances.

Disclosure of Shareholdings

E.ON AG’s Articles of Association do not require shareholders to disclose their shareholdings. The Securities Trading Act which became effective on January 1, 1995 requires each investor whose investment in a German corporation (including E.ON AG) listed on organized markets of a German, European Union or European Economic Area stock exchange reaches, passes or falls below 5 percent, 10 percent, 25 percent, 50 percent or 75 percent of the voting rights of such corporation to notify such corporation and BAFin promptly in writing, but in any event within seven calendar days. Failure of a shareholder to notify the company will, for so long as such failure continues, disqualify such shareholder from exercising the voting rights attached to his shares. In connection with this requirement, the Securities Trading Act contains various rules designed to ensure the attribution of shares to the person who has effective control over the shares.

Additionally, the German Takeover Act (Wertpapiererwerbs- und Übernahmegesetz) requires the publication of the acquisition of “control,” which is defined as the holding of at least 30 percent of the voting rights in a target company, within seven days.

The Securities Trading Act also requires the reporting of certain directors’ dealings. According to the Act, persons discharging managerial responsibilities within a publicly traded issuer have to notify both the issuer and the German Federal Financial Supervisory Authority about their transactions relating to the issuer’s shares and derivatives or other financial instruments linked to those shares. Certain persons closely associated with these managers, for example spouses, dependent children, or other relatives sharing the same household, are under the same obligation. Similarly, the reporting obligation also applies to legal entities, trusts and partnerships that are managed or controlled by any such manager or associated person, or that are set up for the benefit of such a person, or whose economic interests are substantially equivalent to those of such person. There is no notification obligation until the total amount of transactions of a covered manager and all his or her associated persons is at

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least €5,000 during any calendar year. The issuer is obliged to publish all notifications it receives on its website; E.ON made available all such disclosure received during 2005 on its website. Material appearing on the website is not incorporated by reference in this annual report.

Changes in Capital

Under German law, share capital may be increased in consideration of contributions in cash or in kind. To prepare such capital increase, the company may establish authorized capital (Genehmigtes Kapital) or conditional capital (Bedingtes Kapital). Authorized capital provides a company’s board of management with the flexibility to issue new shares for a period of up to five years. Conditional capital allows the board of management to issue new shares for specified purposes, including employee stock option plans, mergers and the issuance of shares upon conversion of bonds with warrants and convertible bonds. Capital increases and the establishment of authorized or conditional capital require an amendment to the articles of association approved by 75 percent of the issued shares present at the shareholders’ meeting at which the increase is proposed. The board of management must also obtain the approval of the supervisory board before issuing new shares. Likewise, the share capital may be reduced. This requires shareholders’ authorization passed by at least 75 percent of the share capital represented at the shareholders’ meeting. If those shares are to be canceled, an additional resolution of the board of management approved by the supervisory board to amend the articles of association to take into account the reduction in share capital is required. E.ON AG’s Articles of Association do not contain conditions regarding changes in the share capital that are more stringent than German law requires.

Authorized and Conditional Capital. Subject to the approval of the Supervisory Board, the Board of Management is authorized to increase the Company’s capital stock until April 27, 2010 by up to €540,000,000 through the one-time or repeated issuance of new Ordinary Shares in return for cash or in kind contributions. E.ON shareholders generally have pre-emptive rights with respect to the issuance of authorized shares issued in return for cash contributions, though their rights may be excluded by the Board of Management, subject to approval by the Supervisory Board, under certain circumstances set forth in the Articles of Association. Subject to the approval of the Supervisory Board, the Board of Management is authorized to exclude the shareholders’ pre-emptive rights with respect to the issuance of authorized shares issued in return for contributions in kind.

Also pursuant to its Articles of Association, E.ON’s capital stock has been conditionally increased by up to €175,000,000. This conditional increase may be implemented only to the extent that holders of conversion rights or obligations or option rights issued under a program authorized by the E.ON shareholders on April 30, 2003 exercise their conversion or option rights or to the extent that the increase is necessary for the fulfillment of conversion obligations and no own shares are used for servicing.

For more information regarding the Company’s capital stock, see Note 17 of the Notes to Consolidated Financial Statements.

Share Buyback. In 2003, E.ON purchased 969 Ordinary Shares in the market and an additional 240,000 Ordinary Shares from a subsidiary and distributed 244,796 Ordinary Shares from treasury stock to its employees in connection with existing employee share purchase plans. In 2004, E.ON purchased 212,135 Ordinary Shares in the market and distributed 240,754 Ordinary Shares from treasury stock to its employees in connection with existing plans, as well as 320 Ordinary Shares to certain former shareholders of Gelsenberg AG in order to meet pre-existing conversion claims. In 2005, E.ON purchased 830,559 Ordinary Shares in the market and distributed 308,704 Ordinary Shares from treasury stock to employees in connection with existing plans. A total of 35,749 Ordinary Shares were purchased as compensation for former shareholders. 35,736 of these shares were designated for former Stinnes minority shareholders and 13 shares were distributed to former shareholders of Gelsenberg AG. Pursuant to shareholder resolutions approved at the annual general meeting of shareholders held on April 27, 2005, the Board of Management is authorized to buy back up to 10 percent of E.ON AG’s outstanding share capital through October 27, 2006. For additional details on this share buyback plan and the share repurchases in 2005, see “Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers.” See also Note 17 of the Notes to Consolidated Financial Statements.

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Significant Differences in Corporate Governance Practices for Purposes of Section 303A.11 of the New York Stock Exchange Listed Company Manual (the “NYSE Manual”)

Corporate governance principles for German stock corporations (Aktiengesellschaften) are set forth in the Stock Corporation Act, the Co-Determination Act and the German Corporate Governance Code. E.ON believes the following to be the significant differences between German corporate governance practices, as E.ON has implemented them, and those applicable to U.S. companies under NYSE listing standards, as set forth in Section 303A of the NYSE Manual.

E.ON’s Implementation of the German Corporate Governance Code. The German Corporate Governance Code was released in 2002 by a commission comprised of German corporate governance experts, including top managers of large German companies and representatives of institutional and retail investors, academia, the accounting profession and labor unions, that was appointed by the German Federal Ministry of Justice in 2001. The Code has been amended twice since its initial release, most recently in June 2005. As a general rule, the Code will be reviewed annually and amended if necessary to reflect international corporate governance developments. The Code describes and summarizes the basic mandatory statutory corporate governance principles found in the Stock Corporation Act and other provisions of German law. In addition, it contains supplemental recommendations and suggestions for standards on responsible corporate governance intended to reflect generally accepted best practice.

The Code addresses six core areas of corporate governance. These are (i) shareholders and shareholders’ meetings, (ii) the interaction between the board of management (Vorstand) and the supervisory board (Aufsichtsrat), (iii) the board of management, (iv) the supervisory board, (v) transparency and (vi) accounting and audits. Although these corporate governance issues are similar to those covered by the NYSE corporate governance guidelines and code of business conduct that a U.S. company subject to the NYSE listing standards must adopt and disclose, the Code’s provisions as such are not legally binding.

The Code contains three types of provisions. First, the Code describes and summarizes the existing statutory, i.e., legally binding, corporate governance framework set forth in the Stock Corporation Act and in other German laws. Those laws — and not the incomplete and abbreviated summaries of them reflected in the Code — must be complied with. The second type of provisions are “recommendations.” While these are not legally binding, §161 of the Stock Corporation Act requires that a German stock corporation listed on a stock exchange in the European Union or European Economic Area must issue an annual compliance report stating which of these Code recommendations, if any, are not being applied. The third and final type of Code provisions comprises “suggestions” which issuers may choose not to adopt without making any related disclosure. The Code contains a significant number of such suggestions, covering almost all of the core areas of corporate governance it addresses.

E.ON issued its annual compliance report for 2005 on December 19, 2005. E.ON’s report notes that it has complied with all of the legally binding provisions of the Code, as well as with all of its recommendations, other than those relating to directors’ and officers’ insurance (the Code recommends that such policies include a deductible, E.ON’s does not) and the disclosure of individual compensation data for the members of the board of management and supervisory board (E.ON discloses such information on an individual basis only from 2005 (covering fiscal 2004) onwards). Neither of these points is expressly addressed by the NYSE listing standards applicable to U.S. companies. A copy of the complete compliance report is available on E.ON’s website at www.eon.com. Information appearing on the website is not incorporated by reference into this annual report.

A German Stock Corporation is Required to Have a Two-Tier Board System. A German stock corporation is required by the Stock Corporation Act to have both a supervisory board and a board of management. This contrasts with the unitary board of directors envisaged by the relevant laws of all U.S. states and the NYSE listing standards. Under the Stock Corporation Act, the two boards are separate and no individual may be a member of both boards. Both the members of the board of management and the members of the supervisory board owe a duty of loyalty and care to the stock corporation.

The board of management is responsible for managing the company and representing the company in its dealings with third parties. The board of management is also required to ensure appropriate risk management

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within the corporation and to establish an internal monitoring system. The members of the board of management, including its chairman or speaker, are regarded as equals and share collective responsibility for all management decisions.

The supervisory board appoints and removes the members of the board of management. Although it is not permitted to make management decisions, the supervisory board has comprehensive monitoring functions, including advising the company on a regular basis and participating in decisions of fundamental importance to the company. To ensure that these monitoring functions are carried out properly, the board of management must, among other things, regularly report to the supervisory board with regard to current business operations and business planning, including any deviation of actual developments from concrete and material targets previously presented to the supervisory board. Transactions of fundamental importance to the stock corporation, such as major strategic decisions or other actions that may have a fundamental impact on the company’s assets and liabilities, financial condition or results of operations, are also subject to the consent of the supervisory board. The supervisory board may also request special reports from the board of management at any time.

The supervisory board of a large company like E.ON is subject to the German principle of employee “co-determination” of the company’s fundamental business direction. Accordingly, under the German Co-determination Act, E.ON’s Supervisory Board consists of representatives of the shareholders and representatives of the employees. E.ON’s employees have the right to elect one-half of the total of 20 Supervisory Board members. In addition, the Chairman of E.ON’s Supervisory Board is a shareholder representative who has the deciding vote in the event of a tie.

The Committees Required by the NYSE Manual are Not Required Under the Stock Corporation Act or the Code. The only supervisory board committee required under German law is a mediation committee, which is required in companies with more than two thousand employees in Germany that are subject to the principle of employee co-determination. This committee’s function is to assist the supervisory board by making proposals for board of management member nominees in the event that the two-thirds majority of employee votes needed to appoint a board of management member is not met. However, the Code contains the recommendation that the supervisory board also establish one or more committees with sufficiently qualified members. In particular, it recommends establishing an “audit committee” to handle issues of accounting and risk management, auditor independence, the engagement and compensation of outside auditors appointed by the shareholders’ meeting and the determination of auditing focal points. The Code suggests that the chairman of the audit committee should not be the current chair of the supervisory board or a former member of the board of management of the stock corporation. The Code also includes suggestions on other subjects that may be handled by committees, including corporate strategy, compensation of the members of the board of management, investments and financing. Under the Stock Corporation Act, any supervisory board committee must regularly report to the supervisory board.

E.ON has created a Finance and Investment Committee, an Audit Committee and an Executive Committee. As a result of its listing on the NYSE, E.ON’s Audit Committee is required to comply with the provisions of Section 301 of Sarbanes-Oxley and Rule 10A-3 of the U.S. Securities Exchange Act of 1934 (“Rule 10A-3”), which are also applicable to U.S. companies. As a foreign private issuer, however, E.ON has an extended compliance period for most of these rules, and must comply by July 31, 2005. E.ON has chosen to comply with these requirements in advance of their formal effective date, and believes that its Audit Committee is in compliance with the provisions of Rule 10A-3 applicable to foreign private issuers. E.ON is also required to disclose information concerning any “audit committee financial expert” (as defined in the relevant SEC rules) serving on its Audit Committee, the fees E.ON pays to its auditors for various services and the policies E.ON has for approving engagements of these auditors, and has done so in Item 16 of this annual report.

E.ON’s Audit Committee is Not Subject to All of the Requirements the NYSE Manual Applies to U.S. Companies. E.ON’s Audit Committee is not subject to requirements similar to those applied to U.S. companies under Section 303A.02 or Section 303A.07 of the NYSE Manual. These requirements include an affirmative determination that audit committee members are “independent” according to stricter criteria than those set forth in Rule 10A-3 as applicable to foreign private issuers, the adoption of an annual performance evaluation, and the review of an auditor’s report describing internal quality-control issues and procedures and all relationships between the auditor and the corporation. The Code requires that the supervisory board and the audit

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committee monitor the work of the independent auditors and receive reports from the auditors on their activities. However, these reporting requirements are not as detailed as those set forth in Section 303A.07 of the NYSE Manual.

German corporate law does not require an affirmative independence determination, meaning that the supervisory board need not make affirmative findings that audit committee members are independent. Nevertheless, both the Stock Corporation Act and the Code contain several rules, recommendations and suggestions to ensure the supervisory board’s independent advice and supervision of the board of management. Under the Stock Corporation Act, advisory, service and certain other contracts between a member of the supervisory board and the company require the supervisory board’s approval. A similar requirement applies to loans granted by the stock corporation to a supervisory board member or other persons, such as certain members of the supervisory board member’s family. In addition, the Code recommends that no more than two former members of the board of management be members of the supervisory board and that supervisory board members not exercise directorships or accept advisory tasks for important competitors of the stock corporation. Furthermore, the Code suggests that the chairman of the audit committee should not be the current chair of the supervisory board or a former member of the board of management of the stock corporation, and E.ON has complied with that suggestion.

The Code recommends that each member of the supervisory board inform the supervisory board of any conflicts of interest which may result from a consulting or directorship function with clients, suppliers, lenders or other business partners of the stock corporation. In the case of material conflicts of interest or ongoing conflicts, the Code recommends that the mandate of the supervisory board member be terminated. The Code further recommends that any conflicts of interest that have occurred be reported by the supervisory board at the annual shareholders’ meeting, together with the action taken, and that potential conflicts of interest be also taken into account in the nomination process for the election of supervisory board members.

Section 303A.02 of the NYSE Manual also imposes independence requirements on members of audit committees of U.S. companies that are more stringent than those set forth in Rule 10A-3, requiring, for instance, that any director who is an employee of an issuer will not be considered independent until three years after the end of such employment relationship. E.ON’s Audit Committee, in accordance with the requirements of the Co-Determination Act (and as permitted by Rule 10A-3, as applicable to foreign private issuers), includes two current employees, neither of whom is an executive officer, as well as the former chairman of E.ON’s Board of Management, who retired from E.ON’s Board of Management in May 2003.

MATERIAL CONTRACTS

In May 2002, in connection with E.ON’s acquisition of Ruhrgas, E.ON 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. The arrangement provides for joint control of Degussa by E.ON and RAG. See also “Item 4. Information on the Company — History and Development of the Company — Ruhrgas Acquisition.” An English translation of the Framework Agreement between RAG AG, RAG Beteiligungs-GmbH, RAG Projektgesellschaft mbH and EBV Aktiengesellschaft, and E.ON AG, Chemie Verwaltungs AG and E.ON Vermögensanlage GmbH has been incorporated by reference as an exhibit to this annual report.

In May 2005, E.ON sold Viterra to Deutsche Annington. The details of the transaction are described in more detail in “Item 4. Information on the Company — Business Overview — Discontinued Operations — Other Activities.” A copy of the sale and purchase agreement has been filed as an exhibit to this annual report.

EXCHANGE CONTROLS

At the present time, Germany does not restrict the movement of capital between Germany and other countries or individuals except Iraq, certain persons and entities associated with Osama bin Laden, the Al-Qaida network and the Taliban and certain other countries and individuals subject to embargoes in accordance with German law and applicable resolutions adopted by the United Nations and the EU. However, for statistical purposes only, every individual or corporation residing in Germany (a “Resident”) must report to the German Central Bank (Deutsche Bundesbank), subject only to certain immaterial exceptions, any payment received from

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or made to or on account of an individual or a corporation resident outside of Germany (a “Non-resident”) if such payment exceeds €12,500 (or the equivalent in a foreign currency). In addition, Residents must report any claims against or any liabilities payable to Non-residents if such claims or liabilities, in the aggregate, exceed €5 million (or the equivalent in a foreign currency) at the end of any month. Residents are also required to report annually any shareholdings of 10 percent or more held in non-resident corporations with total assets of more than €3 million, and resident corporations with assets in excess of €3 million must report annually any shareholdings of 10 percent or more in the company held by a Non-resident.

TAXATION

The following is a summary of material U.S. federal income tax and German tax considerations relating to the ownership of ADSs or Ordinary Shares. The discussion is based on tax laws of the United States and Germany as in effect on the date of this annual report, including the Convention between the United States of America and the Federal Republic of Germany for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion With Respect to Taxes on Income and Capital and to Certain Other Taxes (the “Income Tax Treaty”), and the Convention Between the United States of America and the Federal Republic of Germany for the Avoidance of Double Taxation with Respect to Taxes on Estates, Inheritances, and Gifts (the “Estate Tax Treaty”). Such laws are subject to change. The discussion is also based in part upon the representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.

The discussion is limited to a general description of certain U.S. federal income and German tax consequences with respect to ownership and disposition of ADSs or Ordinary Shares by a U.S. Holder. In general, a “U.S. Holder” is any beneficial owner of ADSs or Ordinary Shares (1) who is a resident of the United States for the purposes of the Income Tax Treaty, (2) who is not also a resident of the Federal Republic of Germany for the purposes of the Income Tax Treaty, (3) who owns the ADSs or Ordinary Shares as capital assets, (4) who does not hold ADSs or Ordinary Shares as part of the business property of a permanent establishment or a fixed base located in Germany and (5) who is entitled to benefits under the Income Tax Treaty with respect to income and gain derived in connection with the ADSs or Ordinary Shares. The discussion does not purport to be a comprehensive description of all the tax considerations that may be relevant to the ownership of ADSs or Ordinary Shares, and, in particular, it does not address U.S. federal taxes other than income tax and German taxes other than income tax, gift and inheritance taxes. Moreover, the discussion does not consider any specific facts or circumstances that may apply to a particular U.S. Holder, some of which (for example, tax-exempt entities, persons that own, directly or indirectly, 10 percent or more of any class of the Company’s stock, holders subject to the alternative minimum tax, securities broker-dealers and certain other financial institutions, holders who hold the ADSs or Ordinary Shares in a hedging transaction or as part of a straddle or conversion transaction or holders whose functional currency is not the U.S. dollar) may be subject to special rules.

Owners of ADSs or Ordinary Shares are strongly urged to consult their tax advisers regarding the U.S. federal, state, local, German and other tax consequences of owning and disposing of ADSs or Ordinary Shares. In particular, owners of ADSs or Ordinary Shares are urged to consult their tax advisers to confirm their status as U.S. Holders and the consequence to them if they do not so qualify.

In general, for U.S. federal income tax purposes and for purposes of the Income Tax Treaty, holders of ADSs will be treated as the owners of the Ordinary Shares represented by those ADSs.

TAXATION OF GERMAN CORPORATIONS

Profits earned by a German resident corporation are subject to a uniform corporate income tax rate of 25 percent. German resident corporations are also subject to a solidarity surcharge equal to 5.5 percent of their corporate income tax liability. The aggregate corporate income tax and solidarity surcharge amount to 26.375 percent. For a transition period, the distribution of profits earned under the former imputation system may increase or decrease the corporate tax liability. In addition to these taxes, profits of a German resident corporation are subject to a municipal trade income tax. This tax is levied at rates set by each municipality in which the

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corporation maintains a business establishment. The municipal trade income tax is an allowable deduction for corporate income and municipal trade income tax purposes.

TAXATION OF DIVIDENDS

The Company is generally required to withhold tax on dividends in an amount equal to 20 percent of the gross amount paid to resident and non-resident stockholders. There is a 5.5 percent solidarity surcharge on the German withholding tax on dividend distributions paid by the Company. The surcharge amounts to 1.1 percent (5.5 percent × 20 percent) of the gross dividend amount. This results in an aggregate withholding rate of 21.1 percent. A full refund of this surcharge and partial refund of the withholding tax can be obtained by U.S. Holders under the Income Tax Treaty. In the case of any U.S. Holder, other than a U.S. corporation owning ADSs or Ordinary Shares representing at least 10 percent of the voting stock of the Company, the German withholding tax is refunded to reduce such tax to 15 percent of the gross amount of the dividend.

For U.S. federal income tax purposes, the gross amount of dividends paid on Ordinary Shares, without reduction for German withholding tax, generally will be subject to U.S. federal income taxation as foreign source dividend income, and will not be eligible for the dividends received deduction generally allowed to U.S. corporations. Subject to certain exceptions for short-term and hedged positions that, an individual U.S. Holder generally will be subject to U.S. taxation at a maximum rate of 15 percent in respect of dividends received before 2009 if the dividends are “qualified dividends.” Dividends that the Company pays generally will be treated as qualified dividends if the Company was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”). Based on the Company’s audited consolidated financial statements and relevant market and shareholder data, the Company believes that it was not treated as a PFIC for U.S. federal income tax purposes with respect to its 2004 or 2005 taxable year. In addition, based on the Company’s audited consolidated financial statements and current expectations regarding the value and nature of its assets, the sources and nature of its income, and relevant market data, the Company does not anticipate becoming a PFIC for its 2006 taxable year.

German withholding tax at the 15 percent rate provided under the Income Tax Treaty will be treated as a foreign income tax that, subject to generally applicable limitations under U.S. tax law, is eligible for credit against a U.S. Holder’s U.S. federal income tax liability or, at the holder’s election, may be deducted in computing its taxable income. Thus, for a declared dividend of $100, a U.S. Holder would be deemed to have paid German taxes of $15. Foreign tax credits may not be allowed for withholding taxes imposed in respect of certain short-term or hedged positions in securities. U.S. Holders should consult their own advisers concerning the implications of these rules in light of their particular circumstances.

Dividends paid in euros to a U.S. Holder of ADSs or Ordinary Shares will be included in income in a dollar amount calculated by reference to an exchange rate in effect on the date the dividends are received by such holder (or, in the case of the ADSs, by the Depositary). If dividends paid in euros are converted into dollars on the date the dividends are received or treated as received by a U.S. Holder, the holder generally should not be required to recognize foreign currency gain or loss in respect of its dividend income. However, a U.S. Holder may be required to recognize domestic-source foreign currency gain or loss on the receipt of a refund in respect of German withholding tax to the extent the U.S. dollar value of the refund differs from the U.S. dollar equivalent of that amount on the date of receipt of the underlying dividend.

REFUND PROCEDURES

Individual claims for refund are made on a special German form, which must be filed with the German tax authorities: Bundesamt für Finanzen, 53221 Bonn, Germany. Copies of the required form may be obtained from the German tax authorities at the same address, or from the Embassy of the Federal Republic of Germany, 4645 Reservoir Road N.W., Washington D.C. 20007-1998.

As part of the individual refund claim, a U.S. Holder must submit to the German tax authorities the original bank voucher (or certified copy thereof) issued by the paying entity documenting the tax withheld, and an official certification on IRS Form 6166 of its last filed United States federal income tax return. IRS Form 6166 generally may be obtained by filing a request (generally an IRS Form 8802) with the Internal Revenue Service Center in

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Philadelphia, Pennsylvania, U.S. Residency Certification Request, P.O. Box 16347, Philadelphia, PA 19114-0447. U.S. Holders should consult a tax advisor and the instructions to the IRS Form 8802 for further details regarding how to obtain this certification.

Claims must be filed within four years of the end of the calendar year in which the dividend was received.

Under a simplified refund procedure based on electronic data exchange (Datenträgerverfahren), a broker which is registered as a participant in the electronic data exchange procedure with the Bundesamt für Finanzen may file a collective refund claim on behalf of all of the U.S. Holders for whom it holds ADSs or Ordinary Shares in custody.

The refund is assessed against and paid to the broker, which will then pay the refund to the U.S. Holders for whom it is acting. The Bundesamt für Finanzen is entitled to review the U.S. Holders’ eligibility for a refund of withholding tax under the Income Tax Treaty. The data transmitted by the broker may be used by the German tax authorities for administrative exchange of information between Germany and the United States.

Another simplified refund procedure applies if ADSs of a U.S. Holder are registered with brokers participating in the Depository Trust Company (“DTC”). Pursuant to administrative procedures agreed between the German Federal Ministry of Finance and the DTC, claims for refunds payable under the Income Tax Treaty to such U.S. Holders may be submitted to the German tax authorities by the DTC (or a custodian as its designated agent) collectively on behalf of all such U.S. Holders. Details of the collective refund procedure will be available from the DTC.

The Bundesamt für Finanzen will issue refunds to the DTC, which will issue corresponding refund checks to the participating brokers. The Bundesamt für Finanzen is entitled to conduct eligibility reviews, generally within a period of four years.

Refunds under the Treaty are not available in respect of Ordinary Shares or ADSs held in connection with a permanent establishment or fixed base in Germany.

TAXATION OF CAPITAL GAINS

Under the Income Tax Treaty, a U.S. Holder will be protected against German tax on capital gains realized or accrued on the sale or other disposition of ADSs or Ordinary Shares provided the assets of the Company do not consist and have not consisted predominantly of immovable property situated in Germany.

Upon a sale or other disposition of ADSs or Ordinary Shares, a U.S. Holder will recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference between the amount realized and the U.S. Holder’s tax basis in the ADSs or Ordinary Shares. Such gain or loss will generally be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder’s holding period for the ADSs or Ordinary Shares exceeds one year. The net amount of long-term capital gain recognized by an individual U.S. Holder generally is subject to taxation at a minimum rate of 15 percent for gains recognized on or prior to December 31, 2008. Deposits and withdrawals of Ordinary Shares in exchange for ADSs will not result in realization of gain or loss for U.S. federal income tax purposes.

GIFT AND INHERITANCE TAXES

The Estate Tax Treaty provides that an individual whose domicile is determined to be in the United States for purposes of such Treaty will not be subject to German inheritance and gift tax (the equivalent of the United States federal estate and gift tax) on the individual’s death or making of a gift unless the ADSs or Ordinary Shares (1) are part of the business property of a permanent establishment located in Germany or (2) are part of the assets of a fixed base of an individual located in Germany and used for the performance of independent personal services. An individual’s domicile in the United States, however, does not prevent imposition of German inheritance and gift tax with respect to an heir, donee, or other beneficiary who either is or is deemed to be resident in Germany at the time the individual died or the gift was made.

198

The Estate Tax Treaty also provides a credit against U.S. federal estate and gift tax liability for the amount of inheritance and gift tax paid to Germany, subject to certain limitations, in a case where the ADSs or Ordinary Shares are subject to German inheritance or gift tax and U.S. federal estate or gift tax.

OTHER GERMAN TAXES

There are no German transfer, stamp or other similar taxes that would apply to U.S. Holders who purchase or sell ADSs or Ordinary Shares.

INFORMATION REPORTING AND BACKUP WITHHOLDING

Dividends on Ordinary Shares or ADSs, and payments of the proceeds of a sale of Ordinary Shares or ADSs, paid within the United States or through certain U.S.-related financial intermediaries are subject to information reporting and may be subject to backup withholding unless the holder (1) is a corporation or other exempt recipient or (2) provides a taxpayer identification number and certifies that no loss of exemption from backup withholding has occurred. Holders that are not U.S. persons generally are not subject to information reporting or backup withholding. However, such a holder may be required to provide a certification to establish its non-U.S. status in connection with payments received within the United States or through certain U.S.-related financial intermediaries.

DOCUMENTS ON DISPLAY

E.ON AG is subject to the reporting requirements of the Securities Exchange Act of 1934, as amended. In accordance with these requirements, E.ON files reports and other information with the Securities and Exchange Commission. These materials, including this annual report and its exhibits, may be inspected and copied at the SEC’s Public Reference Room at 450 Fifth Street N.W., Washington D.C. 20549. Copies of materials may be obtained from the Public Reference Room at prescribed rates. The public may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC in the United States at 1-800-SEC-0330. E.ON’s filings, including this annual report, are also available on the SEC’s website at www.sec.gov. Material appearing on this website is not incorporated by reference into this annual report. In addition, material filed by E.ON with the SEC may be inspected at the offices of the New York Stock Exchange at 20 Broad Street, New York, New York 10005.


Item 11.	Quantitative and Qualitative Disclosures about Market Risk.

The following discussion should be read in conjunction with “Summary of Significant Accounting Policies” in Note 2 of the Notes to Consolidated Financial Statements and in conjunction with Notes 28 and 29 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.

Risk Identification and Analysis

In the normal course of business, the Company is exposed to foreign currency risk, interest rate risk, commodity price risk, share price risk, and counterparty risk. These risks create volatility in equity, earnings and cash flows from period to period. The Company makes use of derivative instruments generally in order to manage currency risk, interest rate risk and commodity price risk. Foreign exchange and interest rate derivatives held by the Company are used only for hedging purposes. The market units also engage in hedging and proprietary trading of energy-related commodity derivatives, subject to established guidelines for risk management. See “— Commodity Price Risk Management” below and the subsections on trading of the market units in “Item 4. Information on the Company — Business Overview.” In its hedging and proprietary trading activities, the Company generally utilizes established and widely-used derivative instruments for which significant liquidity exists. The Company’s comprehensive framework for risk management includes general risk management guidelines for the use and evaluation of derivative instruments that are in place throughout the Group.

199

As part of its risk management system, the Company utilizes instruments such as interest rate swaps, interest rate/cross currency swaps, interest rate options, foreign exchange forward contracts, cross currency swaps, foreign exchange options, commodity forwards, commodity swaps, commodity futures and commodity options, seeking to reduce its risk exposure by entering into offsetting market positions.

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 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.

Foreign Exchange and Interest Rate Risk Management Principles

The Company’s Corporate Treasury, which is primarily responsible for entering into derivative foreign exchange and interest rate contracts for the Group and its companies, acts as a service center for the Company and not as a profit center. With E.ON AG’s approval, individual Group companies may also hedge their currency and interest rate risks directly with third parties in exceptional cases.

The Company uses a Group-wide treasury, risk management and reporting system which incorporates all relevant functions, including those of the Corporate Treasury, Back Office and Financial Controlling units. This system is a standard information technology solution and is both fully integrated and continuously updated. It is designed to provide for the systematic and consistent identification and analysis of the Company’s overall financial and market risks with regard to liquidity, currencies and interest rates. The system is also used to determine, analyze and monitor the Company’s short- and long-term financing and investment requirements as well as market and counterparty risks arising from short- and long-term deposits and hedging transactions.

The range of actions, responsibilities and financial reporting procedures to be followed by each Group company are outlined in detail in the Company’s internal financial guidelines. The market units have enacted their own guidelines for financial risk management within the limits established by the Group’s financial guidelines. To ensure efficient risk management at E.ON AG, the Corporate Treasury, Back Office and Financial Controlling departments are organized as strictly separate units. Standard software is employed in processing relevant business transactions. The Financial Controlling department performs continuous and independent risk controlling. The department prepares operational financial plans, calculates market price and counterparty risks, and evaluates financial transactions. The Financial Controlling department reports to management at regular intervals on the Group’s liquidity, foreign exchange, interest rate and commodity price risks as well as counterparty risks. Those subsidiaries that make use of external hedging transactions with third parties have similar organizational and reporting arrangements in place.

Foreign Exchange Rate Risk Management

Due to the international nature of some of its business activities, the Company is exposed to exchange risk related to sales, assets, receivables and liabilities denominated in foreign currencies, net investments in foreign operations and anticipated foreign exchange payments. Of the Company’s consolidated revenue in 2005, 2004 and 2003, approximately 35 percent, 34 percent and 33 percent, respectively, arose due to transactions with customers which were not located in member states of the EMU, and therefore exposed the Company to foreign exchange rate risk. The Company’s exposure results mainly from transactions in United States dollars, British pounds, Norwegian krona and Swedish krona and from net investments in foreign operations whose functional currencies are U.S. dollars, British pounds and Swedish krona. As of December 31, 2005, the Company was using hedging transactions with respect to each of these currencies.

In accordance with E.ON’s hedging policy, macro-hedging transactions relating to currency risks are generally completed for periods of up to 18 months. Under certain circumstances the hedging horizon is longer. Macro-hedging transactions comprise a number of individual underlying transactions that have been grouped together and hedged as an individual unit.

200

The principal derivative financial instruments used by E.ON to cover foreign currency exposures are foreign exchange forward contracts, cross currency swaps, interest rate/cross currency swaps and foreign exchange options. As of December 31, 2005, the E.ON Group had entered into foreign exchange forward contracts with a nominal value of €12.4 billion, cross currency swaps with a nominal value of €16.3 billion, interest rate/cross currency swaps with a nominal volume of €0.4 billion and foreign exchange options with a nominal value of €0.4 billion.

Market risks for foreign exchange derivatives consist of the positive and negative changes in net asset value that result from fluctuations of the relevant currencies on the respective financial markets. The market values of derivative financial instruments are calculated by comparing all relevant price components of a transaction at the time of the deal with those prevailing on the valuation date. The relevant parameters used to calculate the potential change in market value are the contract amount and the contractual forward-exchange rate. In line with 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” is equal to the maximum potential loss (on the basis of a probability of 99 percent) from derivative 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 market risk analysis of the Company’s foreign exchange derivatives by transaction and maturity as of December 31, 2005 and December 31, 2004 is summarized in the following table.

Total Volume of Foreign Currency Derivatives as of December 31, 2005 and December 31, 2004


			December 31, 2005									December 31, 2004

								1-day		10-day							1-day		10-day
			Nominal		Fair			Value-		Value-		Nominal		Fair			Value-		Value-
			Value		Value			at-Risk		at-Risk		Value		Value			at-Risk		at-Risk

			(€ in millions)
FX forward transactions
	Buy			4,091.3		79.2			16.9		53.4		4,238.2		(41.3	)		11.0		33.0
	Sell			8,331.2		(81.7	)		23.6		74.6		5,328.6		134.2			11.8		35.4
FX currency options
	Buy			227.7		32.8			0.2		0.6		782.7		46.7			1.3		3.9
	Sell			139.6		(39.0	)		0.4		1.3		422.2		(36.4	)		0.4		1.2

		Subtotal		12,789.8		(8.7	)		8.5		26.9		10,771.7		103.2			3.1		9.3

(Remaining maturities)
Cross currency swaps
	up to 1 year			1,734.7		34.7			1.9		6.0		499.1		(7.0	)		2.3		6.9
	1 year to 5 years			8,163.2		57.8			34.6		109.3		11,033.7		484.2			33.4		100.2
	more than 5 years			6,358.4		66.6			8.7		27.5		7,163.8		236.3			12.0		36.0
Interest rate/cross currency swaps
	up to 1 year			125.0		13.1			0.5		1.6		102.3		1.4			0.5		1.5
	1 year to 5 years			316.4		5.0			2.3		7.3		125.0		12.1			0.5		1.5
	more than 5 years			—		—			—		—		297.4		(38.5	)		2.5		7.5

		Subtotal		16,697.7		177.2			40.6		128.3		19,221.3		688.5			44.9		134.7

		Total		29,487.5		168.5			48.0		151.7		29,993.0		791.7			44.6		133.8

The market risk table shows the outstanding nominal values and market values of foreign exchange derivatives as of the balance sheet date without taking into account any economic hedging correlations between hedging contracts on the one hand, and recognized and pending underlying transactions or net foreign investments on the other hand. In fact, all of the Group’s foreign currency derivatives are assigned to a balance sheet item, a pending purchase or sales contract or an anticipated transaction.

201

As an additional means of monitoring market risks, a 10-day value-at-risk (“VaR”) is calculated on derivative positions at regular intervals. In doing so, the market risk, as calculated using the value-at-risk concept, is multiplied by a factor of 3.16 (the square root of ten), in line with the recommendation for the capital adequacy of banks issued by the Bank for International Settlements (“BIS”). The results of this calculation are included in the table above; for the 2004 data, however, this 10-day VaR has been calculated with a rounded factor of 3.

While the nominal value of foreign exchange currency derivatives at December 31, 2005 remained essentially unchanged compared with year-end 2004, the fair value has decreased significantly due to adverse movements in exchange rates.

The value-at-risk amounts presented here are maximum potential daily losses. It is highly unlikely that the Company would experience continuous daily losses such as these over an extended period of time.

Interest Rate Risk Management

Several line items on the Group’s balance sheet and associated financial derivatives bear fixed interest rates, and are therefore subject to changes in fair value resulting from changes in market rates. The Company also faces a similar risk with regard to balance sheet items and associated financial derivatives bearing floating rates, as changes in interest rates will affect the Company’s cash flows. The Company seeks to maintain a desired mix of floating-rate and fixed rate debt in its overall debt portfolio. The Company uses interest rate swaps and interest rate options to allow it to diversify its sources of funding and to reduce the impact of interest rate volatility on its financial condition.

Financial derivatives are also used to realize time congruent hedging of interest rate risks. E.ON’s policy provides that macro-hedging transactions can be concluded for periods of up to five years to cover interest rate risks. For micro-hedging purposes, any adequate term is allowed for individual hedges of foreign exchange and interest rates. However, where economically feasible, the Company applies hedge accounting under SFAS 133 to its interest rate derivatives.

The principal derivative financial instruments used by E.ON to cover interest rate risk exposures are interest rate swaps. As of December 31, 2005, the E.ON Group had entered into interest rate swaps with a nominal value of €9.5 billion.

Market risks for interest rate derivatives are calculated in the same manner as those for foreign exchange instruments, as discussed in detail under “— Foreign Exchange Rate Risk Management” above.

202

The market risk analysis of the Company’s interest rate derivatives by transaction and maturity as of December 31, 2005 and December 31, 2004 is summarized in the following table.


	*Total Volume of Interest Rate Derivatives as of December 31, 2005 and December 31, 2004*


				December 31, 2005									December 31, 2004

									1-day		10-day							1-day		10-day
				Nominal		Fair			Value-		Value-		Nominal		Fair			Value-		Value-
				Value		Value			at-Risk		at-Risk		Value		Value			at-Risk		at-Risk

				(€ in millions)
				(Remaining maturities)
Interest rate swaps
	fixed-rate payer
		up to 1 year			612.2		(11.8	)		0.1		0.3		371.0		(5.4	)		0.1		0.3
		1 year to 5 years			1,294.9		(44.1	)		1.4		4.4		2,092.5		(107.9	)		3.1		9.3
		more than 5 years			1,033.5		(18.0	)		4.0		12.6		373.3		(36.6	)		0.8		2.4
	fixed-rate receiver
		up to 1 year			0.0		0.0			0.0		0.0		23.3		0.3			0.0		0.0
		1 year to 5 years			5,364.4		64.3			7.7		24.3		3,914.0		100.6			10.4		31.2
		more than 5 years			1,196.4		(20.7	)		4.4		13.9		147.0		4.5			0.5		1.5

			Subtotal		9.501.4		(30.3	)		6.6		20.9		6,921.1		(44.5	)		6.7		20.1

Interest rate options
	Buy up to 1 year				—		—			—		—		554.6		(7.2	)		0.1		0.3
		1 year to 5 years			—		—			—		—		—		—			—		—
		more than 5 years			—		—			—		—		—		—			—		—
	Sell up to 1 year				—		—			—		—		110.9		(2.0	)		0.0		0.0
		1 year to 5 years			—		—			—		—		—		—			—		—
		more than 5 years			—		—			—		—		—		—			—		—

			Subtotal		0.0		0.0			—		—		665.5		(9.2	)		0.2		0.6

			Total		9,501.4		(30.3	)		6.6		20.9		7,586.6		(53.7	)		6.7		20.1

The market risk table shows the outstanding nominal values and fair values of interest rate derivatives without taking into account any economic hedging correlations between hedging contracts and underlying transactions. In fact, all of the Group’s interest rate derivatives are assigned to a balance sheet item.

The increase in nominal value of interest rate derivatives at December 31, 2005 compared with year-end 2004 is primarily due to new interest rate swaps entered into in order to reduce the effective maturity profile of the financial liabilities portfolio.

A sensitivity analysis was performed on the Group’s interest bearing short- and long-term capital investments and borrowings, including interest rate derivatives. The aggregate hypothetical loss in fair value on all financial instruments and derivative instruments that would have resulted from a 100 basis-point shift in the interest rate structure curve would change the interest rate portfolio’s market value by €43 million (2004: €9 million) as of the balance sheet date. The market risk according to the value-at-risk calculation amounted to €60 million as of December 31, 2005 (2004: €62 million).

Commodity Price Risk Management

E.ON is also exposed to risks resulting from fluctuations in the prices of commodity derivatives and raw materials. Hedging transactions with respect to commodity-related risks of notable scope are conducted only by the market units.

203

The principal derivative instruments used by E.ON to cover commodity price risk exposures are electricity, gas, coal and oil swaps and forwards, electricity options, and exchange-traded electricity future and option contracts, as well as emission-related derivatives.

Derivative instruments are used by the market units to hedge the impact of electricity, gas, coal, oil and CO₂ emission certificate price fluctuations and to enable the market units to make better use of their own power generating capacities as well as power and gas distribution and sales capabilities. To a limited extent, proprietary trading is conducted with the goal of improving operating results within defined limits in specified markets. The trading limits for proprietary trading as well as for other trading activities are established and monitored by a board independent from the trading operations. Limits used on hedging and proprietary trading activities mainly include value-and profit-at-risk numbers, as well as volume, book and credit 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 control, as well as a risk reporting system independent of the trading operations.

As of December 31, 2005, the E.ON Group had entered into electricity, gas, coal, oil and emissions derivative instruments with a nominal value of €44.0 billion (2004: €25.3 billion). The increase in nominal value of commodities derivatives at December 31, 2005 compared with year-end 2004 reflects, apart from changes in scope of consolidation, the increasing price volatility of several commodities.

The fair value of commodity trading transactions for which E.ON has not established economic hedging conditions involving recognized or contractually agreed upon or planned underlying transactions amounted to negative €133.3 million as of December 31, 2005 (2004: negative €25.2 million). A hypothetical 10 percent change in underlying commodity prices would cause the market value of these commodity trading transactions to change by €20 million (2004: €14 million).

Counterparty Risk From the Use of Derivative Financial Instruments

Counterparty risk consists of potential losses that may arise from the non-fulfillment of contractual obligations by individual counterparties. With respect to derivative transactions, counterparty risk is equivalent to the replacement cost incurred by covering the open position in the event of counterparty default. Only transactions with a positive market value for E.ON are exposed to this risk. The Company’s counterparties for derivatives include financial institutions, commodity exchanges, energy distribution companies and broker-dealers, and other entities that satisfy E.ON’s credit criteria. The credit worthiness of all counterparties that are involved in electricity-, gas-, coal-, oil- and emissions-related derivatives with E.ON are thoroughly checked and monitored on a regular basis. The Company receives and pledges collateral in connection with long-term interest and currency hedging derivatives in the banking sector. Furthermore, collateral is required when entering into transactions in commodity derivatives with counterparties that have a low degree of creditworthiness. Derivative transactions are generally executed on the basis of standard agreements that allow for the netting of all outstanding transactions with individual contracting partners. For currency and interest-rate derivatives in the banking sector, this netting option is reflected in the accounting treatment. Exchange-traded electricity future and option contracts as well as emission-related derivatives with a nominal value of €5,059 million as of December 31, 2005 (2004: €4,593 million) are liquid instruments and do not bear individual counterparty risk. The Company’s counterparty risk with respect to derivatives amounts to €7,149 million as of December 31, 2005 (2004: €3,000 million). The increased credit risk as of year-end 2005 mainly reflects the increasing volatility in the commodity markets, leading to the increased use of outstanding instruments and their fair values. Not all counterparties are rated by S&P and/or Moody’s; for these unrated counterparties thorough credit limit checks and credit risk evaluation systems are installed and collateral is sometimes required. E.ON’s Group-wide credit risk management system and credit risk management guidelines are designed to assure thorough and uniform credit worthiness analysis for all counterparties. Significant Group-wide limits and risks are identified and their credit risk exposures are regularly monitored and reported to the E.ON risk committee. The credit risk management system incorporates information on all counterparty risks resulting from commodity trading transactions and financial transactions in the area of deposits, interest rate and foreign exchange risks.

204

E.ON’s contractual ability to net transactions with positive and negative market values with any defaulting counterparty for which a netting agreement is in place is not reflected in the figures presented in the prior paragraph, regardless of whether the counterparty is rated or unrated, causing the credit risk to appear greater than it is in actuality. In addition, the value of collateral posted by counterparties is not taken into account in calculating such figures.


Item 12.	Description of Securities Other than Equity Securities.

Not applicable.

PART II


Item 13.	Defaults, Dividend Arrearages and Delinquencies.

None.


Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds.

From 2005 onwards, E.ON’s paying agent for cash dividends on E.ON’s Ordinary Shares is Bayerische Hypo- und Vereinsbank AG, MCD3, 80311 Munich, Germany.


Item 15.	Controls and Procedures.

The Company carried out an evaluation under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon the Company’s evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures as of the end of the period covered by this report were effective to provide reasonable assurance that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported as and when required. There were no changes in the Company’s internal control over financial reporting that occurred during 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

For more information on E.ON’s compliance with these requirements, see “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance.”


Item 16A.	Audit Committee Financial Expert.

E.ON’s Supervisory Board has determined that the Company’s Audit Committee currently includes two members who qualify as an “Audit Committee Financial Expert” within the meaning of this Item 16A: Dr. Karl-Hermann Baumann and Ulrich Hartmann. Dr. Karl-Hermann Baumann and Ulrich Hartmann are independent, as that term is defined in Rule 10A-3 under the Securities Exchange Act for purposes of the listing standards of the NYSE that are applicable to E.ON.


Item 16B.	Code of Ethics.

E.ON has adopted a special Code of Ethics for the Chief Executive Officer, the Chief Financial Officer and its senior financial officers. The Company has published the text of this Code of Ethics on its corporate website at www.eon.com. Material appearing on this website is not incorporated by reference into this annual report. If E.ON amends the provisions of this Code of Ethics or grants any waiver of such provisions, it will disclose such amendment or waiver on its website at the same address.

205


Item 16C.	Principal Accountant Fees and Services.

In January 2003, the SEC adopted rules requiring disclosure of fees billed by a public company’s independent auditors in each of the company’s two most recent fiscal years.

The following table sets forth the fees billed to the Company for professional services by its principal independent auditor, PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprüfungsgesellschaft (“PwC”), during the fiscal years 2005 and 2004:


	Year Ended		Year Ended
Type of Fees	December 31, 2005		December 31, 2004

	(€ in millions)
Audit Fees		39.8		41.4
Audit-Related Fees		9.7		11.4
Tax Fees		1.4		1.7
All Other Fees		1.1		4.8

Total		52.0		59.3


	*Audit Committee Pre-Approval Policies*

In accordance with German law, E.ON’s independent auditors are appointed by the annual general meeting of shareholders based on a recommendation of E.ON’s Supervisory Board. The Audit Committee of the Supervisory Board prepares the board’s recommendation on the selection of the independent auditors. Subsequent to the auditor’s appointment, the Audit Committee awards the contract and in its sole authority approves the terms and scope of the audit and all audit engagement fees as well as monitors the auditors’ independence. On April 27, 2005, the annual general meeting of shareholders appointed PwC to serve as the Company’s independent auditors for the 2005 fiscal year.

In order to assure the integrity of independent audits, in May 2003 E.ON’s Audit Committee established a policy to approve all audit and permissible non-audit services provided by E.ON’s independent auditors prior to the auditors’ engagement. As part of the approval process, the Audit Committee adopted pre-approval policies and procedures pursuant to which the Audit Committee annually pre-approves certain types of services to be performed by E.ON’s independent auditors. Compliance with these policies is audited and monitored by the Audit Committee on a quarterly basis. Under the policies, the Company’s independent auditors are not allowed to perform any non-audit services which may impair the auditors’ independence under the SEC’s rules. Furthermore, the Audit Committee has limited the aggregate amount of non-audit fees payable to PwC during a fiscal year to a maximum of 40 percent of all fees.

In 2005, the Audit Committee pre-approved the performance by PwC of material services, mainly including the following:


	*Audit Services*


	•	Annual audit for E.ON’s Consolidated Financial Statements;

	•	Quarterly review of E.ON’s interim financial statements;

	•	Statutory audits of financial statements of E.ON AG and of its subsidiaries under the rules of their respective countries;

	•	Attestation of internal controls as part of the external audit; and

	•	Attestation of regulatory filing and other compliance requirements, including regulatory advice, such as carve-out reports and comfort letters.

206

Audit-Related Services


	•	Accounting advice relating to transactions or events;

	•	Due diligence relating to acquisitions, dispositions and contemplated transactions;

	•	Consultation in accounting and corporate reporting matters;

	•	Attestation of compliance with provisions or calculations required by agreements;

	•	Employee benefit plan audits;

	•	Agreed-upon procedures engagements; and

	•	Advisory services relating to internal controls and systems documentation.

Tax Services


	•	Tax compliance services, including return preparation and tax payment planning;

	•	Tax advice relating to transactions or events;

	•	Expatriate employee tax services;

	•	Transfer pricing studies; and

	•	Tax services for employee benefit plans.

All Other Services


	•	Advisory services on corporate governance and risk management;

	•	Advisory services on corporate treasury processes and systems;

	•	Advisory services on information systems; and

	•	Educational and training services on accounting and industry matters.

Services that are not included in one of the categories listed above or in the Audit Committee’s catalogue of pre-approved services require specific pre-approval of the Audit Committee. An approval may not be granted if the service falls into a category of services not permitted by current law or if it is inconsistent with maintaining auditor independence, as expressed in the rules promulgated by the SEC.


Item 16D.	Exemptions from the Listing Standards for Audit Committees.

Information required by this Item is incorporated by reference to “Item 10. Additional Information — Memorandum and Articles of Association — Corporate Governance — The Supervisory Board Committees.”

207


Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers.

The following table provides information on Ordinary Shares purchased by the Company in 2005:


					Total Number of		Maximum Number of
					Shares Purchased as		Shares that may yet
	Total Number of		Average Price Paid		Part of the Share		be Purchased under the
	Shares Purchased		per Share in €		Buyback Plan		Share Buyback Plan
2005	(a)		(b)		(c)		(d)

Jan. 1-31		28,532		67.70		—		36,324,871
Feb. 1-28		—		—		—		36,353,403
Mar. 1-31		1,880		65.20		—		36,353,403
Apr. 1-30		5,112		67.23		—		36,353,403
May 1-31		450,000		66.59		—		35,903,408
Jun. 1-30		132		71.41		—		35,903,408
Jul. 1-31		36,255		72.78		—		36,535,476
Aug. 1-31		13		78.30		—		36,535,476
Sep. 1-30		150,000		76.97		—		36,203,506
Oct. 1-31		—		—		—		36,203,506
Nov. 1-30		158,635		75.14		—		36,353,506
Dec. 1-31		—		—		—		36,353,552

Total		830,559		70.44		—


(a)	308,555 Ordinary Shares were purchased for the Company’s employee share purchase programs, 486,255 Ordinary Shares were purchased by E.ON Energie for the squeeze-out of Contigas minority shareholders, 35,736 Ordinary Shares were purchased in connection with claims made by certain former shareholders of Stinnes AG and 13 Ordinary Shares were purchased in connection with pre-existing conversion claims of certain former shareholders of Gelsenberg AG. All of these purchases were made in the market. In April 2005, E.ON started a squeeze-out proceeding for the remaining 1.13 percent of Contigas shares not held by E.ON at that time. Shareholders could have accepted a voluntary conversion offer of either €80 in cash for one Contigas share or €85 for each Contigas share paid in E.ON shares until June 27, 2005. 0.91 percent of shareholders accepted this offer; the remaining 0.22 percent were indemnified by means of a cash compensation agreed upon in the squeeze-out resolution. Any legal challenges were settled as of October 27, 2005. In February 2005, E.ON finalized an agreement with certain former shareholders of Stinnes AG in relation to share exchange claims (Spruchstellenverfahren) made at the time of Stinnes’ acquisition by VEBA AG. Claims with respect to the acquisition may still be made by additional former minority shareholders of Stinnes AG, and E.ON may purchase additional Ordinary Shares if and when such further claims are presented. Gelsenberg AG was merged into the former VEBA AG in 1978; its shareholders had the option to receive VEBA shares or cash against delivery of their Gelsenberg shares. In August 2005, some former Gelsenberg AG shareholders presented Gelsenberg AG shares requesting an aggregate of 13 E.ON Ordinary Shares.

(c)(d)	Pursuant to shareholder resolutions approved at the annual general meeting of shareholders held on April 27, 2005, the Board of Management is authorized to buy back up to 10 percent of E.ON AG’s outstanding share capital, or 692,000,000 Ordinary Shares, through October 27, 2006. Pursuant to the German Stock Corporation Act, the maximum number of shares the Company may purchase at any time equals 10 percent of 692,000,000 (or 69,200,000 Ordinary Shares) less the number of Ordinary Shares held in treasury stock at such time. Therefore, the maximum number of Ordinary Shares that may be purchased under the Company’s share buyback plan, as reflected in column D, fluctuated over the course of 2005 due to changes in the number of Ordinary Shares held in treasury stock, rather than due to share repurchases. The Company did not buy back any Ordinary Shares pursuant to this share buyback plan in 2005, as the shares purchased for the employee share purchase programs, the Contigas squeeze out and the Stinnes integration were not purchased pursuant to such plan.

For information about E.ON’s share repurchases in 2003 and 2004, see “Item 10. Additional Information — Memorandum and Articles of Association — Changes in Capital.”

208

PART III


Item 17.	Financial Statements.

Not applicable.


Item 18.	Financial Statements.

See pages F-1 to F-83, incorporated by reference.


Item 19.	Exhibits.


Exhibit No.		Exhibit Title

	1.1	English translation of the Articles of Association (Satzung) of E.ON AG as amended to date.*

	4.1	Unofficial English translation of Framework Agreement between RAG AG, RAG Beteiligungs-GmbH, RAG Projektgesellschaft mbH and EBV Aktiengesellschaft, and E.ON AG, Chemie Verwaltungs AG and E.ON Vermögensanlage GmbH, dated May 20, 2002.**

	4.2	Amended and Restated Fiscal Agency Agreement between E.ON AG, E.ON International Finance B.V., E.ON UK PLC, and Citibank, N.A. as Fiscal Agent, and Banque du Luxembourg S.A. and Citibank AG as Paying Agents, relating to the Euro 20,000,000,000 Medium Term Note Programme, dated August 21, 2002.**

	4.3	Sale and Purchase Agreement Regarding the Sale and Purchase of All Shares in Viterra AG between E.ON Viterra-Beteiligungsgesellschaft mbH, E.ON AG, Atrium Einhunderterste VV GmbH and Praetorium 40. VV GmbH, dated May 17, 2005.* †

	4.4	Unofficial English translation of Current Form of Management Board Service Agreement.***

	4.5	Schedule 1 to Exhibit 4.4 — Individual Deviations from Form of Management Board Service Agreement.***

	8.1	Subsidiaries as of the end of the year covered by this annual report: see “Item 4. Information on the Company — Organizational Structure.”

	12.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

	12.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

	13.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*


*	Filed herewith.

**	Incorporated by reference to the Form 20-F filed by E.ON AG with the Securities and Exchange Commission on March 19, 2003, file number 1-14688.

***	Incorporated by reference to the Form 20-F filed by E.ON AG with the Securities and Exchange Commission on March 10, 2005, file number 1-14688.


†	Confidential material appearing in this document has been omitted and filed separately with the Securities and Exchange Commission in accordance with the Securities Exchange Act of 1934, as amended, and Rule 24b-2 promulgated thereunder. Omitted information has been redacted and marked with an asterisk and appropriate legend to indicate redaction.

209

E.ON AG AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm		F-1
Consolidated Financial Statements:
	Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	F-2
	Consolidated Balance Sheets at December 31, 2005 and 2004	F-3
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-4
	Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003	F-5
	Notes to the Consolidated Financial Statements	F-6

F-i

(PAGE INTENTIONALLY LEFT BLANK)

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

E.ON AG:

We have audited the accompanying Consolidated Balance Sheets of E.ON AG and its subsidiaries (“E.ON”) as of December 31, 2005 and 2004, and the related Consolidated Statements of Income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of E.ON’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of E.ON at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the Consolidated Financial Statements, effective January 1, 2003, E.ON adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”


Düsseldorf	PricewaterhouseCoopers
March 8, 2006	Aktiengesellschaft
	Wirtschaftsprüfungsgesellschaft

	/s/ Dr. Vogelpoth	/s/ Laue

	Dr. Vogelpoth Wirtschaftsprüfer (German Public Auditor)	Laue Wirtschaftsprüfer (German Public Auditor)

F-1

E.ON AG AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except for per share amounts)


				Year Ended December 31,

		Note		2005*			2005			2004			2003

Public utility sales				$	47,353		€	39,987		€	34,307		€	31,771
Gas sales					21,214			17,914			13,227			11,919
Other sales					(1,779	)		(1,502	)		(792	)		419

Sales			(31)		66,788			56,399			46,742			44,109
Electricity and petroleum tax					(5,382	)		(4,545	)		(4,358	)		(3,886	)

Sales, net of electricity and petroleum tax					61,406			51,854			42,384			40,223

Cost of goods sold — Public utility					(33,946	)		(28,666	)		(23,190	)		(22,658	)
Cost of goods sold — Gas					(16,091	)		(13,588	)		(9,017	)		(8,060	)
Cost of goods sold and services provided — Other					1,737			1,467			766			(94	)

Cost of goods sold and services provided					(48,300	)		(40,787	)		(31,441	)		(30,812	)

Gross profit on sales					13,106			11,067			10,943			9,411
Selling expenses					(4,562	)		(3,852	)		(4,235	)		(4,418	)
General and administrative expenses					(1,809	)		(1,528	)		(1,350	)		(1,248	)
Other operating income (expenses), net			(5)		2,007			1,695			1,361			1,658
Financial earnings			(6)		(206	)		(174	)		(364	)		(238	)

Income/(Loss) from continuing operations before income taxes and minority interests					8,536			7,208			6,355			5,165
Income taxes			(7)		(2,695	)		(2,276	)		(1,850	)		(1,145	)

Income/(Loss) from continuing operations after income taxes					5,841			4,932			4,505			4,020
Minority interests			(8)		(655	)		(553	)		(478	)		(445	)

Income/(Loss) from continuing operations					5,186			4,379			4,027			3,575
Income/(Loss) from discontinued operations, net (less applicable income taxes of €(50), €97 and €31, respectively)			(4)		3,594			3,035			312			1,512

Income before cumulative effect of changes in accounting principles					8,780			7,414			4,339			5,087
Cumulative effect of changes in accounting principles, net (less applicable income taxes of €(3), €0 and €(261), respectively)					(9	)		(7	)		—			(440	)

Net income					8,771			7,407			4,339			4,647

Basic earnings per share:			(10)
	Income/(Loss) from continuing operations				7.87			6.64			6.13			5.47
	Income/(Loss) from discontinued operations, net				5.45			4.61			0.48			2.31
	Cumulative effect of changes in accounting principles, net				(0.01	)		(0.01	)		—			(0.67	)

	Net income				13.31			11.24			6.61			7.11

Diluted earnings per share:			(10)
	Income/(Loss) from continuing operations				7.87			6.64			6.13			5.47
	Income/(Loss) from discontinued operations, net				5.45			4.61			0.48			2.31
	Cumulative effect of changes in accounting principles, net				(0.01	)		(0.01	)		—			(0.67	)

	Net income				13.31			11.24			6.61			7.11


*	Note 1

The accompanying Notes are an integral part of these Consolidated Financial Statements.

F-2

E.ON AG AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions)


			December 31,

	Note		2005*		2005		2004

ASSETS
Goodwill			$	18,193	€	15,363	€	14,454
Intangible assets		(11a)		4,885		4,125		3,788
Property, plant and equipment		(11b)		48,935		41,323		43,563
Financial assets		(11c)		25,680		21,686		17,263

Fixed assets				97,693		82,497		79,068

Inventories		(12)		2,910		2,457		2,647
Financial receivables and other financial assets		(13)		2,391		2,019		2,124
Operating receivables and other operating assets		(13)		25,287		21,354		15,759
Assets of disposal groups		(4)		806		681		553
Investment in short-term securities		(14)		12,678		10,706		7,840
Cash and cash equivalents		(15)		5,226		4,413		4,176

Non-fixed assets				49,298		41,630		33,099

Deferred tax assets		(7)		2,462		2,079		1,551
Prepaid expenses		(16)		422		356		344

Total assets (thereof short-term 2005: €32,648; 2004: €25,839)				149,875		126,562		114,062


			December 31,

	Note		2005*			2005			2004

STOCKHOLDERS’ EQUITY AND LIABILITIES
Capital stock		(17)	$	2,130		€	1,799		€	1,799
Additional paid-in capital		(18)		13,913			11,749			11,746
Retained earnings		(19)		30,625			25,861			20,003
Accumulated other comprehensive income		(20)		6,313			5,331			268
Treasury stock				(303	)		(256	)		(256	)

Stockholders’ equity				52,678			44,484			33,560

Minority interests		(21)		5,606			4,734			4,144

Provisions for pensions		(22)		10,326			8,720			8,589
Other provisions		(23)		29,773			25,142			25,653

Accrued liabilities				40,099			33,862			34,242

Financial liabilities		(24)		17,008			14,362			20,301
Operating liabilities		(24)		22,561			19,052			14,054

Liabilities				39,569			33,414			34,355

Liabilities of disposal groups		(4)		984			831			54
Deferred tax liabilities		(7)		9,971			8,420			6,605
Deferred income		(16)		968			817			1,102

Total liabilities (thereof short-term 2005: €25,093; 2004: €23,734)				97,197			82,078			80,502

Total stockholders’ equity and liabilities				149,875			126,562			114,062


*	Note 1

The accompanying Notes are an integral part of these Consolidated Financial Statements.

F-3

E.ON AG AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


			Year Ended December 31,

			2005*			2005			2004			2003

Net income			$	8,771		€	7,407		€	4,339		€	4,647
Income applicable to minority interests				655			553			478			445
Adjustments to reconcile net income to net cash provided by operating activities:
	Income from discontinued operations			(3,594	)		(3,035	)		(312	)		(1,512	)
	Depreciation, amortization, impairment			3,633			3,068			3,051			3,018
	Changes in provisions			(434	)		(367	)		(574	)		1,868
	Changes in deferred taxes			468			395			58			(362	)
	Other non-cash income and expenses			(367	)		(310	)		25			(144	)
	(Gain)/ Loss on disposal:
		Equity investments		(52	)		(44	)		(397	)		(1,252	)
		Other financial assets		(4	)		(3	)		(34	)		1
		Intangible assets and Property, plant and equipment		(43	)		(36	)		(31	)		(96	)
	Changes in non-fixed assets and other operating liabilities:
		Inventories		(335	)		(283	)		(285	)		145
		Trade receivables		(1,782	)		(1,505	)		(210	)		184
		Other operating receivables		(4,560	)		(3,851	)		(2	)		456
		Trade payables		1,641			1,386			(113	)		(642	)
		Other operating liabilities		3,820			3,226			(153	)		(1,449	)

Cash provided by operating activities of continuing operations				7,817			6,601			5,840			5,307

Proceeds from disposal of:
	Equity investments			7,215			6,093			1,619			4,397
	Other financial assets			361			305			719			991
	Intangible assets and Property, plant and equipment			238			201			268			210
Purchase of:
	Equity investments			(1,166	)		(985	)		(2,203	)		(6,235	)
	Other financial assets			(429	)		(362	)		(294	)		(240	)
	Intangible assets and Property, plant and equipment			(3,541	)		(2,990	)		(2,612	)		(2,538	)
Changes in securities (other than trading) (> 3 months)				(567	)		(479	)		(385	)		430
Changes in financial receivables				(1,639	)		(1,384	)		2,506			2,757

Cash provided by (used for) investing activities of continuing operations				472			399			(382	)		(228	)

Payments received (made) from changes in capital including minority interests				(31	)		(26	)		3			(6	)
Payments received (made) for treasury stock, net				(39	)		(33	)		—			7
Payment of cash dividends to:
	Stockholders of E.ON AG			(1,834	)		(1,549	)		(1,312	)		(1,142	)
	Minority stockholders			(290	)		(245	)		(286	)		(477	)
Payments for financial liabilities				3,578			3,022			3,522			2,466
Repayments of financial liabilities				(9,040	)		(7,634	)		(6,693	)		(3,953	)

Cash used for financing activities of continuing operations				(7,656	)		(6,465	)		(4,766	)		(3,105	)

Net increase in cash and cash equivalents of continuing operations				633			535			692			1,974
Cash flows from discontinued operations (Revised, see Note 27)
Cash provided by operating activities of discontinued operations				67			57			132			231
Cash provided by (used for) investing activities of discontinued operations				(317	)		(268	)		(214	)		250
Cash provided by (used for) financing activities of discontinued operations				(194	)		(164	)		305			(440	)

Cash provided by (used for) discontinued operations				(444	)		(375	)		223			41

Effect of foreign exchange rates on cash and cash equivalents of continuing operations				92			77			(60	)		(36	)

Cash and cash equivalents at the beginning of the period				4,945			4,176			3,321			1,342

Cash and cash equivalents				5,226			4,413			4,176			3,321


*	Note 1

The accompanying Notes are an integral part of these Consolidated Financial Statements.

F-4

E.ON AG AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in millions of €)


								Accumulated other comprehensive income

			Additional					Currency			Available			Minimum
	Capital		paid-in		Retained			translation			for sale			pension			Cash flow			Treasury
	stock		capital		earnings			adjustments			securities			liability			hedges			stock			Total

January 1, 2003		1,799		11,402		13,472			(242	)		(3	)		(401	)		(115	)		(259	)		25,653
Shares reacquired/sold				162		(1	)														3			164
Dividends paid						(1,142	)																	(1,142	)
Net income						4,647																		4,647
Other comprehensive income									(779	)		1,187			(91	)		135						452
Total comprehensive income																								5,099

December 31, 2003		1,799		11,564		16,976			(1,021	)		1,184			(492	)		20			(256	)		29,774

Shares reacquired/sold				182																				182
Dividends paid						(1,312	)																	(1,312	)
Net income						4,339																		4,339
Other comprehensive income									125			994			(598	)		56						577
Total comprehensive income																								4,916

December 31, 2004		1,799		11,746		20,003			(896	)		2,178			(1,090	)		76			(256	)		33,560

Shares reacquired/sold				3																				3
Dividends paid						(1,549	)																	(1,549	)
Net income						7,407																		7,407
Other comprehensive income									620			4,698			(312	)		57						5,063
Total comprehensive income																								12,470

December 31, 2005		1,799		11,749		25,861			(276	)		6,876			(1,402	)		133			(256	)		44,484

The accompanying Notes are an integral part of these Consolidated Financial Statements.

F-5

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


(1)	Basis of Presentation

The Consolidated Financial Statements of E.ON AG and its consolidated companies (“E.ON,” the “E.ON Group” or the “Company”), Düsseldorf, Germany, have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).

The E.ON Group is an internationally active group of energy companies with integrated electricity and gas operations based in Germany. Effective January 1, 2004, the Group has been organized around five defined target markets:


	•	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 interests in companies of 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, (formerly: Sydkraft AB) and through E.ON Finland Oyj (“E.ON Finland”), Espoo, Finland, primarily in Sweden and Finland. For additional information about E.ON Finland, please see Note 33.

	•	The U.S. Midwest market unit, led by E.ON U.S. LLC (“E.ON U.S.”), Louisville, Kentucky, U.S., (formerly: LG&E Energy LLC) is primarily active in the regulated energy market in the U.S. state of Kentucky.

The Corporate Center contains those interests held directly by E.ON AG that are not allocated to a particular segment, as well as E.ON AG itself.

These market units form the core energy business and are at the same time segments as defined in SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”). The Corporate Center as part of the core energy business also contains the consolidation effects that take place at the Group level.

The other activities of the E.ON Group include the activities of Degussa AG (“Degussa”), Düsseldorf, Germany, which is accounted for under the equity method. In addition, the 2004 balance-sheet data reported by segment still include Viterra AG (“Viterra”), Essen, Germany, as part of other activities in 2004.

Note 31 provides additional information about the market units.

Pursuant to Article 57 Sentence 1 No. 2 of the Introductory Law to the German Commercial Code (“EGHGB”), E.ON is exempted from the requirement to prepare consolidated financial statements in accordance with the International Financial Reporting Standards (“IFRS”) and a management report in accordance with Article 315a of the German Commercial Code (“HGB”) for the 2005 fiscal year. E.ON is preparing consolidated financial statements and a management report in accordance with internationally accepted accounting standards (U.S. GAAP), as provided for by Article 292a HGB, in combination with Article 58 (5) Sentence 2 EGHGB. For an assessment of the conformity of U.S. GAAP regulations with the Fourth and Seventh EU Accounting Directives, E.ON refers to German Accounting Standard (“DRS”) No. 1, “Exempting Consolidated Financial Statements in accordance with Article 292a HGB,” and DRS No. 1a, “Exempting Consolidated Financial Statements in accordance with Article 292a HGB — U.S. GAAP Consolidated Financial Statements: Goodwill and Other Intangible Assets,” as well as to the transitional regulations of German Accounting Amendment Standard (“DRÄS”) No. 2, Article 2.

F-6

Solely for the convenience of the reader, the December 31, 2005, financial statements (except the changes in stockholders’ equity) have also been translated into United States dollars (“$”) at the rate of €1 = $1.1842, the Noon Buying Rate of the Federal Reserve Bank of New York on December 30, 2005. Such translation is unaudited.


(2)	Summary of Significant Accounting Policies

Principles of Consolidation

The Consolidated Financial Statements include the accounts of E.ON AG and its consolidated subsidiaries. The subsidiaries, associated companies and other related companies have been included in the Consolidated Financial Statements in accordance with the following criteria:


	•	Majority-owned subsidiaries in which E.ON directly or indirectly exercises control through a majority of the stockholders’ voting rights (“affiliated companies”) are fully consolidated. Furthermore, 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”), requires E.ON to consolidate so-called variable interest entities in which it is the primary beneficiary for economic purposes, even if it does not have a controlling interest.

	•	Majority-owned companies in which E.ON does not exercise management control due to restrictions in the control of assets and management (“unconsolidated affiliates”) are generally accounted for under the equity method. Companies in which E.ON has the ability to exercise significant influence in the investees’ operations (“associated companies”) are also accounted for under the equity method. These are mainly companies in which E.ON holds an interest of between 20 and 50 percent.

	•	All other share investments are accounted for under the cost method or, if they are marketable, at fair value.

A list of all E.ON stockholdings and other interests is filed in the Commercial Register of the Düsseldorf District Court, HRB 22315.

Intercompany results, sales, expenses and income, as well as receivables and liabilities between the consolidated companies are eliminated. If companies are accounted for under the equity method, intercompany results are eliminated in the consolidation process if and to the extent that these are material.

Business Combinations

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” (“SFAS 141”), all business combinations are accounted for under the purchase method of accounting, whereby all assets acquired and liabilities assumed are recorded at their fair value. After adjustments to the fair values of assets acquired and liabilities assumed are made, any resulting positive differences are capitalized in the balance sheet as goodwill. Situations in which the fair value of net assets acquired is greater than the purchase price paid result in an excess that is allocated as a pro-rata reduction of the balance sheet amounts. Should any such excess remain after reducing the amounts that otherwise would have been assigned to those assets, the remaining excess is recognized as a separate gain. Goodwill arising in companies for which the equity method is applied is calculated on the basis of the same principles that are applicable to fully consolidated companies.

Foreign Currency Translation

The Company’s transactions denominated in currencies other than the euro are translated at the current exchange rate at the time of the transaction and 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 to hedge the value of its net investments in its foreign operations are recorded with no effect on net income as a component of stockholders’ equity.

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The assets and liabilities of the Company’s foreign subsidiaries with a functional currency other than the euro are translated using year-end exchange rates, while the statements of income are translated using annual-average exchange rates. Significant transactions of foreign subsidiaries occurring during the fiscal year are included 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 stockholders’ equity and accordingly have no effect on net income.

The following chart depicts the movements in exchange rates for the periods indicated for major currencies of countries outside the European Monetary Union (1):


			€1, rate as of				€1, annual
			December 31,				average rate

	ISO code		2005		2004		2005		2004		2003

British pound		GBP		0.69		0.71		0.68		0.68		0.69
Norwegian krone		NOK		7.99		8.24		8.01		8.37		8.00
Swedish krona		SEK		9.39		9.02		9.28		9.12		9.12
U.S. dollar		USD		1.18		1.36		1.24		1.24		1.13


(1)	The countries within the European Monetary Union are Austria, Belgium, Finland, France, Germany, Greece, Ireland, Italy, Luxembourg, The Netherlands, Portugal and Spain.

Presentation of Sales and Cost of Goods Sold and Services Provided

“Public utility sales” and “Cost of goods sold — Public utility” are shown separately in the Consolidated Statements of Income and include the total sales and cost of goods sold of the reportable segments Central Europe, U.K., Nordic and U.S. Midwest.

“Gas sales” and “Cost of goods sold — Gas” reflect the supply, transmission, storage and sale of natural gas from the reportable segment Pan-European Gas.

“Other sales” and “Cost of goods sold and services provided — Other” are presented in the Consolidated Statements of Income and primarily include consolidation effects at the Group level, as well as the activities of Degussa in 2003.

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. The following is a description of E.ON’s major revenue recognition policies in the various segments.

Core Energy Business

Sales in the Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest market units result mainly 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 deliveries of steam and heat.

Revenue from the sale of electricity and gas to industrial and commercial customers and to retail customers is recognized when earned on the basis of a contractual arrangement with the customer; it reflects 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 year-end.

Gains and losses on derivative financial instruments used for proprietary trading are presented net in the Consolidated Statement of Income.

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Other Activities

Sales at Viterra, which is focused on the business of residential real estate and on the growing business of real estate development, are recognized net of discounts, sales incentives, customer bonuses and rebates granted when risk is transferred, remuneration is contractually fixed or determinable and satisfaction of the associated claims is probable. Viterra also performs services under long-term contractual commitments (in particular property leases and service contracts); revenue from such sales is recognized according to the terms of the contracts or at the point when the relevant services have been rendered. Due to the sale of Viterra and its consequent classification as a discontinued operation, the net income from operations of Viterra and the gains from the sale are both reported under “Income/(Loss) from discontinued operations, net” in the accompanying Consolidated Statements of Income, with the prior-year figures adjusted accordingly. Please see Note 4 for further details.

Electricity Tax

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.

Petroleum Tax

The petroleum tax in Germany also includes the natural gas tax. This tax becomes due at the time of procurement or removal of the natural gas from storage facilities. The tax is calculated on the basis of the specified quantities of natural gas.

Taxes other than Income Taxes

Taxes other than income taxes totaled €57 million in 2005 (2004: €78 million; 2003: €102 million) and consisted principally of property tax and real estate transfer tax in all periods presented.

Cost of Goods Sold and Services Provided

Cost of goods sold and services provided primarily includes the cost of generation, procured electricity and gas, the cost of raw materials and supplies used to produce energy, depreciation of the equipment used to generate, store and transfer electricity and gas, personnel costs directly related to the generation and supply of energy, as well as costs incurred in the purchase of production-related services.

Selling Expenses

Selling expenses include all expenses incurred in connection with the sale of energy. These primarily include personnel costs and other sales-related expenses of the regional utilities in the Central Europe market unit.

Administrative Expenses

Administrative expenses primarily include the personnel costs for those employees not connected with production and sales, as well as the depreciation of administration buildings.

Accounting for Sales of Stock of Subsidiaries or Associated Companies

If a subsidiary or associated company sells its stock to a third party, leading to a reduction in E.ON’s ownership share of the relevant company (“dilution”), in accordance with “SEC Staff Accounting Bulletin” (“SAB”) 51, “Accounting for Sales of Stock of a Subsidiary” (“SAB 51”), gains and losses from these dilutive transactions are included in the income statement under “Other operating income (expenses), net.”

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Advertising Costs

Advertising costs are expensed as incurred and totaled €156 million in 2005 (2004: €130 million; 2003: €130 million).

Research and Development Costs

Research and development costs are expensed as incurred, and recorded as other operating expenses. They totaled €24 million in 2005 (2004: €19 million; 2003: €36 million).

Earnings per Share

Earnings per share (“EPS”) are computed in accordance with SFAS No. 128, “Earnings per Share” (“SFAS 128”). Basic (undiluted) EPS are computed by dividing consolidated net income by the weighted average number of ordinary shares outstanding during the relevant period. The computation of diluted EPS is identical to that for basic EPS, as E.ON AG does not have any dilutive securities.

Goodwill and Other Intangible Assets

Goodwill

SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), requires that goodwill not be periodically amortized, but rather be tested for impairment at the reporting unit level on an annual basis. Goodwill must be evaluated for impairment between these annual tests if events or changes in circumstances indicate that goodwill might be impaired. The Company has identified its reporting units as the operating units one level below its reportable segments.

The testing of goodwill for impairment involves two steps:


	•	The first step is to compare each reporting unit’s fair value with its carrying amount including goodwill. If a reporting unit’s carrying amount exceeds its fair value, this indicates that its goodwill may be impaired and the second step is required.

	•	The second step is to compare the implied fair value of the reporting unit’s goodwill with the carrying amount of its goodwill. The implied fair value is computed by allocating the reporting unit’s fair value to all of its assets and liabilities in a manner that is similar to a purchase price allocation in a business combination in accordance with SFAS 141. The remainder after this allocation is the implied fair value of the reporting unit’s goodwill. If this fair value of goodwill is less than its carrying value, the difference is recorded as an impairment.

The annual testing of goodwill for impairment at the reporting unit level, as required by SFAS 142, is carried out in the fourth quarter of each year.

Intangible Assets Not Subject to Amortization

SFAS 142 also requires that intangible assets other than goodwill be amortized over their useful lives unless their lives are considered to be indefinite. Any intangible asset that is not subject to amortization must be tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. This impairment test for intangible assets with indefinite lives consists of a comparison of the fair value of the asset with its carrying value. Should the carrying value exceed the fair value, an impairment loss equal to the difference is recognized in other operating expenses.

Intangible Assets Subject to Amortization

Intangible assets subject to amortization are classified into marketing-related, customer-related, contract-based, and technology-based, all of which are valued 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.

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Accounting for internally-developed software for internal use within the Company is governed by the guidelines of the American Institute of Certified Public Accountants (“AICPA”) Statement of Position (“SOP”) 98-1, “Accounting for the Costs of Computer Software Developed or Obtained for Internal Use.” In accordance with this SOP, any costs incurred from the moment at which the decision on the implementation and all functions, characteristics and specifications of the software was made, are capitalized and amortized over the probable useful life. Any costs incurred up to that point are immediately expensed.

Expenditures for natural gas exploration and development by the companies active in the oil and gas sectors are accounted for under the successful efforts method according to SFAS 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”). Under this method, the costs of exploratory drilling (both productive wells and dry holes) are initially capitalized as an intangible asset. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to tangible production assets. Both tangible and intangible assets are capitalized and amortized on the unit of production basis. All exploration expenditure determined to be unsuccessful is charged against income. Other capitalized costs are also written down once it has been established that no viable reserves can be determined. Other expenses for geological and geophysical work (seismology) and license acquisition costs are immediately charged against income.

Intangible assets with definite lives subject to amortization are reviewed for impairment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

Please see Note 11(a) for additional information about goodwill and intangible assets.

Property, Plant and Equipment

Property, plant and equipment are valued at historical or production costs, including asset retirement costs to be capitalized and depreciated over their expected useful lives, as summarized in the following table.


Buildings		10 to 50 years
Power plants
	Conventional components	10 to 60 years
	Nuclear components	up to 25 years
Hydro power plants and other facilities used to generate renewable energy		10 to 50 years
Equipment, fixtures, furniture and office equipment		3 to 25 years
Technical equipment for storage, distribution and transmission		15 to 65 years

Property, plant and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment is recognized in accordance with SFAS 144 when such a long-lived asset’s carrying amount exceeds its fair value. In such cases, the carrying value of such an impaired asset is written down to its fair value. If necessary, the remaining useful life of the asset is correspondingly revised.

Interest on debt apportioned to the construction period of qualifying assets is capitalized as a part of their cost of acquisition or construction. The additional cost is depreciated over the expected useful life of the related asset, commencing on the completion or commissioning date.

Repair and maintenance costs are expensed as incurred.

Leasing

Leasing transactions are classified according to the lease agreements which specify the benefits and risks associated with the leased property. E.ON concludes some agreements in which it is the lessor and other agreements in which it is the lessee.

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Leasing transactions in which E.ON is the lessee are differentiated into capital leases and operating leases. In a capital lease, the Company receives the economic benefit of the leased property and recognizes the asset and associated liability on its balance sheet. All other transactions in which E.ON is the lessee are classified as operating leases. Payments made under operating leases are recorded as an expense.

Leasing transactions in which E.ON is the lessor and the lessee enjoys substantially all the benefits and bears the risks of the leased property are classified as sales-type leases or direct financing leases. In these two types of leases, E.ON records the present value of the minimum lease payments as a receivable. The lessee’s payments to E.ON are allocated between a reduction of the lease obligation and interest income. All other transactions in which E.ON is the lessor are categorized as operating leases. E.ON records the leased property as an asset and the scheduled lease payments as income.

Financial Assets

Shares in associated companies are generally accounted for under the equity method. E.ON’s accounting policies are also generally applied to its associated companies. Other share investments and debt securities that are marketable are valued in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS 115”). SFAS 115 requires that a security be accounted for according to its classification as trading, available-for-sale or held-to-maturity. Debt securities that the Company does not have the positive intent and ability to hold to maturity, as well as all marketable securities, are classified as available-for-sale securities. The Company does not hold any securities classified as trading or held-to-maturity.

Securities classified as available-for-sale are carried at fair value, with unrealized gains and losses net of related deferred taxes reported as a separate component of stockholders’ equity until realized. Realized gains and losses are recorded based on the specific identification method. Unrealized losses on all marketable securities and investments that are other than temporary are recognized in financial earnings in the line item “Write-down of financial assets and long-term loans.”

The residual value of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is included in net interest income. Realized gains and losses on such securities are respectively included in “Other operating income (expenses), net.” Other share investments that are non-marketable are accounted for at acquisition cost.

Inventories

The Company values inventories at the lower of acquisition or production cost or market value. Raw materials, products and goods purchased for resale are primarily valued at average cost. Gas inventories are generally valued at LIFO. The specific identification method is primarily used for real estate inventories. In addition to production materials and wages, production costs include material and production overheads based on normal capacity. Interest on borrowings is capitalized if the production activities are performed over an extended period (“qualifying assets”). The costs of general administration, voluntary social benefits and pensions are not capitalized. Inventory risks resulting from excess and obsolescence are provided for by appropriate valuation allowances.

Receivables and Other Assets

Receivables and other assets are recorded at their nominal values. Valuation allowances are provided for identified individual risks for these line items, as well as for long-term loans. If the loss of a certain part of the receivables is probable, valuation allowances are provided to cover the expected loss.

Emission Rights

Emission rights held under national and international emission-rights systems are reported as inventory. Emission rights are capitalized at their acquisition costs when issued for the respective reporting period as (partial) fulfillment of the multi-year notice of allocation from the responsible national authorities. Emission rights are subsequently valued at amortized cost. The consumption of emission rights is valued at average cost.

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Any shortfall in emission rights is accrued throughout the year within other provisions. The expenses incurred for the consumption of emission rights and the recognition of a corresponding provision are reported under “Cost of goods sold.”

As part of operating activities, emission rights are also held for proprietary trading purposes. Emission rights held for proprietary trading are reported under “Operating receivables and other operating assets.”

Discontinued Operations and Assets Held for Sale

Discontinued operations are those operations of a reportable or operating segment, or of a component thereof, that either have been disposed of or are classified as held for sale. Assets and liabilities attributable to a component must be clearly distinguishable from the other consolidated entities in terms of their operations and cash flows. In addition, the reporting entity must not have any significant continuing involvement in the operations classified as a discontinued operation.

Also reported under assets and liabilities of discontinued operations are groups of long-lived assets held for disposal in one single transaction together with other assets and liabilities (“disposal groups”). SFAS 144 requires that certain defined criteria be met for an entity to be classified as a disposal group, and specifies the conditions under which a planned transaction becomes reportable separately as a discontinued operation.

Gains or losses from the disposal and income and expenses from the operations of a discontinued operation are reported under “Income/ (Loss) from discontinued operations, net”; prior-year income statement figures are adjusted accordingly. Cash flows of discontinued operations are not included in the Consolidated Statement of Cash Flows. However, there is no reclassification of prior-year balance sheet line items attributable to discontinued operations, as such reclassification is not required by SFAS 144.

The income and expenses related to operations that will be disposed of but are not classified as discontinued operations are included in “Income/ (Loss) from continuing operations” until they are sold.

Individual assets and disposal groups identified as held for sale are no longer depreciated once they are classified as assets held for sale or as disposal groups. Instead, they are reported at the lower of their book value or their fair value. If the fair value of such assets, less selling costs, is less than the carrying value of the assets at the time of their classification as held for sale, an impairment is recognized immediately. The fair value is determined based on discounted cash flows. The underlying interest rate that management deems reasonable for the calculation of such discounted cash flows is contingent on the type of property and prevailing market conditions. Appraisals and, if appropriate, current estimated net sales proceeds from pending offers, are also considered.

Investments in Short-Term Securities

Deposits at banking institutions and available-for-sale securities that management does not intend to hold long-term with original maturities greater than three months are classified as investments in short-term securities. Unrealized gains and losses in these investments are reported net of related deferred taxes as a separate component of stockholders’ equity. Realized gains and losses, as well as unrealized losses that are other than temporary, are recognized in “Other operating income (expenses), net.”

Cash and Cash Equivalents

Cash and cash equivalents with an original maturity of three months or less include checks, cash on hand, balances in Bundesbank accounts and at other banking institutions. Included herein are also securities with an original maturity of three months or less.

Stock-Based Compensation

Stock-based compensation plans are accounted for on the basis of their intrinsic values, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), in combination with FIN 28,

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“Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans” (“FIN 28”). The corresponding expense is recognized in the income statement.

U.S. Regulatory Assets and Liabilities

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 with 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 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 U.S. Midwest market unit currently receives interest on all regulatory assets except for certain assets that have separate rate mechanisms providing for recovery within twelve months. Additionally, no interest is earned on the asset retirement obligation (“ARO”) regulatory asset. This regulatory asset will be offset against the associated regulatory liability, ARO asset and ARO liability at the time the underlying asset is retired.

U.S. regulatory assets and provisions are included in “Operating receivables and other operating assets” and “Other provisions,” respectively.

Provisions for Pensions

The valuation of pension liabilities is based on actuarial computations using the projected unit credit method in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS 87”), and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”). The interpretation of the Emerging Issues Task Force (“EITF”) Issue 03-4, “Determining the Classification and Benefit Attribution Method for a ‘Cash Balance’ Pension Plan” (“EITF 03-4”), has been adopted for pension plans of the type described therein. The expanded disclosure requirements outlined in SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“SFAS 132R”), were followed by E.ON for all domestic and foreign pension plans.

Other Provisions and Liabilities

Other provisions and liabilities are recorded when an obligation to a third party has been incurred, the payment is probable and the amount can be reasonably estimated.

SFAS 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), requires that the fair value of a liability arising from the retirement or disposal of an asset be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. When the liability is recorded, the Company must capitalize the costs of the liability by increasing the carrying amount of the long-lived asset. In subsequent periods, the liability is accreted to its present value and the carrying amount of the asset is depreciated over its useful life. Provisions for nuclear decommissioning costs are based on external studies and are continuously updated. Other provisions for the retirement or decommissioning of property, plant and equipment are based on estimates of the amount needed to fulfill the obligations.

Changes to these estimates arise pursuant to SFAS 143 particularly when there are deviations from original cost estimates or changes to the payment schedule or the level of relevant obligation. The liability must be adjusted in the case of both negative and positive changes to estimates (i.e. when the liability is less or greater than the accreted prior-year liability less utilization). Such an adjustment is usually effected through a corresponding adjustment to fixed assets and is not recognized in income. Provisions for liabilities are accreted annually at the same interest rate that was used to establish fair value. The interest rate for existing liabilities will not be changed in future years. For new liabilities, as well as for increases in fair value due to changes in

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estimates that are treated like new liabilities, the interest rate to be used for subsequent valuations will be the interest rate that was valid at the time the new liability was incurred or the change in estimate occurred.

The Company’s initial application of SFAS 143 on January 1, 2003, resulted in an increase of €1,370 million in the existing provisions from the retirement or decommissioning of fixed assets. Net book values of long-lived assets were increased by €262 million through capitalization of asset retirement costs. Also posted were receivables in the amount of €360 million from the Swedish national fund for nuclear waste management (see Note 13) and in the amount of €14 million for a U.S. regulatory asset. A net effect of €448 million after deferred taxes (€734 million before deferred taxes) arising from the adoption of SFAS 143 was reported in the Consolidated Statement of Income as a “Cumulative effect of changes in accounting principle, net.” Interest resulting from the accretion of asset retirement obligations in the amount of €486 million for 2003 is shown in financial earnings.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an Interpretation of FASB Statement No. 143” (“FIN 47”), clarifies that SFAS 143 also applies to asset retirement obligations even though uncertainty exists about the timing and/or method of settlement. A liability must be recognized for an obligation if its fair value can be reasonably estimated. For the E.ON Group, the adoption of FIN 47 resulted in a charge against earnings of €7 million after taxes (€10 million before taxes). The net book values of long-lived assets increased by €13 million through the adoption of FIN 47, U.S. regulatory assets increased by €13 million, and additional provisions of €36 million were recognized.

FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”), requires the guarantor to recognize a liability for the fair value of an obligation assumed under certain guarantees. It also expands the scope of the disclosures made concerning such guarantees. Note 25 contains additional information on significant guarantees that have been entered into by E.ON.

Deferred Taxes

Under SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), deferred taxes are recognized for all temporary differences between the applicable tax balance sheets and the Consolidated Balance Sheet. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. SFAS 109 also requires the recognition of the future tax benefits of net operating loss carryforwards. A valuation allowance is established when the deferred tax assets are not expected to be realized within a reasonable period of time.

Deferred tax assets and liabilities are measured using the 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 a change in tax rates is recognized in income for the period that includes the enactment date. The deferred taxes for German companies during the reporting year were generally calculated using a tax rate of 39 percent (2004: 39 percent; 2003: 39 percent) on the basis of a federal statutory rate of 25 percent for corporate income tax, a solidarity surcharge of 5.5 percent on corporate tax, and the average trade tax rate applicable for E.ON. Because of the enactment in Germany of the Flood Victims Solidarity Act of 2002, (“Flutopfersolidaritätsgesetz”) the German corporate tax rate was raised from 25 percent to 26.5 percent for 2003 only. The higher tax rate was thus applied to all temporary differences that were in effect in 2003. Foreign subsidiaries use applicable national tax rates.

Note 7 shows the major temporary differences so recorded.

Derivative Instruments and Hedging Activities

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 — an amendment of FASB Statement No. 133” (“SFAS 137”), and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment

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of FASB Statement No. 133” (“SFAS 138”), as well as the interpretations of the Derivatives Implementation Group (“DIG”), are applied as amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“SFAS 149”). SFAS 133 contains accounting and reporting standards for hedge accounting and for derivative financial instruments, including certain derivative financial instruments embedded in other contracts.

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

SFAS 133 requires that all derivatives be recognized as either assets or liabilities in the Consolidated Balance Sheet and measured at fair value. Depending on the documented designation of a derivative instrument, any change in fair value is recognized either in net income, or in stockholders’ equity as a component of “Accumulated other comprehensive income” (“OCI”).

SFAS 133 prescribes requirements for designation and documentation of hedging relationships and ongoing retrospective and prospective assessments of effectiveness in order to qualify for hedge accounting. The Company does not exclude any component of derivative gains and losses from the assessment 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 recorded in income. If a derivative instrument qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is reported in stockholders’ equity (as a component of “Accumulated other comprehensive income”) and is reclassified into earnings in the period or periods during which the transaction being hedged affects earnings. For hedging instruments used to establish cash flow hedges, the change in fair value of the ineffective portion is recorded in current earnings. 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 recorded in the cumulative translation adjustment within stockholders’ equity as a currency translation adjustment in “Accumulated other comprehensive income.”

Fair values of derivative instruments are classified as operating assets or liabilities. Changes in fair value of derivative instruments affecting income are classified as other operating income or expenses. Realized gains and losses of derivative instruments relating to sales of the Company’s products are principally recognized in sales or cost of goods sold. Gains and losses from interest-rate derivatives are displayed within interest income.

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 net income systematically over the term of the derivative. An exception to the accrual relates to unrealized gains and losses from the initial measurement that are verified by quoted market prices in an active market, observable prices of other current market transactions or other observable data supporting the valuation technique. In this case, the result of the initial measurement is recognized in income.

Please see Note 28 for additional information regarding the Company’s use of derivative instruments.

Consolidated Statement of Cash Flows

The Consolidated Statement of Cash Flows is classified by operating, investing and financing activities pursuant to SFAS No. 95, “Statement of Cash Flows” (“SFAS 95”). Cash flows from and to discontinued operations are stated separately in the Consolidated Statement of Cash Flows; prior-year figures are adjusted accordingly. The separate line item, “Other non-cash income and expenses,” mainly comprises undistributed income from companies valued at equity. Effects of changes in the scope of consolidation are shown in investing

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activities, but have been eliminated from operating and financing activities. This also applies to valuation changes due to exchange rate fluctuations, whose impact on cash and cash equivalents is separately disclosed.

Segment Information

The Company’s segment reporting is prepared in accordance with SFAS 131. The management approach required by SFAS 131 designates that the internal reporting organization that is used by management for making operating decisions and assessing performance should be used as the source for presenting the Company’s reportable segments (see Note 31).

Use of Estimates

The preparation of the Consolidated Financial Statements requires management to make estimates and assumptions that may affect the reported amounts of assets and liabilities and disclosure of contingent amounts as of the balance-sheet date and reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications to the prior years’ presentation are made to conform with the current-year presentation.

New Accounting Pronouncements

In December 2004, the FASB published a revised version of SFAS 123, “Share-Based Payment” (“SFAS 123R”). For E.ON, this means that in the future, liabilities resulting from the Company’s stock-based employee compensation program will have to be reported at their fair value, rather than on the basis of the previously applicable intrinsic value. The corresponding expense is recognized in the income statement. A new SEC regulation caused the initial adoption of SFAS 123R to be postponed to fiscal years beginning after June 15, 2005.

In May 2005, the FASB published SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS 154”), a new standard for reporting voluntary changes in accounting principles, accounting changes mandated by accounting pronouncements that do not specify transition provisions and corrections of accounting errors. According to this standard, accounting changes shall henceforth be retrospective, meaning that all prior-year financial statements have to be adjusted unless such adjustment is impracticable. Changes in depreciation, amortization or depletion method for long-lived, nonfinancial assets, however, shall be accounted for prospectively. The application of the standard is mandatory for fiscal years beginning after December 15, 2005.

No significant effects on E.ON’s assets, financial condition and results are expected to result from the initial adoption of these two standards.

In February 2006, the FASB published SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). This standard permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. SFAS 155 also clarifies the treatment of embedded derivatives in connection with certain securitized financial assets and with respect to the concentration of credit risks. In addition, it lifts the restrictions on the use of derivative financial instruments in connection with special-purpose entities that had been provided for in SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (“SFAS 140”). The adoption of SFAS 155 is mandatory for fiscal years that begin after September 15, 2006.

E.ON is currently evaluating the effects arising from the adoption of SFAS 155.

F-17


(3)	Scope of Consolidation

The number of consolidated companies changed as follows during the reporting year:


	Domestic			Foreign			Total

Consolidated companies as of December 31, 2004		197			469			666
Additions		8			49			57
Disposals/ Mergers		(77	)		(139	)		(216	)

Consolidated companies as of December 31, 2005		128			379			507

The disposals relate primarily to the sale of Viterra, which involved the disposal of 42 companies, and that of Ruhrgas Industries GmbH (“Ruhrgas Industries”), Essen, Germany, in which 53 companies were disposed of.

The variable interest entities consolidated within the E.ON Group as of December 31, 2005, are two real estate leasing companies, two jointly managed electricity generation companies and one company managing investments. Following the termination in August 2005 of all contractual relationships with one other variable interest entity for the management and disposal of real estate, which is now presented as a discontinued operation, FIN 46R no longer applies to this company.

As of December 31, 2005, the variable interest entities included in the E.ON Group had total assets of €795 million (2004: €1,109 million) and recorded earnings of €17 million (2004: €91 million; 2003: €(25)) before consolidation. As of December 31, 2004, total assets of €344 million and earnings of €76 million before consolidation were reported for the variable interest entity disposed of during 2005. Fixed assets and other assets in the amount of €127 million serve as collateral for liabilities relating to financial leases and bank loans.

The recourse of creditors of the consolidated variable interest entities to the assets of the primary beneficiaries is generally limited. Two variable interest entities have no such limitation of recourse. The primary beneficiary is liable for €82 million in respect of these two entities.

In addition, the Company has had contractual relationships with another leasing company in the energy sector since July 1, 2000. The Company is not the primary beneficiary of this variable interest entity. The entity is currently in liquidation pursuant to a shareholder resolution. As of the end of the 2004 fiscal year (the most recent fiscal year for which data is available), the entity had total assets of €120 million and recorded earnings for 2004 of €29 million. The E.ON Group’s maximum exposure to loss related to its association with this variable interest entity is approximately €15 million. Neither the relationship to this entity nor its liquidation is expected to result in a realization of losses.

The extent of E.ON’s interest in another variable interest entity, which has been in existence since 2001 and was expected to terminate in the fourth quarter of 2005, still cannot be assessed in accordance with the FIN 46R criteria due to insufficient information. The significant transactions between this entity and the E.ON Group took place in the fourth quarter of 2005. However, the entity’s liquidation remains outstanding. The entity handled the liquidation of assets from operations that had already been sold. Originally, its total assets amounted to €127 million. The relationship with this entity is not expected to result in any significant effects on earnings.

In 2005, a total of 127 domestic and 63 foreign companies were accounted for at equity (2004: 134 domestic and 78 foreign).

See Note 4 for additional information on acquisitions, disposals, discontinued operations and disposal groups.


(4)	Acquisitions, Disposals, Discontinued Operations and Disposal Groups

The presentation of E.ON’s acquisitions, disposals, discontinued operations and disposal groups in this Note is based on SFAS 141 and 144. Pursuant to SFAS 141, acquisitions are classified as either “significant” or “other.” For significant transactions, additional information is provided. In 2005, no acquisition was classified as significant under these guidelines. Additional information is provided for significant acquisitions in 2004 and 2003.

F-18

In general, information regarding multi-step acquisitions occurring over different reporting periods is provided in the year the most recent step has taken place. Details regarding disposals and discontinued operations are generally provided in the reporting period when the most significant portion of the overall transaction has taken place.

All acquisitions and disposals are in principle consistent with E.ON’s strategy for growth, which is to focus on its activities in the electricity and gas sectors.

Acquisitions in 2005

Central Europe


	Gorna Oryahovitza/ Varna

In February 2005, E.ON Energie acquired 67.0 percent stakes in each of the regional utilities Elektrorazpredelenie Gorna Oryahovitza AD (“Gorna Oryahovitza”), Gorna Oryahovitza, Bulgaria, and Elektrorazpredelenie Varna AD (“Varna”), Varna, Bulgaria. The aggregate purchase price of approximately €138 million was paid in 2004 in accordance with the contract and reported under “Financial receivables and other financial assets.” Goodwill of €16 million resulted from the purchase price allocation. The companies were fully consolidated as of March 1, 2005.


	ETE

In July 2005, E.ON Energie transferred its 51.0 percent interest (49.0 percent voting interest) in Gasversorgung Thüringen GmbH (“GVT”), Erfurt, Germany, and its 72.7 percent interest in Thüringer Energie AG (“TEAG”), Erfurt, Germany, to Thüringer Energie Beteiligungsgesellschaft mbH (“TEB”), Munich, Germany. Municipal shareholders also transferred interests in GVT totaling 43.9 percent to TEB. GVT was then merged into TEAG, and the merged entity was renamed E.ON Thüringer Energie AG (“ETE”), Erfurt, Germany. Following the reorganization, E.ON Energie holds an 81.5 percent interest in TEB and TEB holds a 76.8 percent interest in ETE.

The consolidation of GVT as of July 1, 2005, undertaken at an acquisition cost of €168 million, led to goodwill of €58 million as a result of the purchase price allocation. The transfer of the stake in TEAG resulted in a gain of €90 million, which is included under other operating income.


	NRE

In September 2005, E.ON Energie completed the acquisition of 100 percent of the Dutch electric and gas utility NRE Energie b.v. (“NRE”), Eindhoven, The Netherlands. The purchase price amounted to €79 million, with €46 million in goodwill resulting from the preliminary purchase price allocation. NRE was fully consolidated as of September 1, 2005.


	E.ON Moldova

In September 2005, E.ON Energie acquired a 24.6 percent stake in the regional utility Electrica Moldova S.A. (“Moldova”), Bacau, Romania — now 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. The purchase price for the 51.0 percent amounted to €101 million, with no goodwill resulting from the preliminary purchase price allocation. E.ON Moldova was fully consolidated as of September 30, 2005.

Pan-European Gas

Distrigaz

Following approval by the relevant authorities, E.ON Ruhrgas purchased a 30.0 percent interest in the gas utility S.C. Distrigaz Nord S.A. (“Distrigaz”), Târgu Mures, Romania, from the Romanian government for €127 million in June 2005. Following a simultaneous increase in capital by €178 million, this holding increased

F-19

to 51.0 percent. The company was fully consolidated as of June 30, 2005. Goodwill amounting to €56 million resulted from the preliminary purchase price allocation.

Caledonia

E.ON Ruhrgas in November 2005 bought the British gas exploration company Caledonia Oil and Gas Limited (“Caledonia”), London, U.K., which has a stake in 15 gas fields in the British part of the southern North Sea. The purchase price for the 100 percent interest in Caledonia amounted to €602 million and was primarily paid through the issuance of loan notes. The company was fully consolidated as of November 1, 2005. Total goodwill in the amount of €349 million resulted from the preliminary purchase price allocation. The company was subsequently renamed E.ON Ruhrgas UK North Sea Limited.

U.K.

Enfield

During the first half of 2005, E.ON UK bought 100 percent of the shares of Enfield Energy Centre Ltd. (“Enfield”), Coventry, U.K., in two phases. The purchase price was approximately €185 million (GBP 127 million). The company was fully consolidated as of April 1, 2005. No goodwill resulted from the purchase price allocation.

Holford

In July 2005, E.ON UK acquired Holford Gas Storage Ltd. (“Holford”), Edinburgh, U.K. The purchase price for the company was approximately €140 million (GBP 96 million). Full consolidation of the company took place on July 28, 2005. No goodwill resulted from the purchase price allocation.

Disposals, Discontinued Operations and Disposal Groups in 2005:

Discontinued Operations in 2005

For the 2005 fiscal year, Viterra and Ruhrgas Industries, both of which were sold during the year, are reported as discontinued operations in accordance with SFAS 144. In the U.S. Midwest market unit, Western Kentucky Energy Corp. (“WKE”), Henderson, Kentucky, U.S., has also been classified as a discontinued operation. In addition, a pre-tax gain of €10 million (after-tax gain: 10 million) has been recorded in 2005 from the discontinued operation of the Company’s former aluminum segment, which had already been sold in 2002.

Pan-European Gas

Ruhrgas Industries

On June 15, 2005, E.ON Ruhrgas sold Ruhrgas Industries, which operates in the gas measurement and control segments and in the construction of industrial blast furnaces, to the holding company CVC Capital Partners for a price of approximately €1.2 billion. The company was classified as a discontinued operation in June 2005, and deconsolidated as of August 31, 2005. The sale resulted in a gain of approximately €0.6 billion.

F-20

The table below provides details of selected financial information from the discontinued operations of the Pan-European Gas segment for the periods indicated:


€ in millions	2005			2004			2003

Sales		847			1,188			1,043
Gain on disposal, net		606			—			—
Other income/(expenses), net		(803	)		(1,123	)		(991	)

Income from continuing operations before income taxes and minority interests		650			65			52
Income taxes		(21	)		(35	)		(16	)
Minority interests		(1	)		(1	)		(1	)

Income from discontinued operations		628			29			35

U.S. Midwest

WKE

Through WKE, 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.

In November 2005, E.ON U.S. entered into a letter of intent with BREC regarding a proposed transaction to terminate the lease and operational agreements among the parties and other related matters. The closing of the intended transaction is subject to the review and approval of various regulatory agencies and other interested parties. Subject to such contingencies, the parties are working towards completing the proposed transaction by the end of 2006. At the end of December 2005, WKE was classified as a discontinued operation.

The tables below provide selected financial information from the discontinued WKE operations in the U.S. Midwest segment:


€ in millions	2005			2004			2003

Sales		214			195			200
Gain on disposal, net		—			—			—
Other income/(expenses), net		(466	)		(199	)		(199	)

Income from continuing operations before income taxes and minority interests		(252	)		(4	)		1
Income taxes		90			2			—

Income from discontinued operations		(162	)		(2	)		1

The increase in net other expenses is largely attributable to the marking to market of certain derivative instruments, which was required as a result of the termination of the lease due to the fact that the underlying contract is no longer expected to be fulfilled.


	December 31,
€ in millions	2005

Fixed assets		212
Non-fixed assets		469

Total assets		681

Total liabilities		831

F-21

Other Activities


	Viterra

On May 17, 2005, E.ON sold 100% of Viterra, which is active in residential real estate and in the growing real estate development business, to Deutsche Annington GmbH, Düsseldorf, Germany. The price for the shares was approximately €4 billion. The company was classified as a discontinued operation in May 2005 and deconsolidated as of July 31, 2005. A book gain of €2.4 billion was recognized on the sale.

The table below provides details of selected financial information from the discontinued operations of the other activities segment for the periods indicated:


€ in millions	2005			2004			2003

Sales		453			978			1,075
Gain on disposal, net		2,406			—			—
Other income/(expenses), net		(282	)		(595	)		(755	)

Income from continuing operations before income taxes and minority interests		2,577			383			320
Income taxes		(19	)		(64	)		37
Minority interests		—			(25	)		(18	)

Income from discontinued operations		2,558			294			339

Acquisitions in 2004:

Significant Acquisitions in 2004

U.K.

Midlands Electricity

On January 16, 2004, E.ON UK completed the acquisition of 100 percent of the British distributor of electricity Midlands Electricity plc (“Midlands Electricity”), Worcester, U.K. The purchase price, including incidental acquisition expenses, amounted to €1,706 million (GBP 1,180 million), of which €55 million was paid to stockholders and €881 million was paid to creditors. Moreover, financial debts amounting to an equivalent of €856 million were assumed. The payments to stockholders were offset by acquired liquid funds of €86 million. The company was thus fully consolidated as of January 16, 2004.

The table below contains a presentation of the major classes of assets and liabilities of Midlands Electricity as of the acquisition date:


€ in millions	January 16, 2004

Goodwill		473
Intangible assets		10
Property, plant and equipment		1,745
Financial assets		34
Non-fixed assets		197
Other assets		20

Total assets		2,479

Accrued liabilities		(178	)
Liabilities		(1,911	)
Other liabilities		(335	)

Total liabilities		(2,424	)

Net assets		55

F-22

The following condensed unaudited pro forma consolidated results of operations of the E.ON Group are presented as if the complete acquisition of Midlands Electricity had taken place on January 1, 2004, and the acquisition of E.ON Ruhrgas (for further details on the transactions, please see page F-25) had taken place on January 1, 2003. Adjustments to E.ON’s historical information have been made for the acquirees’ results of operations prior to the respective dates of acquisition. In addition, adjustments were made for depreciation, amortization and related tax effects resulting from the purchase price allocation. The pro forma figures also include adjustments to include interest costs determined on the basis of E.ON’s average interest rate for external debt, taking into consideration the respective financing structures.


	2004		2003
€ in millions	unaudited		unaudited

Net sales		42,408		42,116
Income before changes in accounting principles		4,343		5,156
Net income		4,343		4,726
Earnings per share (in €)		6.61		7.23

This unaudited pro forma information is not necessarily indicative of what the actual combined results of operations might have been had the acquisitions occurred at the beginning of the respective periods presented.

Other Acquisitions in 2004

Central Europe

JME/ JCE

In 2003, majority stakes in two Czech regional utilities, Jihomoravská energetika a.s. (“JME”), Brno, Czech Republic, and Jihoceská energetika a.s. (“JCE”), Ceské Budejovice, Czech Republic, were acquired for a total of €207 million, and both companies were fully consolidated on October 1, 2003. In December 2004, additional interests in JME and JCE were acquired; these transactions increased the Company’s respective interests in JME and JCE from 85.7 percent and 84.7 percent as of January 1, 2004, to 99.0 percent and 98.7 percent as of December 31, 2004. The total purchase price in 2004 amounted to €81 million.

Through the acquisition of all minority interests in 2005, E.ON’s ownership interest in both companies was increased to 100 percent. The acquisition costs for the stakes acquired in 2005 amounted to €5 million. The businesses of JCE and JME were subsequently transferred to the group companies E.ON Distribuce a.s., E.ON Ceská republika a.s. and E.ON Energie a.s., all registered in Ceské Budejovice, Czech Republic.

For the interests acquired in 2004 and 2005, no goodwill remained after purchase price allocation.

E.ON Bayern

In June 2003, a meeting of shareholders of E.ON Bayern AG (“E.ON Bayern”), Regensburg, Germany, had authorized E.ON Energie to acquire the outstanding shares of E.ON Bayern held by minority shareholders by means of a squeeze-out procedure. In 2004, the acquisition of the remaining E.ON Bayern shares resulted in acquisition costs of €189 million, of which €165 million were attributable to the transfer of E.ON AG shares. The goodwill resulting from this transaction was €148 million.

Following the conclusion of all legal challenges to the squeeze-out procedure, the squeeze-out was entered in the commercial register in July 2004. E.ON now holds 100 percent of E.ON Bayern.

Pan-European Gas

Thüga

At an extraordinary general meeting of shareholders of Thüga Aktiengesellschaft (“Thüga”), Munich, Germany, held on November 28, 2003, it had been decided that E.ON AG would acquire the remaining shares held by the minority shareholders in a squeeze-out transaction. In May 2004, the squeeze-out transaction for the outstanding Thüga shares (3.4 percent) was completed and entered in the commercial register, with the result that

F-23

the total E.ON Group stake in Thüga amounted to 100 percent as of December 31, 2004. The remaining 2.9 million shares were acquired at a purchase price of €223 million (including ancillary costs related to the acquisition). The purchase price allocation for these shares resulted in goodwill amounting to €106 million.

As of January 1, 2003 the total E.ON Group stake in Thüga was 87.1 percent. Through the acquisition of E.ON Ruhrgas AG in 2003, E.ON acquired additional shares in 2003. The E.ON Group stake in Thüga thus amounted to 96.6 percent on December 31, 2003.

Nordic

Graninge

In the first half of 2004, E.ON Sverige increased its stake in Graninge AB (“Graninge”), Solleftea, Sweden, from 79.0 percent as of January 1, 2004, to 100 percent through the acquisition of the outstanding shares in three tranches for an aggregate price of €307 million (SEK 2.82 billion). The purchase price allocation relating to these shares resulted in goodwill amounting to €76 million.

In 2003, E.ON increased its stake in Graninge from the 36.3 percent held on January 1, 2003, to 79.0 percent as of December 31, 2003, upon receiving regulatory antitrust approval for the transaction. To comply with Swedish stock exchange regulations, such an acquisition of a majority interest required that a public takeover offer, valid until January 16, 2004, had to be submitted to the remaining minority shareholders in November 2003. As of December 31, 2004, the goodwill relating to the 100 percent interest in Graninge amounted to €233 million.

Disposal Groups in 2004

Disposals, Discontinued Operations and Disposal Groups in 2004:

Nordic

Graninge

In 2004, E.ON reached an understanding in principle with the Norwegian utility Statkraft SF (“Statkraft SF”), Oslo, Norway, on the sale of part of the hydroelectric generation capacity that E.ON had acquired when it purchased Graninge.

E.ON Sverige and Statkraft AS (“Statkraft AS”), Oslo, Norway, signed an agreement to that effect on July 1, 2005. The sales price was approximately €480 million (SEK 4.46 billion). Statkraft AS took over the power plants in October 2005. 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.

The table below shows the major balance sheet line items affected by the transaction; they were presented in the Consolidated Balance Sheet as of December 31, 2004, under “Assets/ Liabilities of disposal groups.”


€ in millions	December 31, 2004

Fixed assets		553
Non-fixed assets		—

Total assets		553

Total liabilities		(54	)

Net assets		499

F-24

Acquisitions in 2003:

Significant Acquisitions in 2003

E.ON AG

E.ON Ruhrgas

The acquisition of E.ON Ruhrgas AG in 2003 was a significant element in the strategy of strengthening E.ON as an integrated electricity and gas company.

On January 31, 2003, E.ON reached an out-of-court settlement with nine companies that had filed appeals in state Superior Court in Düsseldorf, Germany, against the ministerial approval of the Ruhrgas takeover. All appeals were withdrawn. This allowed E.ON to expand its 38.5 percent holding in E.ON Ruhrgas as of December 31, 2002, through the subsequent acquisition of the shares belonging to Bergemann GmbH (“Bergemann”), Essen, Germany, thereby acquiring a majority of the shares of E.ON Ruhrgas. By the beginning of March 2003, the remaining shares of Ruhrgas had been acquired. The total purchase price amounted to €10.2 billion.

E.ON Ruhrgas was fully consolidated into the Consolidated Financial Statements on February 1, 2003. Goodwill in the amount of €2.9 billion resulted from the purchase price allocation.

The table below summarizes the major classes of assets and liabilities (excluding goodwill) of E.ON Ruhrgas as of the acquisition date:


€ in millions	February 1, 2003

Intangible assets		651
Property, plant and equipment		4,191
Financial assets		4,843
Non-fixed assets		6,042
Other assets		200

Total assets		15,927

Accrued liabilities		(2,098	)
Liabilities		(4,702	)
Other liabilities (including minority interests)		(1,854	)

Total liabilities		(8,654	)

Net assets (excluding goodwill)		7,273

Disposals, Discontinued Operations and Disposal Groups in 2003:

Disposals in 2003

E.ON AG

Degussa

Effective January 31, 2003, E.ON sold 18.1 percent of the capital stock of Degussa to RAG Aktiengesellschaft (“RAG”), Essen, Germany, pursuant to a public takeover offer. The sale price amounted to €1,413 million and resulted in a total gain of €276 million. However, as E.ON holds a 39.2 percent stake in RAG, the share of the gain recorded in the Consolidated Statement of Income was €168 million. E.ON continued to hold a 46.5 percent interest in Degussa, which had been accounted for at equity in the Consolidated Financial Statements thereafter. Degussa is jointly managed by E.ON and RAG pursuant to the shareholders’ agreement of May 20, 2002.

In addition, E.ON and RAG entered into a forward contract according to which RAG would purchase an additional 3.6 percent of the capital stock of Degussa by May 31, 2004, to secure a 50.1 percent holding in the

F-25

company. This transaction closed in accordance with the agreement on May 31, 2004. The sale for €283 million resulted in gains of €84 million, of which intercompany gains due to E.ON’s stake in RAG of 39.2 percent had to be adjusted. A gain of €51 million was thus realized from the sale. As of December 31, 2005, E.ON retains a 42.9 percent stake in Degussa.

Bouygues Telecom

In January 2003 E.ON entered into an agreement with the Bouygues Group, Paris, France, on the two-step disposal of E.ON’s 15.9 percent interest in Bouygues Telecom S.A. (“Bouygues Telecom”), Boulogne-Billancourt, France, the third-largest cellular phone company in France. In the first quarter of 2003, E.ON realized a gain of €294 million from the first step, the sale of 5.8 percent of Bouygues Telecom shares at a price of €394 million. In October of that year, the Bouygues Group exercised a call option to purchase the remaining 10.1 percent interest in Bouygues Telecom by December 30, 2003, at a price of €692 million. A further gain of €546 million was realized on this transaction.

The gains from the disposal of the Degussa and Bouygues Telecom shares are accounted for under “Other operating income.” Please see Note 5 for further details.

Central Europe/ Pan-European Gas

The ministerial approval of the acquisition of E.ON Ruhrgas of July 5, 2002, (amended September 18, 2002) includes, among other requirements, the requirement that E.ON disposes of the following interests by February 2004.


	•	Bayerngas GmbH (“Bayerngas”), Munich, Germany (held by E.ON Energie (22.0 percent) and E.ON Ruhrgas (22.0 percent))

	•	Gelsenwasser AG (“Gelsenwasser”), Gelsenkirchen, Germany (E.ON Energie (80.5 percent))

	•	swb AG (“swb”), Bremen, Germany (E.ON Energie (22.0 percent) and E.ON Ruhrgas (10.4 percent))

	•	Verbundnetz Gas AG (“VNG”), Leipzig, Germany (E.ON Energie (5.3 percent) and E.ON Ruhrgas (36.8 percent))

	•	EWE Aktiengesellschaft (“EWE”), Oldenburg, Germany (E.ON Energie (27.4 percent))

Bayerngas

At the end of July 2003, E.ON Energie and E.ON Ruhrgas entered into sales contracts on the disposal of their Bayerngas holdings. Each company had a 22.0 percent interest in Bayerngas. The city of Landshut, Germany, and the municipal utilities of the German cities of Munich, Augsburg, Regensburg and Ingolstadt purchased the shares in the fourth quarter of 2003 following receipt of required approvals by the responsible committees and the German Federal Ministry of Economics and Labor. E.ON realized a gain of €22 million on the complete sale, at a price of €127 million. No gain was realized on the sale of the Bayerngas shares held by E.ON Ruhrgas, as these shares had been recorded at their fair value at the time of E.ON’s consolidation of E.ON Ruhrgas.

Gelsenwasser

In September 2003, E.ON Energie sold its interest in Gelsenwasser to a joint venture owned by the municipal utilities of the German cities of Dortmund and Bochum. Further information can be found under “Discontinued Operations in 2003,” on page F-28.

swb

In November 2003, E.ON Energie sold its entire interest in E.ON Energiebeteiligungs-Gesellschaft mbH (“E.ON Energiebeteiligungs-Gesellschaft”), Munich, Germany, to EWE for €305 million. E.ON Energiebeteiligungs-Gesellschaft held 32.4 percent of the shares of swb (comprising all of the shares previously held by

F-26

E.ON Energie and Ruhrgas). The gain of €85 million resulting from the sale pertains solely to the portion held by E.ON Energie, because the swb shares held by E.ON Ruhrgas were recorded at their fair value at the time of E.ON’s consolidation of E.ON Ruhrgas.

VNG/ EWE

On January 26, 2004, the two main shareholders in EWE, Energieverband Elbe-Weser Beteiligungsholding GmbH and Weser-Ems Energiebeteiligungen GmbH, acquired the E.ON Energie stake in EWE (27.4 percent) when they exercised their preferential subscription rights. The share purchase and transfer agreement of December 8, 2003, was thus implemented in full. E.ON recorded proceeds of approximately €520 million from the disposal of the EWE shares and a net book gain of €257 million.

On January 28, 2004, EWE assumed 32.1 percent of the VNG interest. The remaining 10.0 percent were offered to and assumed by eastern German municipalities at the same sales price in accordance with the requirements of the ministerial approval. The total sales price was approximately €899 million. From the sale, E.ON recorded a net book gain of €60 million on the 5.3 percent share in VNG originally held by Central Europe. The 36.8 percent share held through Pan-European Gas was recorded at its fair value at the time of the purchase price allocation undertaken after the acquisition of the company, therefore no net book gain was attained when this stake was sold.

Contracts for the sale of E.ON’s interest in VNG and EWE were concluded in December 2003. Completion of the sales was, however, conditional on the approvals of the companies’ respective boards and on regulatory approvals. The disposals were completed in 2004.

Discontinued Operations in 2003

The sales of E.ON’s former VEBA Oel and MEMC segments, which took place in 2002 and 2001, respectively, but had not been finalized as of the end of 2002, were reported in 2003 under discontinued operations, in accordance with SFAS 144. Viterra and U.S. Midwest also disposed of certain operations and assets. In addition, as part of the requirements included in the ministerial approval for the acquisition of E.ON Ruhrgas, Central Europe classified its interest in Gelsenwasser as an asset held for sale. Amounts in the Consolidated Statements of Income and the Consolidated Statements of Cash Flows for 2003, including the notes thereto, have been adjusted to reflect these discontinued operations.

E.ON AG

VEBA Oel

In 2002, E.ON realized a preliminary sales price of approximately €2.8 billion for 100 percent of the shares of VEBA Oel AG (“VEBA Oel”), Gelsenkirchen, Germany, pursuant to an agreement E.ON entered into with BP plc. (“BP”), London, U.K., in July 2001. The final sales price payable under the contract depended on numerous conditions and settlement modalities, and especially on the proceeds BP would generate from the sale of VEBA Oel’s exploration and production businesses. In view of the political conditions in Venezuela at that time, it was not possible to sell the Venezuelan operations. In April 2003, E.ON and BP therefore agreed on a final purchase price for VEBA Oel — without impact on the customary indemnifications. This resulted in a total price of approximately €2.9 billion for VEBA Oel, and E.ON posted a book gain from the sale in the 2002 fiscal year, followed by a pre-tax loss of €35 million in 2003 (after-tax loss: €37 million). Claims asserted in 2004 resulted in an additional loss of €19 million in 2004 before taxes (after-tax loss: €19 million).

F-27

The following table provides details of selected financial information from the discontinued operations of the former Oil segment for the periods indicated:


€ in millions	2003

Sales		—
Gain (loss) on disposal, net		(35	)
Other income/(expenses), net		—

Income from continuing operations before income taxes and minority interests		(35	)
Income taxes		(2	)
Minority interests		—

Income from discontinued operations		(37	)

MEMC

On September 30, 2001, E.ON entered into an agreement to sell its silicon wafer operations to the Texas Pacific Group (“TPG”), Fort Worth, Texas, U.S. The symbolic price of USD 6.00 was paid for E.ON’s 71.8 percent interest and shareholder loans in MEMC Electronic Materials, Inc. (“MEMC”), St. Peters, Missouri, U.S. The transaction closed on November 13, 2001. The purchase price was initially subject to adjustment if MEMC met certain predefined operating objectives for 2002. In August 2003 E.ON and the purchaser reached agreement on the final purchase price, and the result was a net gain from discontinued operations of €14 million.

Central Europe

Gelsenwasser

In September 2003, Central Europe sold its 80.5 percent interest in Gelsenwasser to a joint venture owned by the municipal utilities of the German cities of Dortmund and Bochum for €835 million. This resulted in a gain of €418 million. The sale brought E.ON a step closer to fulfilling the ministerial approval requirements for the acquisition of E.ON Ruhrgas, as previously mentioned in connection with the disposal activities of 2003.

The following table provides details of selected financial information from the discontinued operations of Central Europe’s disposal groups for the periods indicated:


€ in millions	2003

Sales		295
Gain on disposal, net		418
Other income/(expenses), net		(201	)

Income from continuing operations before income taxes and minority interests		512
Income taxes		(24	)
Minority interests		(9	)

Income from discontinued operations		479

U.S. Midwest

CRC-Evans

CRC-Evans International Inc. (“CRC-Evans”), Houston, Texas, U.S., was a wholly-owned subsidiary of LG&E Energy, acquired in 1999. CRC-Evans is a provider of equipment and services for the construction and maintenance of natural gas and oil pipelines. The conditions imposed by the SEC on E.ON UK’s acquisition of LG&E Energy included the disposal of this business. In November 2003, LG&E Energy sold its stake in CRC-Evans for €37 million. CRC-Evans was deconsolidated as of October 31, 2003. With revenues of €73 million in 2003, this discontinued operation produced earnings before and after taxes that were well below €1 million in 2003. In 2005 a further gain of approximately €1 million before and after tax was realized.

F-28

Other Activities

Viterra Energy Services/ Viterra Contracting

At the end of 2002, Viterra Energy Services AG (“Viterra Energy Services”), Essen, Germany, was accounted for as a discontinued operation in E.ON’s Consolidated Financial Statements. In April 2003 Viterra sold its wholly-owned service subsidiary to CVC Capital Partners. The transaction was completed in June 2003. At the beginning of 2003, Viterra Contracting GmbH (“Viterra Contracting”), Bochum, Germany, was also sold. Viterra received proceeds totaling €961 million, including approximately €112 million in liabilities assumed by the purchaser, and realized an aggregate gain in the amount of €641 million. In 2004, pre-tax gains of €10 million were realized from the reversal of provisions that had to be established in connection with the disposals in 2003 (after-tax gain: €10 million). Both disposals reflected Viterra’s strategy of focusing on residential real estate and real estate development.

The table below provides aggregated details of selected financial information from the discontinued operations of Viterra in 2003:


€ in millions	2003

Sales		202
Gain on disposal, net		641
Other income/(expenses), net		(145	)

Income from continuing operations before income taxes and minority interests		698
Income taxes		(17	)
Minority interests		—

Income from discontinued operations		681


(5)	Other Operating Income and Expenses

The table below provides details of “Other operating income (expenses), net” for the periods indicated:


€ in millions	2005			2004			2003

Gains from the disposal of business and/or fixed assets		83			473			1,316
Gain on derivative instruments, net		946			585			384
Exchange rate differences		138			(309	)		39
SAB 51 Gain		31			—			—
Research and development costs		(24	)		(19	)		(36	)
Write-down of non-fixed assets		(38	)		(31	)		(209	)
Miscellaneous		559			662			164

Total		1,695			1,361			1,658

Other operating expenses include costs that cannot be allocated to production, selling or administration activities.

Gains on the disposal of businesses and/or fixed assets in 2005 relate with €37 million to the sale of fixed assets and with €33 million to the sale of shareholdings. The higher gains of 2004 compared to 2005 were attributable to the sale of stakes in EWE and VNG (total gain: €317 million), the disposal of 3.6 percent of the shares of Degussa AG (€51 million), the sale of shares in Union Fenosa S.A. (Union Fenosa), Madrid, Spain, with €26 million and additional disposals of investments held by the Central Europe market unit (€57 million). Net book gains of €1,316 million for 2003 included gains from the sale of E.ON’s 15.9 percent interest in Bouygues Telecom (€840 million), the sale of 18.1 percent of Degussa’s shares to RAG (€168 million), as well as from the sale of a number of shareholdings at the Central Europe market unit (aggregating €150 million).

F-29

In 2005, gains on the required marking to market of derivatives reported as “Gains on derivative instruments, net” increased by €361 million. In 2004, gains on the marking to market of derivatives increased in comparison with 2003 by €201 million. Net income from exchange rate differences improved in 2005 compared with 2004 by €447 million, reflecting results from the recognition of exchange rate movements on foreign currency transactions and net realized losses on foreign currency derivatives.

The SAB 51 gain in 2005 in the amount of €31 million related to the sale of shares of E.ON Avacon AG, Helmstedt, Germany.

Miscellaneous other operating income (expenses), net decreased by €103 million, amounting to income of €559 million in 2005, as compared with income of €662 million in 2004. The decrease from 2004 is mainly attributable to lower income from the reversal of provisions (€218 million) and an impairment loss recorded at cogeneration facilities in the U.K. market unit (€129 million) which is partly offset by higher gains realized on the sale of securities classified as non fixed assets (€153 million) and the gain from the reduction of the Company’s stake in TEAG in connection with the bundling of its electric and gas activities into ETE in the German state of Thuringia (€90 million). The increase in miscellaneous other operating income (expenses), net in 2004 compared with 2003 was primarily resulting from higher net gains from the sale of short-term securities (€106 million) and income from the reversal of certain provisions (€158 million).

The following table provides details of financial earnings for the periods indicated:


(6)	Financial Earnings


€ in millions	2005			2004			2003

Income from companies in which share investments are held; thereof from affiliated companies: €33 (2004: €32; 2003: €25)		203			185			160
Income from profit- and loss-pooling agreements; thereof from affiliated companies: €3 (2004: €5; 2003: €9)		3			5			18
Income from companies accounted for under the equity method; thereof from affiliated companies: €3 (2004: €4; 2003: €16)		778			817			794
Losses from companies accounted for under the equity method; thereof from affiliated companies: €(96) (2004: €(54); 2003: (€3))		(345	)		(168	)		(130	)
Losses from profit- and loss-pooling agreements; thereof from affiliated companies: €(1) (2004: €(8); 2003: €(11))		(3	)		(10	)		(18	)
Write-down of investments		(29	)		(77	)		(50	)

Income from share investments		607			752			774

Income from other long-term securities		45			36			48
Income from long-term loans		31			43			52
Other interest and similar income; thereof from affiliated companies: €6 (2004: €8; 2003: €0)		971			536			644
Interest and similar expenses; thereof from affiliated companies: €(8) (2004: €(5); 2003: €(12)) thereof SFAS 143 accretion expense: €(511) (2004: €(499); 2003: €(486))		(1,783	)		(1,677	)		(1722	)

Interest and similar expenses (net)		(736	)		(1,062	)		(978	)

Write-down of financial assets and long-term loans		(45	)		(54	)		(34	)

Financial earnings		(174	)		(364	)		(238	)

The income from companies in which share investments are held consists primarily of returns on numerous participations held in the core energy business.

Income (loss) from companies accounted for under the equity method are largely attributable to equity investments held by the market units Pan-European Gas and Central Europe. Losses from companies accounted

F-30

for under the equity method in 2005 were attributable primarily to a further impairment charge recorded by Degussa on its fine chemicals division. The equity-method accounting of Degussa resulted in a net loss to E.ON of €215 million through its directly held 42.9 percent share. This loss includes the pro-rata share of the impairment charge attributable to E.ON, which amounted to €347 million which was partly off-set by Degussa’s operating income. Valuation adjustments of deferred tax assets in the financial statements of another at equity holding of the Corporate Center were primarily responsible for €96 million in losses from companies accounted for under the equity method attributable to this holding in 2005.

In 2004, income from companies accounted for at equity included a gain of €107 million from the equity method treatment of Degussa.

In 2003, the equity method accounting for Degussa had resulted in a loss of €86 million. This loss primarily reflected the impairment charge recorded on the fine chemicals division. The impact on E.ON of this impairment amounted to €86 million from its directly held share of the Degussa result (€187 million), which then was 46.5 percent. The stake in Degussa held indirectly by E.ON through RAG resulted in additional losses. The total loss attributable to the indirect stake was €73 million, of which, however, only €15 million was recognized in E.ON’s losses from equity method investments in 2003, as the carrying amount of E.ON’s investment in RAG could not be reduced beyond zero.

The losses from companies accounted for under the equity method also include €1 million (2004: €86 million; 2003: €0 million) in impairment charges on goodwill of such companies.

The figure for net interest and similar expenses improved in 2005, primarily because of higher interest income. Interest expense decreased in 2004 as compared to 2003, primarily because of reduced gross financial indebtedness and as a result of the lowering of interest rates. In 2003, interest expense primarily included the initial recognition of accretion expense related to the provisions pursuant to SFAS 143 (€486 million) as well as the financing cost of the acquisitions of E.ON UK and E.ON Ruhrgas. Interest expense was reduced by capitalized interest on debt totaling €24 million (2004: €20 million; 2003: €22 million).

Included in interest and similar expenses (net) is a balance of €30 million (2004: €31 million; 2003: €24 million) in interest expense resulting from financial relationships with associated companies and other share investments.


(7)	Income Taxes

The following table provides details of income taxes, including deferred taxes, for the periods indicated:


€ in millions		2005			2004			2003

Current taxes
	Domestic corporate income tax		1,081			952			560
	Domestic trade tax		416			446			407
	Foreign income tax		381			395			283
	Other		—			(1	)		1

Total			1,878			1,792			1,251

Deferred taxes
	Domestic		(4	)		92			(28	)
	Foreign		402			(34	)		(78	)

Total			398			58			(106	)

Income taxes			2,276			1,850			1,145

F-31

The increase in tax expenses of €426 million over the previous year primarily reflects the following events: Improvements in operating income and a reduced proportion of tax-exempt earnings resulted in an increase in current income taxes of €86 million. The significant increase in foreign deferred taxes was due in particular to the marking to market of energy derivatives in the U.K. market unit, which resulted in an increase over 2004 in the fair values of these derivatives. The increase in tax expenses by €705 million in 2004 compared to 2003 primarily reflected improvements in operating earnings.

The 2003 Tax Preference Reduction Act (“Steuervergünstigungsabbaugesetz”) altered the regulatory framework regarding the utilization of corporate tax credits arising from the corporate imputation system (“Anrechnungsverfahren”), which existed until 2001. The main changes include the repeal of the tax credit for corporate dividends paid out after April 11, 2003, and before January 1, 2006. This has resulted in a final increased tax burden of approximately €258 million (2004: €219 million; 2003: €190 million) on dividend payments in the amount of €1,549 million in 2005 (2004: €1,312 million; 2003: €1,142 million).

In 2004, a deferred tax liability of €330 million was recorded to take into account the difference between net assets and the tax bases of subsidiaries and associated companies. As of December 31, 2005, the deferred tax liability amounted to €436 million. No deferred taxes have been recognized for temporary differences between net assets and the tax bases of foreign subsidiaries held by companies in third countries, since no actual reversals of these differences are expected to occur, which in turn makes it impracticable to determine deferred taxes for them.

Changes in foreign tax rates resulted in a total deferred tax expense of €4 million. This compares to a deferred tax benefit of €10 million recorded in 2004 resulting from changes in tax rates and tax law in Finland, the Netherlands and Austria. In 2003, a deferred tax benefit of €206 million was recorded following changes in tax rates in the Czech Republic, Italy and Hungary, as well as a change of tax law in Sweden affecting the taxation of gains on the disposal of shareholdings in certain corporations that came into effect in mid-2003.

In light of the positive developments in three precedent-setting tax proceedings in the lower German tax courts, the Company released a tax provision in 2001 that had previously been established to account for a probable liability stemming from gains from profit-and-loss-pooling agreements with former non-profit real estate companies that were in place during periods prior to the consolidated tax filing status. In December 2002, the federal tax court confirmed the favorable decisions of the lower courts. In accordance with that December 2002 tax court decision, the tax authorities in 2004 made the appropriate amendments to the corporate tax assessments for preceding years. This resulted in the Company receiving tax refunds in 2004 totaling €351 million.

For fiscal years ending after December 31, 2003, pre-consolidation remittance surpluses and shortfalls (“vororganschaftliche Mehr- und Minderabführungen”) have become subject to the revised provisions of Article 14 (3) of the Corporate Tax Act (“KStG”), as amended by the Directive Implementation Act of December 9, 2004 (“EURLUmsG”). This revision of the KStG provides that tax-effective transfers of profits and losses that took place during periods before the profit-and-loss-pooling agreement came into effect no longer fall under the profit-and-loss rules applicable to consolidated entities. Pre-consolidation remittance surpluses and shortfalls are now to be treated respectively as distributions and capital contributions, with 5 percent of distributions taxable. This change in tax law resulted in a tax benefit of €9 million in 2005 (2004: €152 million tax expense), including a deferred tax benefit of €20 million (2004: €87 million tax expense).

F-32

The differences between the statutory tax rate in 2005 of 25 percent (2004: 25 percent; 2003: 26.5 percent) in Germany and the effective tax rate are reconciled as follows:


		2005			2005			2004			2004			2003			2003
€ in millions		Amount			Percent			Amount			Percent			Amount			Percent

Corporate income tax			1,802			25.0			1,588			25.0			1,369			26.5
Domestic trade tax net of federal tax benefit			475			6.6			433			6.8			78			1.5
Foreign tax rate differentials			165			2.3			164			2.6			70			1.4
Change in valuation allowances			109			1.5			(202	)		(3.2	)		542			10.5
Changes in tax rate/tax law			4			0.1			142			2.2			60			1.2
Tax effects on
	Tax-free income		(218	)		(3.0	)		(343	)		(5.4	)		(409	)		(7.9	)
	Equity accounting		(46	)		(0.7	)		(122	)		(1.9	)		(163	)		(3.2	)
Other			(15	)		(0.2	)		190			3.0			(402	)		(7.8	)

Effective income taxes/ tax rate			2,276			31.6			1,850			29.1			1,145			22.2

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 are as follows:


€ in millions	2005			2004			2003

Viterra		19			64			(37	)
Viterra Energy Services/Viterra Contracting		—			—			17
Ruhrgas Industries		21			35			16
WKE		(90	)		(2	)		—
Veba Oel		—			—			2
MEMC		—			—			9
Gelsenwasser		—			—			24

Income taxes from discontinued operations		(50	)		97			31

Income from continuing operations before income taxes and minority interests was attributable to the following geographic locations in the periods indicated:

€ in millions

2005

2004

2003

Domestic

3,526

3,553

3,033

Foreign

3,682

2,802

2,132

Total

7,208

6,355

5,165

F-33

Deferred tax assets and liabilities are as follows as of December 31, 2005 and 2004:


		December 31,

€ in millions		2005			2004

Deferred tax assets
	Intangible assets		41			167
	Property, plant and equipment		624			376
	Financial assets		383			518
	Inventories		7			14
	Receivables		178			343
	Accrued liabilities		4,753			4,165
	Liabilities		2,421			1,250
	Net operating loss carryforwards		891			1,089
	Tax credits		33			34
	Other		269			440

	Subtotal		9,600			8,396

	Valuation allowance		(573	)		(509	)

	Total		9,027			7,887

Deferred tax liabilities
	Intangible assets		(1,030	)		(700	)
	Property, plant and equipment		(6,609	)		(6,155	)
	Financial assets		(2,312	)		(1,114	)
	Inventories		(94	)		(98	)
	Receivables		(2,401	)		(1,934	)
	Accrued liabilities		(1,167	)		(1,086	)
	Liabilities		(911	)		(1,149	)
	Other		(844	)		(705	)

	Total		15,368			12,941

	Net deferred tax liabilities		(6,341	)		(5,054	)

Of the deferred tax liabilities on financial assets reported for 2005, €1,137 million (2004: €317 million) relate to the marking to market of other share investments. Of this amount, €1,120 million (2004: €299 million) were recorded under stockholders’ equity (other comprehensive income), with no effect on income.

Net deferred income taxes included in the Consolidated Balance Sheets are as follows:


	December 31, 2005						December 31, 2004

				Thereof						Thereof
€ in millions	Total			non-current			Total			non-current

Deferred tax assets		2,652			2,269			2,060			1,865
Valuation allowance		(573	)		(563	)		(509	)		(506	)

Net deferred tax assets		2,079			1,706			1,551			1,359

Less deferred tax liabilities		(8,420	)		(7,929	)		(6,605	)		(5,779	)

Net deferred tax liabilities		(6,341	)		(6,223	)		(5,054	)		(4,420	)

In the acquisition of Caledonia, the purchase price allocation resulted in deferred tax assets of €112 million and deferred tax liabilities of €245 million as of December 31, 2005. The purchase price allocation of GVT resulted in a deferred tax liability of €36 million as of December 31, 2005.

F-34

The purchase price allocations of the acquisitions of Distrigaz, NRE Energie, Varna and Enfield resulted in a total deferred tax liability of €56 million as of December 31, 2005.

The purchase price allocation of the acquisition of Midlands Electricity resulted in a deferred tax liability of €274 million in 2004.

Based on subsidiaries’ past performance and the expectation of similar performance in the future, it is expected that the future taxable income of these subsidiaries will more likely than not be sufficient to permit recognition of their deferred tax assets. A valuation allowance has been provided for that portion of the deferred tax assets for which this criterion is not expected to be met.

The tax loss carryforwards as of the dates indicated are as follows:


	December 31,

€ in millions	2005		2004

Domestic tax loss carryforwards		2,907		4,487
Foreign tax loss carryforwards		1,220		1,158

Total		4,127		5,645

Since January 1, 2004, a tax loss carryforward 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. Despite the introduction of minimum taxation, the German tax loss carryforwards have no expiration date.

Foreign tax loss carryforwards expire as follows: €52 million in 2006, €29 million between 2007 and 2010, €508 million after 2010. €631 million do not have an expiration date.

Tax credits totaling €37 million are exclusively foreign and expire as follows: €7 million between 2007 and 2010 and €15 million after 2010. €15 million do not have an expiration date.


(8)	Minority Interests in Net Income

Minority stockholders participate in the profits of the affiliated companies in the amount of €584 million (2004: €533 million; 2003: €532 million) and in the losses in the amount of €31 million (2004: €55 million; 2003: €87 million).

(9) Personnel-Related Information

Personnel Costs

The following table provides details of personnel costs for the periods indicated:


€ in millions	2005		2004		2003

Wages and salaries		3,232		2,933		3,101
Social security contributions		553		504		536
Pension costs and other employee benefits; thereof pension costs: €744 (2004: €734; 2003: €647)		794		755		748

Total		4,579		4,192		4,385

In 2005, E.ON purchased a total of 308,555 of its ordinary shares (0.04 percent of E.ON’s outstanding shares) on the open market (2004: 211,815; 0.03 percent) at an average price of €76.03 (2004: €58.08) per share for resale to employees. These shares were sold to employees at preferential prices between €35.01 and €64.04 per share (2004: between €29.68 and €53.31). The difference between purchase price and resale price was 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 17.

F-35

Since the 2003 fiscal year, a stock-based employee compensation program based on E.ON shares has been in place at the U.K. market unit. Through this program, employees have the opportunity to purchase E.ON shares and to acquire additional bonus shares. The cost of issuing these bonus shares is also recorded under personnel costs as “wages and salaries.”

Stock Appreciation Rights of E.ON AG

In 1999, the E.ON Group introduced a stock-based compensation plan (“Stock Appreciation Rights” or “SAR”) based on E.ON AG shares. E.ON AG continued the SAR program by issuing a seventh tranche of SAR in 2005.

Since all first-tranche SAR (1999 to 2003) were exercised in full in 2002, there remained liabilities from the second through seventh tranches in 2005 as follows:


	7th tranche		6th tranche		5th tranche		4th tranche		3rd tranche		2nd tranche

Date of issuance		Jan. 3, 2005		Jan. 2, 2004		Jan. 2, 2003		Jan. 2, 2002		Jan. 2, 2001		Jan. 3, 2000
Term		7 years		7 years		7 years		7 years		7 years		7 years
Blackout period		2 years		2 years		2 years		2 years		2 years		2 years
Price at issuance (in €)		65.35		49.05		42.11		54.95		62.95		48.35
Number of participants in year of issuance		357		357		344		186		231		155
Number of SAR issued (in millions)		2.9		2.7		2.6		1.7		1.8		1.5
Exercise hurdle (minimum percentage by which exercise price exceeds the price at issuance)		10		10		10		10		20		20
Exercise hurdle (minimum exercise price in €)		71.89		53.96		46.32		60.45		75.54		58.02
Intrinsic value as of December 31, 2005 (in €)		22.04		38.34		45.28		32.44		24.44		39.04
Maximum exercise gain (in €)		65.35		49.05		—		—		—		—
Number of SAR outstanding as of December 31, 2005 (in millions)		2.9		2.4		0.6		0.2		0.1		0.1
Provision as of December 31, 2005 (€ in millions)		31.8		92.7		27.8		7.7		3.9		0.5
Exercise gains in 2005 (€ in millions)		0.1		1.2		49.9		8.5		15.1		3.3
Expense in 2005 (€ in millions)		31.9		70.2		15.4		6.4		13.6		0.2

All the members of the Board of Management of E.ON AG and certain executives of E.ON AG and of the market units participate in the E.ON AG SAR program. In 2003, E.ON Ruhrgas ended the program of phantom stock options it had set up in 2002, having fulfilled all its obligations thereunder. The costs of €0.8 million pertaining to the program are reported as part of personnel costs.

SAR can only be issued if the qualified executive owns a certain minimum number of shares of E.ON stock, which must be held until the expiration date of the issued SAR, or until they have all been exercised.

SAR can be exercised (either the total grant or partial grant) by eligible executives following the blackout period of 2 years until the end of the respective tranche’s term within predetermined exercise windows for a period of four weeks starting on the first business day after the publication of an E.ON Interim Report or Annual Report. The term of the SAR is limited to a total of 7 years.

Both of the following two conditions must be met before E.ON SAR may be exercised:


	•	Between the date of issuance and exercise, the E.ON stock price must outperform the Dow Jones STOXX Utilities Index (Price EUR) on at least ten consecutive trading days.

F-36


	•	The E.ON stock price on the exercise date must be at least 10.0 percent (for the second and third tranches: at least 20.0 percent) above the price at issuance.

SAR that remain unexercised by the employee on the corresponding tranche’s last exercise date are considered to have been exercised automatically on that date, subject to fulfillment of the exercise conditions. Otherwise the rights embodied in the SAR expire.

When exercising SAR, qualified executives receive cash. Possible dilutive effects of capital-related measures and extraordinary dividend payments between the time of issuance of the SAR and their exercise are taken into consideration when calculating such compensation.

The amount paid to executives when they exercise their SAR is the difference between the E.ON AG stock price at the time of exercise and the underlying stock 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 strike price was put in place in order to limit the effect of unforeseen extraordinary increases in the price of the underlying stock.

Starting with the fourth tranche, the underlying stock price equals the average XETRA closing quotations for E.ON stock during the December prior to issuance. For tranches two and three, the underlying stock price is the E.ON stock price at the actual time of issuance.

Once issued, SAR are not transferable, and when the qualified executive leaves the E.ON Group they may be exercised according to the SAR conditions either on the next possible allowed date or, if certain conditions have been fulfilled, prior to that date. If employment is terminated by the executive, SAR expire and become void without compensation if such termination occurs within the two-year blackout period or if the SAR are not exercised on the next possible exercise date.

In 2005, 3,432,309 SAR from tranches two through five were exercised on an ordinary basis. In addition, 140,004 SAR from tranches two through seven were exercised in accordance with the SAR terms and conditions on an extraordinary basis. 39,000 SAR expired. The gain to the holders on exercise was €78.1 million. The intrinsic values of the second through seventh tranches are shown in the table on page F-36 and resulted in an increase in the liability to €164.4 million. The total expense recorded for the SAR program in 2005 was €137.7 million.

F-37

The E.ON SAR program has shown the following developments since 2002:


Number of Options	7th tranche		6th tranche			5th tranche			4th tranche			3rd tranche			2nd tranche

Outstanding as of January 1, 2002		—		—			—			—			1,822,620			1,345,800
Granted in 2002		—		—			—			1,646,419			—			—
Exercised in 2002		—		—			—			—			—			220,150
Cancelled in 2002		—		—			—			—			—			—
Change in scope of consolidation		—		—			—			—			(504,720	)		(301,000	)

Outstanding as of December 31, 2002		—		—			—			1,646,419			1,317,900			824,650

Granted in 2003		—		—			2,549,188			15,000			—			—
Exercised in 2003		—		—			9,902			—			—			—
Cancelled in 2003		—		—			—			—			—			—
Change in scope of consolidation		—		—			—			(46,000	)		(17,000	)		(26,800	)

Outstanding as of December 31, 2003		—		—			2,539,286			1,615,419			1,300,900			797,850

Granted in 2004		—		2,653,847			12,107			—			—			—
Exercised in 2004		—		6,666			49,000			805,533			—			605,350
Cancelled in 2004		—		—			—			—			—			—
Change in scope of consolidation		—		—			—			—			—			—

Outstanding as of December 31, 2004		—		2,647,181			2,502,393			809,886			1,300,900			192,500

Granted in 2005		2,904,949		17,297			—			—			—			—
Exercised in 2005		7,521		55,983			1,860,682			503,477			983,650			161,000
Cancelled in 2005		12,000		20,000			—			—			7,000			—
Change in scope of consolidation		—		(170,500	)		(28,000	)		(67,500	)		(151,500	)		(19,000	)

Outstanding as of December 31, 2005		2,885,428		2,417,995			613,711			238,909			158,750			12,500

Outstanding as of December 31, 2005 (in%)		99.3		90.5			24.0			14.4			8.7			0.9

SAR exercisable at year end		—		—			613,711			238,909			158,750			12,500

The changes in the scope of consolidation in 2005 are related to the discontinued operations Viterra and Ruhrgas Industries. The respective percentages of outstanding SAR indicated for December 31, 2005, are based on the total number of SAR issued from each corresponding tranche. As of December 31, 2005, none of the SAR in the sixth and seventh tranches were exercisable because the blackout periods had not expired.

Employees

During 2005, the Company employed an average of 75,173 people (2004: 61,309), not including 2,174 apprentices (2004: 2,063). The breakdown by segments is shown below:


	2005		2004

Central Europe		42,835		37,509
Pan-European Gas		11,025		3,982
U.K.		12,106		10,453
Nordic		5,766		5,908
U.S. Midwest		3,007		3,039
Corporate Center		434		418

*Core energy business*		75,173		61,309

Other activities		—		—

Total		75,173		61,309

F-38

(10) Earnings per Share

The computation of basic and diluted earnings per share for the periods indicated is shown below:


€ in millions		2005			2004		2003

Income/(Loss) from continuing operations			4,379			4,027		3,575
Income/(Loss) from discontinued operations, net			3,035			312		1,512
Income/(Loss) from cumulative effect of changes in accounting principles, net			(7	)		—		(440	)

Net income			7,407			4,339		4,647

Weighted-average number of shares outstanding (in millions)			659			657		654

Earnings per share (in €)
	from continuing operations		6.64			6.13		5.47
	from discontinued operations, net		4.61			0.48		2.31
	from cumulative effect of changes in accounting principles, net		(0.01	)		—		(0.67	)

	from net income		11.24			6.61		7.11

The computation of diluted EPS is identical to that for basic EPS, as E.ON AG does not have any dilutive securities.

F-39

(11) Fixed Assets

The following table provides information about the developments of fixed assets during the fiscal year:


	Acquisition and Production Costs

			Exchange			Change in
	January 1,		rate			scope of														December 31,
€ in millions	2005		differences			consolidation			Additions		Disposals			Transfers			Impairment			2005

Goodwill		14,758		613			356			43		(82	)		(26	)		—			15,662
Intangible assets		5,428		32			494			114		(79	)		67			—			6,056
Advance payments on intangible assets		7		—			2			26		—			(9	)		—			26

Goodwill and intangible assets		20,193		645			852			183		(161	)		32			—			21,744

Real estate, leasehold rights and buildings		18,653		(35	)		(6,749	)		95		(395	)		218			(15	)		11,772
Technical equipment, plant and machinery		73,725		834			1,623			1,918		(1,240	)		540			(9	)		77,391
Other equipment, fixtures, furniture and office equipment		3,222		71			146			209		(241	)		70			(129	)		3,348
Advance payments and construction in progress		1,348		31			(5	)		940		(119	)		(854	)		(10	)		1,331

Property, plant and equipment		96,948		901			(4,985	)		3,162		(1,995	)		(26	)		(163	)		93,842

Shares in unconsolidated affiliates		599		(2	)		(157	)		228		(204	)		226			(14	)		676
Shares in associated companies		10,431		47			(140	)		330		(561	)		149			(8	)		10,248
Other share investments		2,560		(2	)		(195	)		149		(120	)		(147	)		(15	)		2,230
Long-term loans to unconsolidated affiliates		592		(1	)		(52	)		30		(110	)		(208	)		—			251
Loans to associated companies and other share investments		315		(8	)		(1	)		74		(50	)		(17	)		(1	)		312
Other long-term loans		556		(9	)		(2	)		52		(21	)		(5	)		(9	)		562
Long-term securities		466		4			(3	)		362		(274	)		—			—			555

Financial assets		15,519		29			(550	)		1,225		(1,340	)		(2	)		(47	)		14,834

Total		132,660		1,575			(4,683	)		4,570		(3,496	)		4			(210	)		130,420


	Accumulated Depreciation

				Exchange			Change in											Fair value
	January 1,			rate			scope of											OCI			December 31,
	2005			differences			consolidation			Additions		Disposals			Transfers			adjustments			2005

Goodwill		304			(3	)		(2	)		—		—			—			—			299
Intangible assets		1,647			10			(30	)		366		(52	)		16			—			1,957
Advance payments on intangible assets		—			—			—			—		—			—			—			—

Goodwill and intangible assets		1,951			7			(32	)		366		(52	)		16			—			2,256

Real estate, leasehold rights and buildings		6,713			29			(2,583	)		231		(302	)		38			—			4,126
Technical equipment, plant and machinery		44,433			318			387			2,012		(1,067	)		(71	)		—			46,012
Other equipment, fixtures, furniture and office equipment		2,216			43			69			249		(230	)		26			—			2,373
Advance payments and construction in progress		23			—			—			—		—			(15	)		—			8

Property, plant and equipment		53,385			390			(2,127	)		2,492		(1,599	)		(22	)		—			52,519

Shares in unconsolidated affiliates		28			—			(18	)		—		(1	)		—			—			9
Shares in associated companies		495			1			(4	)		—		(3	)		—			5			494
Other share investments		(1,924	)		—			(12	)		—		—			—			(4,839	)		(6,775	)
Long-term loans to unconsolidated affiliates		—			—			—			—		—			—			—			—
Loans to associated companies and other share investments		18			—			—			—		—			—			—			18
Other long-term loans		7			—			—			—		—			—			—			7
Long-term securities		(368	)		—			—			—		—			—			(237	)		(605	)

Financial assets		(1,744	)		1			(34	)		—		(4	)		—			(5,071	)		(6,852	)

Total		53,592			398			(2,193	)		2,858		(1,655	)		(6	)		(5,071	)		47,923

[Additional columns below]

[Continued from above table, first column(s) repeated]


	Net book values

	December 31,		December 31,
	2005		2004

Goodwill		15,363		14,454
Intangible assets		4,099		3,781
Advance payments on intangible assets		26		7

Goodwill and intangible assets		19,488		18,242

Real estate, leasehold rights and buildings		7,646		11,940
Technical equipment, plant and machinery		31,379		29,292
Other equipment, fixtures, furniture and office equipment		975		1,006
Advance payments and construction in progress		1,323		1,325

Property, plant and equipment		41,323		43,563

Shares in unconsolidated affiliates		667		571
Shares in associated companies		9,754		9,936
Other share investments		9,005		4,484
Long-term loans to unconsolidated affiliates		251		592
Loans to associated companies and other share investments		294		297
Other long-term loans		555		549
Long-term securities		1,160		834

Financial assets		21,686		17,263

Total		82,497		79,068

F-40

a) Goodwill and Other Intangible Assets

Goodwill

During the 2004 and 2005 fiscal years, the carrying amount of goodwill changed as follows in each of E.ON’s segments:


				Pan-															Core
	Central			European									U.S.			Corporate			Energy			Other
€ in millions	Europe			Gas			U.K.			Nordic			Midwest			Center			Business			Activities			Total

Book value as of January 1, 2004		2,178			3,755			4,348			297			3,367			—			13,945			10			13,955
Goodwill additions/disposals		282			167			473			71			—			1			994			—			994
Other changes (1)		(155	)		(2	)		(42	)		(9	)		(287	)		—			(495	)		—			(495	)

Book value as of December 31, 2004		2,305			3,920			4,779			359			3,080			1			14,444			10			14,454
Goodwill additions/disposals		115			481			21			7			—			(1	)		623			—			623
Other changes (1)		(1	)		(332	)		155			2			472			—			296			(10	)		286

Book value as of December 31, 2005		2,419			4,069			4,955			368			3,552			—			15,363			—			15,363


(1)	Other changes include transfers and exchange rate differences; the figures for 2005 also include reclassifications to discontinued operations (Pan-European Gas segment: €(326) million; other activities: €(10) million)

To perform the annual impairment test, the Company determines the fair value of its reporting units based on a valuation model that draws on medium-term planning data that the Company uses for internal reporting purposes. The model uses the discounted cash flow method and market comparables. Goodwill must also be evaluated at the reporting unit level for impairment between these annual tests if events or changes in circumstances indicate that goodwill might be impaired.

As the fair value of each reporting unit exceeded the carrying amount, no goodwill impairment charge was recognized in 2005 in connection with the impairment test (2004: €0 million; 2003: €0 million).

Other Intangible Assets

As of December 31, 2005, the Company’s intangible assets other than goodwill, including advance payments on intangible assets, consisted of the following:

December 31, 2005

Acquisition

Accumulated

Net book

€ in millions

costs

Amortization

value

Intangible assets subject to amortization

Marketing-related intangible assets

223

123

100

thereof brand names

223

123

100

Customer-related intangible assets

2,419

765

1,654

thereof customer lists and customer relationships

2,305

704

1,601

Contract-based intangible assets

1,674

593

1,081

thereof concessions

1,223

392

831

Technology-based intangible assets

662

476

186

thereof software

563

408

155

Intangible assets not subject to amortization

1,104

—

1,104

thereof easements

818

—

818

Total

6,082

1,957

4,125

F-41

The following intangible assets were added in 2005, including intangible assets that were acquired either individually or as part of business combinations:


				Weighted average
		Acquisition costs		amortization period
		(€ in millions)		(in years)

Intangible assets subject to amortization
Marketing-related intangible assets			—
Customer-related intangible assets			144		27
	thereof customer lists and customer relationships		141		28
Contract-based intangible assets			160		22
	thereof construction permits		140		25
Technology-based intangible assets			88		3
	thereof software		85		3
Intangible assets not subject to amortization			253
	thereof licenses for exploration and production		251

Total			645

In 2005, the Company recorded an aggregate amortization expense of €366 million (2004: €370 million; 2003: €369 million). No impairment charge on intangible assets other than goodwill was recognized in 2005 (2004: €9 million; 2003: €3 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:


€ in millions

2006			354
2007			326
2008			241
2009			198
2010			165

Total			1,284

As acquisitions and disposals occur in the future, actual amounts may vary.

b) Property, Plant and Equipment

Property, plant and equipment includes capitalized interest on debt apportioned to the construction period of qualifying assets as part of their cost of acquisition and production in the amount of €24 million (2004: €20 million; 2003: €22 million). Impairment charges on property, plant and equipment were €163 million (2004: €156 million; 2003: €9 million).

In 2005, the Company recorded depreciation of property, plant and equipment in the amount of €2,492 million (2004: €2,286 million; 2003: €2,527 million).

As of December 31, 2005, the gross carrying value of property, plant and equipment under operating leases in which the E.ON is the lessor was €1,270 million (2004: €8,174 million), and the accumulated depreciation corresponding to these leased assets totaled €983 million (2004: €3,578 million). The changes are primarily the result of disposals of companies.

Restrictions on disposals of the Company’s tangible fixed assets exist in the amount of €4,191 million (2004: €3,742 million) mainly with regard to land, buildings and technical equipment. For additional information on collateralized tangible fixed assets, see Note 24.

F-42

Jointly Owned Power Plants

E.ON holds joint ownership and similar contractual rights in certain power plants that are all independently financed by each respective participant. These jointly owned power plants were formed under ownership agreements or arrangements that did not create legal entities for which separate financial statements are prepared. They are therefore included in the financial statements of their owners. E.ON’s share of the operating expenses for these facilities is included in the Consolidated Financial Statements.

The following table provides additional details about these plants, which are located in Germany unless otherwise indicated:


						E.ON’s
		E.ON’s		E.ON’s		accumulated		E.ON’s
		ownership		total		depreciation &		construction
		interest		acquisition cost		amortization		work in process
Name of plants by type		in %		(€ in millions)		(€ in millions)		(€ in millions)

Nuclear
	Isar 2		75.00		1,991		1,855		8
	Gundremmingen B		25.00		96		81		—
	Gundremmingen C		25.00		108		93		—
Lignite
	Lippendorf S		50.00		532		373		—
Hard Coal
	Bexbach 1		8.33		64		60		—
	Trimble County (U.S.)		75.00		516		187		8
	Rostock		50.38		317		284		—
Hydroelectric/ Wind
	Nymølle Havspark/ Rødsand (Denmark)		20.00		42		4		—
	Nußdorf		53.00		55		41		—
	Ering		50.00		31		28		—
	Egglfing		50.00		47		43		—

c) Financial Assets

Impairment charges on financial assets during 2005 amounted to €47 million (2004: €230 million; 2003: €110 million).


	Shares in Affiliated and Associated Companies Accounted for Under the Equity Method

The financial information below summarizes income statement and balance-sheet data for the investments of the Company’s affiliated and associated companies that are accounted for under the equity method. Separate summarized income-statement and balance-sheet data are presented for RAG, as this investment had to be considered a significant investment in 2004 under applicable rules of the U.S. Securities and Exchange Commission.


€ in millions	2005			thereof RAG			2004			thereof RAG		2003			thereof RAG

Sales		59,533			21,670			55,790			18,240		51,096			12,791
Net income		1,782			91			2,415			—		2,258			86
E.ON’s share of net income		550			36			881			—		791			34
Other (1)		(117	)		(36	)		(232	)		—		(127	)		(49	)

Income from companies accounted for under the equity method		433			—			649			—		664			(15	)


(1)	‘Other’ primarily includes adjustments to conform with E.ON accounting policies, amortization of fair value adjustments due to purchase price allocations and intercompany eliminations.

F-43

Dividends received from affiliated and associated companies accounted for under the equity method were €824 million in 2005 (2004: €834 million; 2003: €683 million).


	December 31,

€ in millions	2005		thereof RAG			2004		thereof RAG

Fixed assets		47,547		16,841			48,318		17,714
Non-fixed assets and prepaid expenses		32,165		11,679			30,713		11,973
Accrued liabilities		28,611		15,401			26,797		14,686
Liabilities and deferred income		30,307		9,833			29,561		9,785
Minority interests		2,152		1,831			3,085		2,889

Net assets		18,642		1,455			19,588		2,327

E.ON’s share in equity		6,788		570			7,433		912
Other (1)		2,901		(570	)		2,398		(912	)

Investment in companies accounted for under the equity method		9,689		—			9,831		—


(1)	‘Other’ primarily includes adjustments to conform with E.ON accounting policies, (goodwill, fair value adjustments due to purchase price allocations), intercompany eliminations and impairments.

The book value of affiliated and associated companies accounted for under the equity method whose shares are marketable amounts to a total of €2,536 million (2004: €2,739 million). The fair value of E.ON’s share in these companies is €5,493 million (2004: €4,096 million).

Additions of investments in associated and affiliated companies that are accounted for under the equity method resulted in goodwill of €44 million in 2005 (2004: €51 million).

Investments in associated companies totaling €71 million (2004: €69 million) were restricted because they were pledged as collateral for financing as of the balance-sheet date.

Other Share Investments and Available-for-Sale Securities

The amortized costs, fair values and gross unrealized gains and losses for other share investments and available-for-sale securities that management intends to hold long-term, as well as the maturities of fixed-term securities as of December 31, 2005 and 2004, are summarized below:


	December 31, 2005								December 31, 2004

					Gross		Gross						Gross		Gross
	Amortized		Fair		unrealized		unrealized		Amortized		Fair		unrealized		unrealized
€ in millions	cost		value		loss		gain		cost		value		loss		gain

Fixed-term securities
Less than 1 year		10		10		—		—		109		109		—		—
Between 1 and 5 years		54		54		—		—		14		14		—		—
More than 5 years		58		68		—		10		97		101		—		4

Subtotal		122		132		—		10		220		224		—		4

Non-fixed-term securities		2,624		10,033		1		7,410		2,755		5,094		1		2,340

Total		2,746		10,165		1		7,420		2,975		5,318		1		2,344

In 2005, amortized costs were written down in the amount of €15 million (2004: €36 million; 2003: €15 million).

Disposals of other share investments and available-for-sale securities generated proceeds of €353 million in 2005 (2004: €769 million; 2003: €815 million) and capital gains of €3 million (2004: €25 million; 2003: €0 million). The Company uses the specific identification method as a basis for determining these amounts.

F-44

Non-fixed-term securities include non-marketable investments or securities of €767 million (2004: €1,065 million).

For the other share investments that are marketable, gross unrealized gains of €6,814 million were recorded as of December 31, 2005 (2004: €1,974 million). The increase in fair value of other share investments that are marketable in 2005 was primarily attributable to the investment in OAO Gazprom (“Gazprom”), Moscow, Russia.


	Long-Term Loans

Long-term loans were as follows as of December 31, 2005 and 2004:


	December 31, 2005						December 31, 2004

			Average						Average
			interest rate		Maturity				interest rate		Maturity
	€ in millions		(in %)		through		€ in millions		(in %)		through

Loans to affiliated companies		251		4.24		2022		592		4.34		2025
Loans to associated companies and other share investments		294		3.68		2024		297		3.18		2024
Other long-term loans		555		2.08		2021		549		2.42		2023

Total		1,100						1,438

Of the decline in loans to affiliated companies, €223 million is due to the capital increase that took place following the conversion of shareholder loans at ONE GmbH (“ONE”), Vienna, Austria. For additional information, see Note 30.


(12)	Inventories

The following table provides details of inventories as of the dates indicated:


		December 31,

€ in millions		2005		2004

Raw materials and supplies by segment
	Central Europe		904		838
	Pan-European Gas		28		104
	U.K.		326		221
	Nordic		223		213
	U.S. Midwest		237		182
	Corporate Center		—		—

	Core energy business		1,718		1,558
	Other activities		—		69

Total			1,718		1,627

Work in progress			58		320
Finished products			10		98
Goods purchased for resale			671		602

Inventories			2,457		2,647

Raw materials, finished products and goods purchased for resale are generally valued at average cost. Where this is not the case, the LIFO method is used, particularly for the valuation of natural gas inventories. In 2005, inventories valued according to the LIFO method amounted to €502 million (2004: €509 million).

The difference between valuation according to LIFO and higher replacement costs is €332 million (2004: €89 million).

F-45


(13)	Receivables and Other Assets

The following table provides details of receivables and other assets as of the dates indicated:


	December 31, 2005				December 31, 2004

	With a		With a		With a		With a
	remaining		remaining		remaining		remaining
	term up to		term of more		term up to		term of more
€ in millions	1 year		than 1 year		1 year		than 1 year

Financial receivables from affiliated companies		115		—		85		19
Financial receivables from associated companies		87		158		84		3
Other financial assets		858		801		1,145		788

Financial receivables and other financial assets		1,060		959		1,314		810

Trade receivables		8,179		90		6,462		72
Operating receivables from affiliated companies		62		—		63		—
Operating receivables from associated companies and other share investments		748		—		747		24
Reinsurance claim due from the mutual insurance fund Versorgungskasse Energie		80		1,495		44		974
U.S. regulatory assets		52		69		58		55
Other operating assets		8,832		1,747		6,334		926

Operating receivables and other operating assets		17,953		3,401		13,708		2,051

Receivables and other assets		19,013		4,360		15,022		2,861

In 2005, other financial assets included receivables from owners of minority interests in jointly owned power plants of €688 million (2004: €724 million) and margin account deposits receivable of €30 million (2004: €67 million). In addition, in connection with the application of SFAS 143, other financial assets include a claim for a refund from the Swedish nuclear fund in the amount of €394 million (2004: €404 million) in connection with the decommissioning of nuclear power plants. Since this asset is designated for a particular purpose, E.ON’s access to it is restricted.

The reinsurance claims due from the mutual insurance fund Versorgungskasse Energie Versicherungsverein auf Gegenseitigkeit (“VKE”), Hanover, Germany, cover part of the pension obligations payable to E.ON Energie employees. The claims of these employees at the point of retirement are covered to a certain extent by insurance contracts entered into with VKE. To improve overall coverage, E.ON made an additional contribution of €463 million in 2005.

In accordance with SFAS 71, assets that are subject to U.S. regulation are disclosed separately. For further information, please see Note 2.

Other operating assets include the positive fair values of derivative financial instruments of €7,349 million (2004: €3,007 million). The increase in the fair values of the derivatives is due to a combination of increasing volumes and higher market prices. Also included here are tax refund claims of €553 million (2004: €1,815 million). This line item further includes receivables related to E.ON Benelux’s cross-border lease transactions for power plants amounting to €1,011 million (2004: €900 million) and accrued interest receivables of €544 million (2004: €543 million). Also included in this line item is the €309 million (2004: €0 million) surplus of plan assets within the E.ON UK pension plans over the respective benefit obligations covered by the plans.

F-46

Valuation Allowances for Doubtful Accounts

The valuation allowances for doubtful accounts comprise the following for the periods indicated:


€ in millions	2005		2004

Balance as of January 1		431		463
Changes affecting income		34		(13	)
Changes not affecting income		58		(19	)

Balance as of December 31		523		431

Changes not affecting income are related to changes in the scope of consolidation, charges against the allowances and currency translation adjustments.


(14)	Investments in Short-Term Securities

The following table provides details of investments in short-term securities as of the dates indicated:


	December 31,

€ in millions	2005		2004

Deposits at banking institutions with an original maturity greater than 3 months		1,488		89
Securities with an original maturity greater than 3 months		9,218		7,751

Investments in short-term securities		10,706		7,840

Available-for-sale securities that management does not intend to hold long-term are classified as investments in short-term securities.

These securities’ amortized costs, fair values, gross unrealized gains and losses, as well as the maturities of fixed-term available-for-sale securities as of the dates indicated, break down as follows:

December 31, 2005

December 31, 2004

Gross

Amortized

Fair

unrealized

Amortized

Fair

unrealized

€ in millions

cost

value

loss

gain

cost

value

loss

gain

Fixed-term securities

Less than 1 year

406

433

165

168

—

Between 1 and 5 years

2,408

2,426

2,372

2,395

More than 5 years

2,689

2,797

111

2,359

2,413

Subtotal

5,503

5,656

162

4,896

4,976

124

Non-fixed-term securities

2,823

3,604

804

2,459

2,807

388

Total

8,326

9,260

966

7,355

7,783

512

F-47

The gross unrealized losses attributable to these short-term available-for-sale securities break down as follows:


	December 31, 2005

	less than				12 months
	12 months				or greater				Total

			Gross				Gross				Gross
	Fair		unrealized		Fair		unrealized		Fair		unrealized
€ in millions	value		loss		value		loss		value		loss

Fixed-term securities
Less than 1 year		309		1		—		—		309		1
Between 1 and 5 years		964		5		—		—		964		5
More than 5 years		357		3		—		—		357		3

Subtotal		1,630		9		—		—		1,630		9
Non-fixed-term securities		303		23		—		—		303		23

Total		1,933		32		—		—		1,933		32

In 2005, amortized costs were written down in the amount of €32 million (2004: €45 million).

The disposal of short-term marketable securities that management does not intend to hold long-term generated proceeds in the amount of €4,997 million (2004: €4,180 million). Realized net gains from such disposals in an amount of €395 million (2004: €206 million) were recorded in 2005. E.ON uses the specific identification method as a basis for determining cost and calculating realized gains and losses on such disposals.

Non-fixed-term securities classified as short-term include €39 million in non-marketable securities or investments (2004: €0 million).


(15)	Cash and Cash Equivalents

Cash and cash equivalents with an original maturity of less than three months include checks, cash on hand, and balances in Bundesbank accounts and at other banking institutions. Also included here are €42 million (2004: €32 million) in securities with an original maturity of less than three months.

Balances in bank accounts include €54 million (2004: €23 million) of collateral deposited at banks, the purpose of which is to prevent the exhaustion of credit lines in connection with the marking to market of derivatives transactions.

Also included in bank account balances are liquid funds in the amount of €44 million (2004: €40 million) that are subject to restricted access, of which €3 million must be considered as long-term restricted funds (2004: €12 million).


(16)	Prepaid Expenses and Deferred Income

Of the prepaid expenses totaling €356 million (2004: €344 million), €227 million (2004: €217 million) matures within one year. Deferred income totaled €817 million in 2005 (2004: €1,102 million), of which €202 million (2004: €194 million) matures within one year.


(17)	Capital Stock

The Company’s authorized capital stock of €1,799,200,000 remains unchanged and consists of 692,000,000 ordinary shares issued without nominal value. The number of outstanding shares as of December 31, 2005, totaled 659,153,552 (2004: 659,153,403; 2003: 656,026,401).

Pursuant to a shareholder resolution approved at the Annual Shareholders Meeting held on April 27, 2005, the Board of Management is authorized to buy back outstanding shares up to an amount of 10 percent of E.ON AG’s capital stock through October 27, 2006.

F-48

During 2005, E.ON AG purchased a total of 344,304 shares on the open market (2004: 212,135). Of these, 35,749 shares were designated as compensation for former shareholders. 308,704 (2004: 240,754) shares were distributed to employees. Thus, as of December 31, 2005, E.ON AG held a total of 4,374,254 (2004: 4,374,403) treasury shares having a book value of €256 million in the Consolidated Balance Sheet (equivalent to 0.6 percent or €11,373,060 of the capital stock). Please refer to Note 9 for further information on stock-based compensation.

As part of the voluntary share exchange offer made to shareholders of CONTIGAS, E.ON Energie bought 486,255 shares of E.ON AG, which it provided to CONTIGAS shareholders who tendered their shares in the exchange offer. The gain of approximately €3 million realized from this transaction is included in additional paid-in capital.

An additional 28,472,194 shares of E.ON AG are held by one of its subsidiaries as of December 31, 2005 (2004: 28,472,194). These shares held by subsidiaries were acquired at the time of the VEBA/ VIAG merger and considered treasury shares with no purchase price allocated to them.


	Authorized Capital

At the Annual Shareholders Meeting of April 27, 2005, the three authorizations for capital increases granted to the Board of Management at the Annual Shareholders Meeting of May 25, 2000, were rescinded. The Board had been authorized to increase the Company’s capital stock by up to €180 million (“Authorized Capital I”) through the issuance of new shares in return for cash contributions (with the option to restrict shareholders’ subscription rights) and to increase the Company’s capital stock by up to €180 million (“Authorized Capital II”) through the issuance of new shares in return for contributions in kind, excluding shareholders’ subscription rights. Following the capital increase in 2000, Authorized Capital II stood at €150.4 million. The Board had further been authorized to increase the Company’s capital stock by up to €180 million (“Authorized Capital III”) through the issuance of new shares in return for cash contributions (with the authorization to exclude shareholders’ subscription rights).

In place of these rescinded authorizations, 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 without nominal value in return for contributions in cash and/or in kind (with the option to restrict 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 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.


(18)	Additional Paid-in Capital

Additional paid-in capital results exclusively from share issuance premiums. As of December 31, 2005, additional paid-in capital amounts to €11,749 million (2004: €11,746 million). The increase of €3 million during 2005 is primarily a result of the execution of the exchange offer for minority shareholders of CONTIGAS.

The increase in 2004 from €11,564 million to €11,746 million resulted from the distribution of 3.1 million E.ON AG shares held by subsidiaries to minority shareholders.

F-49


(19)	Retained Earnings

The following table provides details of the E.ON Group’s retained earnings as of the dates indicated:

December 31,

€ in millions

2005

2004

2003

Legal reserves

Other retained earnings

25,816

19,958

16,931

Total

25,861

20,003

16,976

According to German securities law, E.ON AG shareholders can only receive distributions from the retained earnings of E.ON AG as defined by German GAAP, which are included in the Group’s retained earnings under U.S. GAAP. As of December 31, 2005, these German-GAAP retained earnings amount to €4,231 million (2004: €3,852 million). Of these, legal reserves of €45 million (2004: €45 million) pursuant to Article 150 (3) and (4) AktG and reserves for own shares of €257 million (2004: €257 million) pursuant to Article 272 (4) HGB were not distributable on December 31, 2005. Accordingly, an amount of €3,929 million (2004: €3,550 million) is in principle available for dividend payments.

The Group’s retained earnings as of December 31, 2005, include accumulated undistributed earnings of €617 million (2004: €692 million) from companies that have been accounted for under the equity method.


(20)	Other Comprehensive Income

The components of other comprehensive income and the related tax effects as of the dates indicated are as follows:


	December 31, 2005									December 31, 2004									December 31, 2003

				Tax									Tax									Tax
				benefit/									benefit/									benefit/
€ in millions	Before tax			(expense)			Net-of-tax			Before tax			(expense)			Net-of-tax			Before tax			(expense)			Net-of-tax

Foreign currency translation adjustments		536			78			614			139			(25	)		114			(701	)		(152	)		(853	)
Plus (Less) reclassification adjustments affecting income		6			—			6			11			—			11			71			3			74
Unrealized holding gains (losses) arising during period		5,709			(851	)		4,858			1,349			(243	)		1,106			1,282			(35	)		1,247
Plus (Less) reclassification adjustments affecting income		(169	)		9			(160	)		(107	)		(5	)		(112	)		(74	)		14			(60	)
Additional minimum pension liability		(580	)		268			(312	)		(935	)		337			(598	)		(156	)		65			(91	)
Cash Flow Hedges		65			(8	)		57			89			(33	)		56			224			(89	)		135

Total		5,567			(504	)		5,063			546			31			577			646			(194	)		452

The increase in unrealized gains from available-for-sale securities in 2005 was primarily attributable to an increase by €4,837 million (before tax) in the fair value of the investment in Gazprom.

The change in the minimum pension liability in 2005 is due primarily to the lowering of the discount rate. For additional information, see Note 22.

F-50


(21)	Minority Interests

Minority interests as of the dates indicated are attributable to the following segments:


	December 31,

€ in millions	2005		2004

Central Europe		2,618		2,096
Pan-European Gas		255		126
U.K.		81		92
Nordic		1,659		1,668
U.S. Midwest		85		103
Corporate Center		36		36

Core energy business		4,734		4,121
Other activities		—		23

Total		4,734		4,144

(22) Provisions for Pensions

E.ON and its subsidiaries maintain both defined benefit pension plans and defined contribution plans. Some of the latter are part of a multiemployer pension plan under EITF 90-3, “Accounting for Employers’ Obligations for Future Contributions to a Multiemployer Pension Plan,” for approximately 5,500 employees at the Nordic market unit.

Pension benefits are primarily based on compensation levels and years of service. Most Germany-based employees who joined the Company prior to 1999 participate in a final-pay arrangement, under which their retirement benefits depend in principle on their final salary (averaged over the last years of employment) and on years of service, but years of service beyond 2004 are now often no longer considered in these plans. Employees who joined the Company in or after 1999 and years of service beyond 2004 are mostly covered by a cash balance pension plan, under which regular payroll deductions are actuarially converted into pension units. To fund these defined benefit plans, the Company sets aside notional contributions and/or accumulates plan assets. For employees in defined contribution pension plans, under which the Company pays fixed contributions to an outside insurer or pension fund, the amount of the benefit depends on the value of each employee’s individual pension entitlement at the time of retirement from the Company.

Upon approval by the Supervisory Board on August 10, 2005, E.ON Pension Trust e.V. and Pensionsabwicklungstrust e.V. were formed, both with registered offices in Grünwald, Germany. The purpose of these trusts is the fiduciary administration of funds to provide for future retirement benefit payments to employees of German group companies (the so-called “CTA model”). The board resolution allows for a contribution of up to €5.4 billion; no contributions to the trusts had been made by the end of 2005. For details on the initial funding of €2.6 billion on March 8, 2006 please refer to Note 33.

The liabilities arising from the pension plans and their respective costs are determined using the projected unit credit method in accordance with SFAS 87. The valuation is based on current pensions and pension entitlements and on economic assumptions that have been chosen in order to reflect realistic expectations. Furthermore, cash balance pension plans are valued in accordance with EITF 03-4 (traditional unit credit method). The obligations arising primarily at U.S. companies from health-care and other post-retirement benefits for certain employees are calculated in accordance with SFAS 106.

The effective date for fixing the economic valuation parameter is December 31 of each year. The necessary calculation of the number of personnel, particularly in the group companies, takes place on September 30, with significant changes carried forward to December 31.

Actuarial gains and losses result from variations in valuation assumptions, differences between the estimated and actual number of beneficiaries and underlying assumptions. Under U.S. GAAP, they are recognized as

F-51

provisions for pensions on a delayed basis and amortized separately over periods determined for each individual pension plan.

The changes in the projected benefit obligation (“PBO”) are shown below. The disposal of Viterra (€228 million) and Ruhrgas Industries (€179 million) is mainly responsible for the change shown as “Change in scope of consolidation” in 2005. The acquisition of Midlands Electricity, which resulted in an increase of €1,390 million in related obligations, was mainly responsible for the change in that same category in 2004.


€ in millions	2005			2004

Projected benefit obligation as of January 1		15,918			13,295
Service cost		232			215
Interest cost		777			804
Change in scope of consolidation		(375	)		1,397
Prior service cost		32			6
Actuarial losses		1,618			1,182
Exchange rate differences		352			(144	)
Other		—			6
Pensions paid		(842	)		(843	)

Projected benefit obligation as of December 31		17,712			15,918

The amount disclosed for 2004 was not adjusted for discontinued operations in order to maintain comparability. Accordingly, this results in differences to the presentation of net periodic pension costs for 2004 on page F-54.

Of the entire benefit obligation, €187 million (2004: €210 million) is related to health-care benefits.

No significant effects resulted from the adoption of FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP No. 106-2”) in the third quarter of 2004.

The changes in plan assets are shown in the following table. The disposal of Viterra, which led to a reduction of €13 million in plan assets, and of Ruhrgas Industries, with a reduction in plan assets of €40 million, are mainly responsible for the change shown as “Change in scope of consolidation” in 2005. The full consolidation of Midlands Electricity resulted in an addition of €1,218 million in the same category in 2004.


€ in millions	2005			2004

Fair value of plan assets as of January 1		6,399			4,922
Actual return on plan assets		1,198			601
Company contributions		733			182
Employee contributions		17			16
Change in scope of consolidation		(58	)		1,220
Exchange rate differences		262			(97	)
Pensions paid		(451	)		(439	)
Other		(3	)		(6	)

Fair value of plan assets as of December 31		8,097			6,399

The company contributions include payments of €629 million to the E.ON Holding Group of the Electricity Supply Pension Scheme (ESPS) to facilitate the merger of the previously autonomous sections of E.ON UK covering Powergen, East Midlands Electricity, Midlands Electricity and TXU. The payment has covered a significant portion of the actuarial deficit in the E.ON UK pension plans and improved financing across all four sections.

For 2006, it is expected that the overall Company contribution to plan assets will consist of €87 million (2004: €54 million) to guarantee the minimum plan asset values stipulated by law or by-laws, and of €5.4 billion as part of the CTA funding. For details on the initial funding of €2.6 billion on March 8, 2006 please refer to Note 33.

F-52

In the E.ON Group, the vast majority of reported plan assets currently relates to the pension plans at the U.K. and U.S. Midwest market units. The investment objective for the pension plan assets is to provide full coverage of benefit obligations at all times for the corresponding pension plans.

The long-term investment strategy and the associated expected rate of return on plan assets for the various pension plans takes into consideration, among other things, the scope of the benefit obligations, the maturity structure, the minimum capital reserve requirements and, if applicable, other relevant factors. In 2005, the average rate of return on plan assets was 17.3 percent. This performance was above the expected rate of return of 6.7 percent, which is part of the net periodic pension costs.

The target portfolio structure was determined on the basis of current evaluations of the investment strategy and the market environment, and is reviewed on a regular basis and adjusted, if necessary, to reflect market trends. The current investment strategy is focused on equity securities, as well as on high-quality government bonds and selected corporate bonds. As of December 31, 2005, the percentage of overall plan assets consisting of equity securities had been further reduced.

The current allocation of plan assets to asset categories and the target portfolio structure are as follows:


			December 31,
	Target
in %	Allocation		2005		2004

Equity securities		22		45		51
Debt securities		69		48		42
Real estate		9		5		5
Other		—		2		2

Debt with remaining maturities from 0 to 49 years had an average weighted remaining maturity of 17.4 years on December 31, 2005. On December 31, 2004, the remaining terms ranged between 0 and 30 years, and the average weighted remaining maturity of the debt was 17.1 years.

The funded status — the difference between the PBO for all pension units and the fair value of plan assets — is reconciled with the provisions shown on the balance sheet as shown below:


	December 31,

€ in millions	2005			2004

Funded status		9,615			9,519
Unrecognized actuarial loss		(3,192	)		(2,453	)
Unrecognized prior service cost		(27	)		(27	)

Net amount recognized		6,396			7,039

The amounts recognized on the balance sheet are as follows:


	December 31,

€ in millions	2005			2004

Provisions for pensions		8,720			8,589
Additional minimum liability
Intangible assets		(29	)		(38	)
Accumulated other comprehensive income		(1,986	)		(1,512	)
Other operating assets		(309	)		—

Net amount recognized		6,396			7,039

The provisions for pensions reported for December 31, 2005, include €430 million (2004: €403 million) in short-term commitments, of which €32 million are attributable to the partial reversal of the additional minimum liability due to the planned CTA funding.

The accumulated benefit obligation for all defined benefit pension plans amounted to €16,475 million (2004: €14,878 million) on December 31, 2005.

Under U.S. GAAP, the additional minimum liability is recognized against “Intangible assets” and “Accumulated other comprehensive income,” and thus does not affect net income.

F-53

Provisions for pensions shown on the balance sheet as of December 31, 2005, particularly include obligations of U.S. companies arising from post-retirement health-care benefits in the amount of €153 million (2004: €181 million), with allowances made for increases in the costs of health-care benefits amounting to 10.0 percent in the short term and 5.0 percent in the long term.

The total net periodic defined benefit pension cost is detailed in the table below. Amounts for 2004 are adjusted to reflect effects of discontinued operations.


€ in millions	2005			2004			2003

Employer service cost		215			190			152
Interest cost		777			783			701
Expected return on plan assets		(448	)		(422	)		(327	)
Prior service cost		33			25			21
Net amortization of losses		85			40			23

Total		662			616			570

The net periodic pension cost shown includes an amount of €13 million in 2005 (2004: €17 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 +€0.6 million or - €0.5 million, respectively. The resulting accumulated post-retirement benefit obligation would change by +€8.8 million or -€7.8 million, respectively.

In addition to total net periodic pension cost, an amount of €54 million in 2005 (2004: €52 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.

Prospective undiscounted pension payments for the next ten years are shown in the following table:


€ in millions

2006			865
2007			889
2008			915
2009			939
2010			960
2011-2015			5,009

Total			9,577

The Company uses the 2005 revisions of the Klaus Heubeck biometric tables (“Richttafeln”) for the domestic pension liabilities, the industry standard for calculating company pension obligations in Germany.

The discount rate assumptions used by E.ON reflect the rates available for high-quality fixed-income investments during the period to maturity of the pension benefits in the respective market units at the end of the respective fiscal year.

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:


	December 31, 2005						December 31, 2004

			United		United				United		United
in %	Germany		Kingdom		States		Germany		Kingdom		States

Discount rate		4.00		4.80		5.50		4.75		5.30		5.75
Salary increase rate		2.75		4.00		5.25		2.75		4.00		4.50
Expected return on plan assets		4.00		5.50		8.25		4.75		6.70		8.25
Pension increase rate		1.50		2.80		—		1.25		2.80		—

F-54

(23) Other Provisions

Immediately below is a brief description of the asset retirement obligations in accordance with SFAS 143. The subsequent sections contain more detailed information about the other provisions as a whole.

Description of Asset Retirement Obligations

As of December 31, 2005, E.ON’s asset retirement obligations included:


	•	retirement costs shown in sub-items 1ab) and 1ba) for decommissioning of nuclear power plants in Germany in the amount of €8,400 million (2004: €8,204 million) and in Sweden in the amount of €403 million (2004: €404 million),

	•	environmental improvement measures reported under sub-item 8) related to the locations of non-nuclear power plants, including removal of electricity transmission and distribution equipment in the amount of €388 million (2004: €327 million) and

	•	environmental improvements at gas storage facilities in the amount of €90 million (2004: €77 million) and at opencast mining facilities in the amount of €61 million (2004: €59 million) as well as the decommissioning of oil and gas field infrastructure in the amount of €319 million (2004: €277 million). These obligations are also reported under sub-item 8).

The following table summarizes the changes in E.ON’s asset retirement obligations.


€ in millions	2005			2004

Balance as of January 1		9,348			9,269
Liabilities incurred in the current period		37			11
Liabilities settled in the current period		(181	)		(164	)
Change in scope of consolidation		33			2
Accretion expense		511			499
Revision in estimated cash flows		(126	)		(272	)
Other changes		39			3

Balance as of December 31		9,661			9,348

Interest resulting from the accretion of asset retirement obligations is shown in financial earnings (see Note 6).

Other Provisions

The following table lists other provisions as of the dates indicated:


		December 31,

€ in millions		2005		2004

Provisions for nuclear waste management (1)			13,362		13,481
	Disposal of nuclear fuel rods		5,003		5,370
	Asset retirement obligation (SFAS 143)		8,803		8,608
	Waste disposal		425		378
	less advance payments		869		875
Provisions for taxes (2)			3,000		2,871
Provisions for personnel costs (3)			1,540		1,611
Provisions for supplier-related contracts (4)			2,150		2,818
Provisions for customer-related contracts (5)			306		439
U.S. regulatory liabilities (6)			507		415
Provisions for environmental remediation (7)			309		337
Provisions for environmental improvements, including land reclamation (8)			1,725		1,657
Miscellaneous (9)			2,243		2,024

Total			25,142		25,653

F-55

As of December 31, 2005, €19,112 million of the above provisions are due after more than one year (2004: €19,142 million).

Of these other provisions, €14,457 million (2004: €14,512 million) bear interest.

1) Provisions for Nuclear Waste Management

a) Germany

Provisions for nuclear waste management comprise costs for the disposal of spent nuclear fuel rods, the retirement and decommissioning of nuclear and non-nuclear power plant components and the disposal of low-level nuclear waste.

The provisions for nuclear waste management stated above are net of advance payments of €869 million in 2005 (2004: €875 million). The advance payments are prepayments to nuclear fuel reprocessors and to other waste management companies, as well as to governmental authorities, relating to reprocessing of spent fuel rods and the construction of permanent storage facilities. Provisions for the costs of nuclear fuel rod disposal, of nuclear power plant decommissioning and of the disposal of low-level nuclear waste also include the costs for the permanent storage of radioactive waste.

Permanent storage costs include investment, operating and financing costs for the planned permanent storage facilities Gorleben and Konrad and are based on Germany’s ordinance on advance payments for the establishment of federal facilities for the safe custody and final storage of radioactive wastes (“Endlagervorausleistungsverordnung”) and on data from the German Federal Office for Radiation Protection (“Bundesamt für Strahlenschutz”). Each year the Company makes advance payments to the Bundesamt für Strahlenschutz.

In calculating the provisions for nuclear waste management, the Company has also taken into account the effects of the nuclear energy agreement reached by the German government and the country’s major energy utilities on June 14, 2000, and the related agreement signed on June 11, 2001.

aa) Management of Spent Nuclear Fuel Rods

The requirement for spent nuclear fuel reprocessing and disposal/storage is based on the German Nuclear Power Regulations Act (“Atomgesetz”). Operators may either reprocess or permanently store nuclear waste. The option to ship material for reprocessing ended on June 30, 2005; from now on, spent nuclear fuel rods will be disposed of exclusively through permanent storage.

There are contracts in place between E.ON Energie and two large European fuel reprocessing firms, BNFL in the U.K. and Cogema in France, for the reprocessing of spent nuclear fuel rods delivered through June 30, 2005, from its German nuclear plants. The radioactive waste that results from reprocessing will be returned to Germany to be temporarily stored in an authorized storage facility. Permanent storage is also expected to occur in Germany.

The provision for the unsettled reprocessing costs of spent nuclear fuel rods delivered through June 30, 2005, includes the costs for all components of the reprocessing requirements, particularly


	•	the costs of fuel reprocessing and

	•	the costs of outbound transportation and the intermediate storage of nuclear waste.

The cost estimates are based primarily on existing contracts.

Provisions for the costs of permanent storage of used fuel rods primarily include


	•	contractual costs for procuring intermediate containers and intermediate on-site storage on the plant premises and

	•	costs of transporting spent fuel rods to conditioning facilities, conditioning costs and costs for procuring permanent storage containers as determined by external studies.

F-56

The provision for the management of used fuel rods is provided over the period in which the fuel is consumed to generate electricity.

ab) Nuclear Plant Decommissioning

The obligation with regard to the nuclear portion of nuclear plant decommissioning is based on the aforementioned Atomgesetz, while the obligation for the non-nuclear portion depends upon legally binding civil agreements and public regulations, as well as other agreements.

The provision for the costs of nuclear plant decommissioning includes the expected costs for run-out operation, closure and maintenance of the facility, dismantling and removal of both the nuclear and non-nuclear portions of the plant, conditioning and temporary and final storage of contaminated waste. The expected decommissioning and storage costs are based upon studies performed by external specialists and are updated regularly.

ac) Waste from Plant Operations

The provision for the costs of the disposal of low-level nuclear waste covers all expected costs for the conditioning of low-level waste that is generated in the operation of the facilities.

b) Sweden

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 energy inspection authority 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 calculations are then submitted to government offices for approval. Upon approval, E.ON Sverige makes the corresponding payments.

ba) Decommissioning

Due to the adoption of SFAS 143 on January 1, 2003, an asset retirement obligation for decommissioning was recognized. Since in the past, fees have been paid to the national fund for nuclear waste management, a compensating receivable relating to these decommissioning costs was recorded under “Financial receivables and other financial assets” on January 1, 2003.

bb) Nuclear Fuel Rods and Nuclear Waste in Sweden

The required fees for high-level radioactive waste paid to the national fund for nuclear waste management are shown as an expense.

In the case of low-level and medium-level radioactive waste, a joint venture owned by Swedish nuclear power plant operators charges annual fees based on actual waste management costs. The Company records the corresponding payments to this venture as an expense.

c) United Kingdom and United States

Neither the U.K. nor the U.S. Midwest market unit operates any nuclear power plants. They are therefore not required to make payments or record liabilities similar to those described above with respect to Germany.

2) Taxes

Provisions for taxes relate primarily to domestic and foreign corporate income taxes due in the current year, and also to any tax obligations that might arise from preceding years. Tax obligations from preceding years consist of provisions for audit periods that are still open and relate primarily to the tax recognition of provisions for the disposal of radioactive waste in Germany. Tax provisions are generally calculated on the basis of the respective tax legislation of the countries in which E.ON operates, and due consideration is taken of all known circumstances.

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3) Personnel Liabilities

Provisions for personnel expenses primarily cover provisions for vacation pay, early retirement benefits, anniversary obligations, the stock option program and other deferred personnel costs.

4) Supplier-Related Liabilities

Provisions for supplier-related liabilities consist primarily of provisions for goods and services received but not yet invoiced and for potential losses from purchase obligations. Provisions for goods and services received but not yet invoiced represent obligations related to the purchase of goods that have been received and services that have been rendered, but for which an invoice has not yet been received.

5) Customer-Related Liabilities

Provisions for customer-related liabilities consist primarily of potential losses on open sales contracts. Also included are provisions for warranties, as well as for rebates, bonuses and discounts.

6) U.S. Regulatory Liabilities

Pursuant to SFAS 71 (see Note 2), liabilities that are subject to U.S. regulation are reported separately.

7) Environmental Remediation

Provisions for environmental remediation refer primarily to rehabilitating contaminated sites, redevelopment and water protection measures.

8) Environmental Improvements and Similar Liabilities, including Land Reclamation

Provisions for environmental improvements and similar liabilities primarily include asset retirement obligations pursuant to SFAS 143 in the amount of €858 million (2004: €740 million). Also included are provisions for reversion of title, other environmental improvements and reclamation liabilities.

In addition, there are certain individual conditional asset retirement obligations. The type, scope, timing and associated probabilities cannot be estimated reasonably, meaning that even the application of an expected present value technique would not produce reasonable estimates of fair values. According to FIN 47, no provisions are recognized for such circumstances.

9) Miscellaneous

Other provisions primarily include provisions arising from the electricity business, provisions for liabilities arising from the acquisition and disposal of companies, provisions from emissions trading systems and provisions for tax-related interest expenses.

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(24)	Liabilities

The following table provides details of liabilities as of the dates indicated:


		December 31, 2005										December 31, 2004

				With a remaining term										With a remaining term
				of										of
										Average										Average
										interest rate										interest rate
				up to		1 to 5		over		up to 1 year				up to		1 to 5		over		up to 1 year
€ in millions		Total		1 Year		Years		5 Years		(in %)		Total		1 Year		Years		5 Years		(in %)

Bonds (including Medium Term Note programs)			9,538		732		5,195		3,611		5.7		9,148		355		5,306		3,487		2.4
Commercial paper			—		—		—		—		—		3,631		3,631		—		—		2.1
Bank loans/ Liabilities to banks			1,530		424		729		377		5.0		4,130		1,010		1,506		1,614		3.7
Bills payable			42		—		42		—		—		51		3		48		—		2.6
Other financial liabilities			1,306		742		165		399		2.7		1,648		155		547		946		4.4

Financial liabilities to banks and third parties			12,416		1,898		6,131		4,387				18,608		5,154		7,407		6,047

Financial liabilities to affiliated companies			134		128		—		6		3.1		134		128		—		6		2.5
Financial liabilities to associated companies and other share investments			1,812		1,781		12		19		4.4		1,834		1,754		20		60		3.5

Financial liabilities to group companies			1,946		1,909		12		25				1,968		1,882		20		66

Financial liabilities			14,362		3,807		6,143		4,412				20,576		7,036		7,427		6,113

Accounts payable			5,288		5,272		16		—				3,662		3,627		35		—
Operating labilities to affiliated companies			105		59		3		43				147		103		—		44
Operating liabilities to associated companies and other share investments			188		98		70		20				184		92		71		21
Capital expenditure grants			270		19		96		155				271		26		93		152
Construction grants from energy consumers			3,674		420		736		2,518				3,558		347		692		2,519
Advance payments			488		488		—		—				725		722		3		—
Other operating liabilities			9,039		6,946		668		1,425				5,507		3,793		323		1,391
	thereof taxes		614		614								989		989
	thereof social security contributions		63		63								62		62

Operating liabilities			19,052		13,302		1,589		4,161				14,054		8,710		1,217		4,127


Liabilities			33,414		17,109		7,732		8,573				34,630		15,746		8,644		10,240

Up to December 31, 2004, liabilities of Viterra were reported net of the interest portion of non-interest-bearing and low-interest liabilities in the Consolidated Balance Sheet and totaled €34,355 million. The interest portion amounted to €275 million. Due to the disposal of Viterra in 2005 (see Note 4), no deduction of the interest portion was reported as of December 31, 2005.

Financial Liabilities

The following is a description of the E.ON Group’s significant credit arrangements and debt issuance programs. Outstanding amounts under credit lines and bank loans are disclosed in the table above as “Bank loans/ Liabilities to banks.” Issuances under a Medium Term Note program (“MTN program”) and issuances of commercial paper are disclosed in the corresponding line item.

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These financing arrangements contain affirmative and negative covenants and provide for various events of default that are generally in line with industry standard terms for similar borrowings. In general, E.ON’s most significant financial arrangements do not include financial covenants such as ratio compliance tests or a rating trigger, though a number do include restrictions on certain types of transactions and negative pledges, while others include material adverse change clauses relating to the relevant borrower. The following description of each of the Group’s most significant individual financing arrangements includes disclosures of financial covenants or cross-default clauses contained in those arrangements that were in effect as of December 31, 2005. E.ON and its subsidiaries were in compliance with all such covenants as of December 31, 2005 and 2004, and no cross-default clauses had been triggered as of such dates.

In addition, E.ON has numerous additional financing arrangements that are not individually significant and that are summarized below grouped by segment and type of arrangement. These other arrangements also include affirmative and negative covenants and provide for various events of default that are generally in line with industry standard terms for similar borrowings. Certain of these arrangements also include financial covenants, including requirements to maintain certain ratios. Certain arrangements also include material adverse change clauses, as well as restrictions on certain types of transactions and negative pledges. E.ON and its subsidiaries were in compliance with all such covenants as of December 31, 2005 and 2004, and no cross-default clauses had been triggered as of such dates.

The failure of E.ON or the relevant borrower to comply with any of the identified covenants or the triggering of any cross-default clauses could result in any and all of the following:


	•	the repayment of the affected financing arrangement

	•	the declaration that a liability becomes due and payable before its stated maturity

	•	the triggering of cross defaults in other financing arrangements

	•	E.ON’s access to additional financing on favorable terms being severely curtailed or even eliminated

Corporate Center

€20 billion Medium Term Note Program

The existing €20 billion MTN program allows E.ON AG and its wholly owned subsidiaries E.ON International Finance B.V. (“E.ON International Finance”), Rotterdam, The Netherlands, and E.ON UK Finance plc (“E.ON UK Finance”), Coventry, U.K., under the unconditional guarantee of E.ON AG, to periodically issue debt instruments through syndicated and private placements to investors. On May 17, 2002, E.ON issued its first-ever multi-currency bond in euros and pounds sterling (“GBP”) on the international bond markets. At year-end 2005, the following bonds were outstanding:


	•	€4.25 billion issued by E.ON International Finance with a coupon of 5.75 percent and a maturity in May 2009

	•	€0.9 billion issued by E.ON International Finance with a coupon of 6.375 percent and a maturity in May 2017

	•	GBP 500 million or €725 million issued by E.ON International Finance with a coupon of 6.375 percent and a maturity in May 2012

	•	GBP 0.975 billion or €1.37 billion issued by E.ON International Finance with a coupon of 6.375 percent and a maturity in June 2032

Neither the MTN program nor any of the bonds outstanding at the end of 2005 or 2004 contain any financial covenants. The MTN program documentation, as well as the bonds issued under the program, both contain the same cross-default clause. A cross default would be triggered if any creditor is entitled to declare that any such indebtedness is payable before its stated maturity by reason of an event of default or if an issuer or the guarantor under the program fails to pay indebtedness for borrowed money or any amount payable under any guarantee in

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respect of such indebtedness (cross payment default). A cross default would only occur if the aggregate amount of such indebtedness exceeds €25 million.

€10 billion Commercial Paper Program

The existing €10 billion commercial paper program allows E.ON AG and the wholly owned subsidiaries E.ON International Finance and E.ON UK Finance, under the unconditional guarantee of E.ON AG, to periodically issue commercial paper with maturities of up to 729 days to investors. Proceeds from these offerings may be used for general corporate purposes. The commercial paper program does not contain any financial covenants. A cross default would be triggered if any creditor is entitled to declare that any such indebtedness is payable before its stated maturity by reason of an event of default or if an issuer or the guarantor under the program fails to pay indebtedness for borrowed money or any amount payable under any guarantee in respect of such indebtedness (cross payment default). A cross default would only occur if the aggregate amount of such indebtedness exceeds €30 million. As of December 31, 2005, no commercial paper was outstanding under the program (2004: €3.4 billion), leaving the full amount available.

€10 billion Syndicated Multi-Currency Revolving Credit Facility Agreement

Under the existing €10 billion revolving credit facility, E.ON AG and its subsidiaries E.ON Finance GmbH, Düsseldorf, Germany, E.ON International Finance and E.ON UK Finance (each under the unconditional guarantee of E.ON AG, collectively “the borrowers”) may make borrowings in various currencies in an aggregate amount of up to €10 billion. The facility is divided into Tranche A, a revolving credit facility in the amount of €5 billion, and Tranche B, a revolving credit facility also in the amount of €5 billion. Amounts raised under Tranche A may be used for general corporate purposes, and amounts raised under Tranche B may be used for the refinancing of existing credit facilities, for liquidity back-up and for other general corporate purposes. Tranche A has an initial maturity of 364 days but includes both an extension option and a term-out option of 364 days each. Tranche B has a maturity of 5 years but includes an extension option which allows for two extensions each of one year. The extension option may only be exercised at the end of year 1 and/or at the end of year 2. On October 17, 2005, both the extension option for Tranche A and Tranche B were exercised, and as a result, Tranche A was extended to November 30, 2006, and Tranche B was extended to December 2, 2010. On November 28, 2005, an Amendment Agreement was signed to reduce commitment fees and margin with effect on December 1, 2005. Drawings under Tranche A now bear interest equal to EURIBOR or LIBOR for the respective currency plus a margin of 12.5 basis points (down from 15 basis points) and drawings under Tranche B bear interest equal to EURIBOR or LIBOR for the respective currency plus a margin of 15 basis points (down from 20 basis points). A cross default would be triggered by the declaration of financial indebtedness of any material subsidiary or any of the borrowers to be due and payable prior to its specified maturity pursuant to the occurrence of an event of default (cross acceleration default) and by non-payment of any financial indebtedness of any material subsidiary or any of the borrowers when due or after any applicable grace period (cross payment default). These cross defaults would only occur if the aggregate amount of all such financial indebtedness is more than €100 million (or its equivalent in any other currency or currencies). The material subsidiaries pursuant to this agreement are E.ON Energie AG, E.ON UK plc, E.ON U.S. LLC, E.ON Ruhrgas AG and any other member of the Group whose total assets or revenues exceed 10 percent of the total assets or revenues of the E.ON Group. As of December 31, 2005, there were no borrowings outstanding under this facility (2004: €0 million).

The E.ON AG syndicated credit facility contains no financial covenants, nor does it provide for a rating trigger.

Bilateral Credit Lines

At year-end 2005, E.ON AG had committed short-term credit lines of €180 million (2004: €180 million) with maturities of up to one year and variable interest rates of up to 25 basis points above EURIBOR. These credit lines may be used for general corporate purposes. In addition, E.ON AG had several uncommitted short-term credit lines. E.ON AG had no outstanding balances under this line at the end of 2005 and 2004.

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As of December 31, 2005, E.ON North America Inc. (“E.ON North America”), New York, U.S., a wholly-owned subsidiary of E.ON AG, had an USD 50 million credit facility. This is an overdraft loan facility to be used for short-term overnight general corporate use. The rate charged on the daily loan balance is 8 basis points over the Federal Funds Rate. There was no outstanding balance under this line at the end of 2005 and 2004.

None of these bilateral credit lines include financial covenants, nor do they provide for cross defaults or a rating trigger.

Central Europe

Bank Loans, Credit Facilities

As of December 31, 2005, the Central Europe market unit had committed credit lines of €348 million (2004: €491 million). The credit lines may be used for general corporate purposes. In particular, they serve as back-up facilities for letters of credit and bank guarantees. In addition, Central Europe had uncommitted short-term credit lines with various banks. Under the credit lines, €180 million was outstanding at year-end 2005 (2004: €181 million). Most of the credit lines do not have a specific maturity. Interest rates for unanticipated drawdowns of facilities reach up to 3 percent. Planned use of the facilities is subject to interest at variable money-market rates plus a margin of up to 47.5 basis points.

Bank loans have been used by the Central Europe market unit primarily to finance specific projects or investment programs and include subsidized credit facilities from national and international financing institutions. Bank loans (including short-term credit lines) amounted to €1,109 million as of December 31, 2005 (2004: €1,216 million).

Pan-European Gas

Long-Term Loans

In March 1999, E.ON Ruhrgas obtained four long-term bilateral loans from banks bearing fixed interest rates in the aggregate amount of €280 million with maturities of 5 to 15 years and repayable at maturity. The entire amount of €140 million outstanding under the loans as of December 31, 2004, was repaid prior to maturity during 2005. The corresponding loss on extinguishment totaled €18 million. The interest rates for these loans varied between 3.75 and 5.068 percent.

In addition, in the period from 1997 to 2003, Pan-European Gas subsidiary Ferngas Nordbayern GmbH obtained long-term loans from banks totaling €84 million. The loans each have a maturity of up to 10 years with annual or quarterly repayments. The outstanding amount as of December 31, 2005, was approximately €15 million (2004: €21 million). The interest rates for these loans varied between 4.1 and 5.98 percent (on average, about 5.06 percent).

U.K.

Bonds

Following the acquisition of the Midlands Electricity group of companies in January 2004, E.ON UK plc assumed responsibility for the liabilities of the acquired companies that were outstanding at the time of the acquisition. In the following, these liabilities are referred to as “the Midlands Debt.”

During the first half of 2004, a portion of the outstanding bonds issued by E.ON UK plc and its subsidiaries were purchased by other E.ON Group companies following an offer to tender. Consequently, as of December 31, 2005, only a portion of the bonds still outstanding were held by investors external to the E.ON Group, as detailed below:


	•	GBP 250 million or €362 million bond issued by E.ON UK plc with a coupon of 8.5 percent maturing in July 2006, of which GBP 44 million or €62 million was held by external investors

	•	GBP 250 million or €362 million bond issued by E.ON UK plc with a coupon of 6.25 percent maturing in April 2024, of which GBP 8 million or €11 million was held by external investors

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	•	GBP 150 million or €217 million issued by Central Networks plc (previously Midlands Electricity plc, a wholly-owned subsidiary of E.ON UK plc) with a coupon of 7.375 percent maturing in November 2007 (part of the Midlands Debt), of which GBP 0.4 million or approximately €0.6 million was held by external investors

	•	€500 million Eurobond issued by E.ON UK plc with a coupon of 5.0 percent maturing in July 2009, of which €264 million was held by external investors

	•	USD 410 million or €347 million Yankee Bond issued by Powergen (East Midlands) Investments, London, U.K., with a coupon of 7.45 percent maturing in May 2007, of which USD 173 million or €147 million was held by external investors

Each of these bonds includes covenants providing for a negative pledge and restrictions on sale and lease-back transactions. Each also includes a cross-default clause that would be triggered by a non-payment of principal, premium or interest on any obligation of the issuer, E.ON UK plc or any of its subsidiaries, with the threshold amounts ranging from GBP 10 million to GBP 50 million.

Nordic

E.ON Sverige Medium Term Note Program

A domestic MTN program was established by Sydkraft, now E.ON Sverige, in 1999 and was increased in 2003 to a maximum allowed outstanding amount of SEK 13 billion. The facility is renewed every year and allows for borrowings in various currencies with a maturity of up to 15 years with various interest rate structures. The program does not include any financial covenants but does contain a cross-default clause which would be triggered by a default of E.ON Sverige or any of its subsidiaries on financial indebtedness in the amount of SEK 10 million or more. The outstanding amount as of December 31, 2005, was SEK 6,601 million or €703 million (2004: SEK 4,458 million or €494 million).

E.ON Sverige Commercial Paper Programs

Established in 1990, the domestic commercial paper program of Sydkraft, now E.ON Sverige, was increased in 1999 to a maximum allowed outstanding amount of SEK 3 billion. Borrowings can be made for terms of up to 360 days. The outstanding amount as of December 31, 2005, was SEK 0 million or €0 million (2004: SEK 1,500 million or €166 million).

A Euro commercial paper program was established by Sydkraft, now E.ON Sverige, in 1990 with a maximum allowed outstanding amount of USD 200 million. Borrowings can be made in various currencies for terms of up to 360 days. The outstanding amount as of December 31, 2005, was €0 million (2004: €61 million).

None of these commercial paper programs include any financial covenants or cross-default clauses.

Bank Loans, Credit Facilities

E.ON Sverige has obtained bilateral loans from credit institutions at variable money-market rates, with floating rate spreads of 21.5 and 42.5 basis points over the Stockholm Interbank Offered Rate (STIBOR), and maturities of up to ten years. As of December 31, 2005, the aggregate amount outstanding was SEK 1,349 million or €144 million (2004: SEK 2,269 million or €252 million). These loans have mainly been used to finance specific investments.

U.S. Midwest

Bonds and Medium Term Note Programs

E.ON U.S. Capital Corp. (“E.ON U.S. Capital”), Louisville, Kentucky, U.S., has an MTN program under which it was authorized to issue initially up to USD 1.05 billion in bonds. Amounts repaid may not be reborrowed. As of December 31, 2005, the amount outstanding under the program was USD 300 million or €254 million (2004: USD 300 million or €221 million), leaving USD 400 million available for future issuance.

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The average interest rate for issues under this program for 2005 was 6.97 percent with maturities ranging from 2008 to 2011.

The E.ON U.S. Capital MTN program requires E.ON U.S. to maintain ownership of at least 80 percent of E.ON U.S. Capital and 100 percent of Louisville Gas and Electric Company (“LG&E”), Louisville, Kentucky, U.S. The program also requires E.ON U.S. Capital to maintain tangible net worth of at least USD 25 million, and prohibits liens on the shares of LG&E and E.ON U.S. Capital. Additionally, the program limits the use of sale and leaseback transactions. Any default on debt of the subsidiaries of E.ON U.S. Capital in excess of USD 15 million or a default by LG&E or E.ON U.S. in excess of USD 25 million causes a default of the MTN program.

In addition, as of December 31, 2005, bonds in the amount of USD 574 million or €486 million (2004: USD 574 million or €422 million) were outstanding at LG&E and bonds in the amount of USD 362 million or €307 million (2004: USD 385 million or €283 million) were outstanding at Kentucky Utilities Company (“Kentucky Utilities”), Lexington, Kentucky, U.S., with fixed interest rates as well as with variable interest rates. Fixed rate bonds range from 5.90 percent to 7.92 percent, the average interest rate on the variable rate bonds was less than 2.60 percent in 2005. On the LG&E bonds, maturities range from 2013 to 2035, and on the Kentucky Utilities bonds, maturities range from 2006 to 2035. The LG&E and Kentucky Utilities bonds are collateralized by a lien on substantially all of the assets of the respective companies.

Bilateral Credit Lines, Bank Loans

LG&E has five revolving lines of credit with banks totaling USD 185 million or €157 million. These credit facilities expire in June 2006, and there was no outstanding balance under any of these facilities on December 31, 2005 (2004: €0 million).

These revolving lines of credit include financial covenants, in particular that LG&E’s debt/total capitalization ratio must be less than 70 percent and that E.ON AG must own at least two thirds of voting stock of LG&E directly or indirectly. Furthermore, the corporate credit rating of LG&E must be at or above BBB- and Baa3 and LG&E may not dispose of assets aggregating more than 15 percent of its total assets. Each of the credit lines contains a cross-default provision that causes the LG&E bilateral line of credit to be in default if LG&E is in default on other debt in excess of USD 25 million.

As of December 31, 2005, E.ON’s financial liabilities to banks and third parties had the following maturities:


	Repayment		Repayment		Repayment		Repayment		Repayment		Repayment
€ in millions	2006		2007		2008		2009		2010		after 2010		Total

Bonds (including MTN programs)		732		219		283		275		4,418		3,611		9,538
Commercial paper		—		—		—		—		—		—		—
Bank loans/ Liabilities to banks		424		183		116		74		356		377		1,530
Bills payable		—		40		2		—		—		—		42
Other financial liabilities		742		39		99		24		3		399		1,306

Financial liabilities to banks and third parties		1,898		481		500		373		4,777		4,387		12,416


Used credit lines		93		14		14		—		8		52		181
Unused credit lines		5,597		—		—		—		5,000		122		10,719

Used and unused credit lines		5,690		14		14		—		5,008		174		10,900

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The following table shows the interest rates for the Company’s financial liabilities to banks and third parties:


	December 31, 2005

€ in millions	0 - 3%		3.1 - 7%		7.1 - 10%		more than 10%		Total

Bonds (including MTN programs)		571		8,624		343		—		9,538
Commercial paper		—		—		—		—		—
Bank loans/ Liabilities to banks		765		762		3		—		1,530
Bills payable		—		42		—		—		42
Other financial liabilities		161		1,124		4		17		1,306

Financial liabilities to banks and third parties		1,497		10,552		350		17		12,416

The following table provides details of the Company’s liabilities due to banks as of the dates indicated:


	December 31,

€ in millions	2005		2004

Bank loans collateralized by mortgages on real estate		141		1,147
Other collateralized bank loans		51		805
Uncollateralized bank loans, drawings on credit lines, short-term loans		1,338		2,178

Total		1,530		4,130

Collateralized liabilities to banks totaled €192 million as of December 31, 2005 (2004: €1,952 million), including €0 million (2004: €278 million) that are non-interest-bearing or bear interest rates below market rates.

In 2004, bank loans that bear interest below market rates had been granted mainly to Viterra for financing residential rental real estate. In return, occupancy rights and/or rents below the prevailing market rates were offered to the lender. Due to these conditions, such loans appeared at present value on the balance sheet in 2004. Due to the disposal of Viterra in 2005, no such loans are recorded in the Consolidated Balance Sheet as of December 31, 2005. Financial liabilities include non-interest-bearing and low-interest liabilities in the amount of €26 million in 2005 (2004: €566 million).

In November 2005, E.ON Ruhrgas issued Loan Notes in connection with the acquisition of Caledonia for an amount of approximately GBP 402 million, or €595 million, with a contractual maturity of eighteen months, which may be redeemed after one year. A large portion of these Loan Notes (approximately GBP 365 million or €528 million) was converted into USD Loan Notes (approximately USD 636 million). The coupon is based on LIBOR. As of December 31, 2005, €545 million of these Loan Notes are shown under “Other financial liabilities.” €49 million of the Loan Notes issued were assigned to banks in 2005 and are disclosed as “Bank loans/ Liabilities to banks” at year-end 2005.

Operating Liabilities

Capital expenditure grants of €270 million (2004: €271 million) are paid primarily by customers in the core energy business 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.

Construction grants of €3,674 million (2004: €3,558 million) are paid by customers of the core energy business for costs of connections according to the generally binding linkup terms. 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 primarily include the negative fair values of derivative financial instruments of €5,761 million (2004: €1,773 million), E.ON Benelux’s cross-border lease transactions for power plants amounting to €1,011 million (2004: €900 million) and accrued interest payable of €638 million (2004: €694 million).

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(25) Contingencies and Commitments

E.ON is subject to contingencies and commitments involving a variety of matters, including different types of guarantees, litigation and claims (as discussed in Note 26), long-term contractual and legal obligations and other commitments.

Financial Guarantees

Financial guarantees include both direct and indirect obligations (indirect guarantees of indebtedness of others). These require the guarantor 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 the equity of the guaranteed party.

The Company’s financial guarantees include nuclear-energy-related items. Obligations also comprise direct financial guarantees to creditors of related parties and third parties. Direct financial guarantees with specified terms extend as far as 2022. Maximum potential undiscounted future payments could total up to €427 million (2004: €737 million). €304 million of this amount involves guarantees issued on behalf of related parties (2004: €534 million). Indirect guarantees primarily include obligations in connection with cross-border lease transactions and obligations to provide financial support to primarily related parties. Indirect guarantees have specified terms up to 2023. Maximum potential undiscounted future payments could total up to €431 million (2004: €459 million). €67 million of this amount involves guarantees issued on behalf of related parties (2004: €162 million). The Company has recorded provisions of €25 million (2004: €98 million) as of December 31, 2005, with respect to financial guarantees. In addition, E.ON has commitments under which it assumes joint and several liability arising from its stakes in the civil-law companies (“GbR”), non-corporate commercial partnerships and consortia in which it participates.

Several subsidiaries have certain obligations that are based on their membership in VKE in accordance with the articles of incorporation. It is not expected that any claims will arise in respect of these obligations.

With the entry into force of the Atomgesetz, as amended, and of the ordinance regulating the provision for coverage under the Atomgesetz (“Atomrechtliche Deckungsvorsorge-Verordnung” or “AtDeckV”), as amended, on April 27, 2002, 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.

To provide liability coverage for the additional €2,244.4 million per incident required by the above-mentioned amendments, E.ON Energie 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 43.0 percent (2004: 43.0 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 with the operation of those facilities. As of December 31, 2005, the liability was limited to SEK 3,401 million or €362 million, per incident (2004: SEK 3,076 million or €341 million), which amount must be insured according to the Law Concerning Nuclear

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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 nuclear obligations. It is at present unclear to what extent this review will lead to an adjustment of the nuclear liability limit in Sweden.

Neither the U.K. nor the U.S. Midwest market unit operates nuclear power plants; they therefore do not have comparable contingent liabilities.

Indemnification Agreements

Contracts in connection with the disposal of shareholdings concluded throughout the Group include indemnification agreements and other guarantees with terms up to 2041 in accordance with contractual arrangements and local legal requirements, unless shorter terms were contractually agreed. The maximum undiscounted amounts potentially payable in respect of the circumstances expressly set forth in these agreements could total up to €6,623 million (2004: €4,602 million). The indemnities (“Freistellungen”) typically relate to customary representations and warranties, environmental damages and taxes. In some cases the buyer is required to either share costs or cover a certain amount of costs before the Company is required to make any payments. Some obligations are to be covered first by insurance contracts or provisions of the disposed companies. The Company has recorded provisions of €296 million (2004: €86 million) as of December 31, 2005, with respect to all indemnities and other guarantees included in sales agreements. 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 final sales contracts in the form of indemnities.

Other Guarantees

Other guarantees with an effective period through 2020 consist primarily of market value guarantees and warranties (maximum potential undiscounted future payments of €130 million). Product warranties, for which provisions of €25 million had been established as of December 31, 2004, no longer exist as of December 31, 2005, due to the disposal of Viterra and Ruhrgas Industries in 2005, and the corresponding provisions have been eliminated.

Long-Term Obligations

As of December 31, 2005, the principal long-term contractual obligations in place relate to the purchase of fossil fuels such as gas, lignite and hard coal.

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 used to perform the calculations.

The increase of contractual obligations in place for the purchase of gas are mainly due to the higher purchasing costs of gas in 2005, which led to an adjustment of planning assumptions.

The contractual obligations in place for the purchase of electricity relate especially to purchases from jointly operated power plants. 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 storage of spent fuel elements delivered through June 30, 2005.

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Other financial obligations amount to €4,299 million (2004: €4,093 million). They primarily consist of obligations for the acquisition of investments.

There is a put option agreement in place since October 2001 allowing a minority shareholder of E.ON Sverige to exercise its right to sell its remaining stake for approximately €2 billion. In 2003, the term of this option was extended to 2007.

The Central Europe market unit has entered into put option agreements related to various acquisitions that allow other shareholders to exercise rights to sell their remaining stakes for an aggregate total of approximately €1.1 billion.

As of December 31, 2005, the Nordic market unit is a party to a put option agreement which, if exercised, would lead to the acquisition by that market unit of additional shares in E.ON Finland. For additional information about E.ON Finland, please see Note 33.

A CTA with a funding volume of up to €5.4 billion will be established in the E.ON Group in order to cover existing pension obligations. This amount is not included in the table below.

Expected payments arising from long-term obligations totaled €181,134 million on December 31, 2005, and are as follows:


€ in millions	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years

Natural gas		164,634		15,292		26,565		34,835		87,942
Oil		—		—		—		—		—
Coal		2,889		1,135		1,099		485		170
Lignite and other fossil fuels		1,089		33		66		66		924

Total fossil fuel purchase obligations		168,612		16,460		27,730		35,386		89,036

Electricity purchase obligations		4,228		1,231		915		515		1,567
Other purchase obligations		1,024		208		238		135		443

Total long-term purchase commitments/obligations		173,864		17,899		28,883		36,036		91,046

Major repairs		19		14		5		—		—
Environmental protection measures		29		3		5		3		18
Other (including capital expenditure commitments)		1,791		647		416		263		465

Total other purchase commitments/obligations		1,839		664		426		266		483

Other financial obligations		4,299		237		3,681		205		176

Loan commitments		1,132		364		193		14		561

Total		181,134		19,164		33,183		36,521		92,266

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Rental, Tenancy and Lease Agreements

Nominal values of other commitments arising from rental, tenancy and lease agreements are due as follows:


€ in millions

2006			136
2007			121
2008			107
2009			65
2010			69
Thereafter			236

Total			734

Expenses arising from such contracts reflected in the Consolidated Statements of Income amounted to €102 million in 2005 (2004: €71 million; 2003: €63 million).

(26) Litigation and Claims

Various legal actions, including lawsuits for product liability or for alleged price-fixing agreements, governmental investigations, proceedings and claims are pending or may be instituted or asserted in the future against the Company. This in particular includes arbitration proceedings against E.ON Nordic (for further information see Note 33), as well as lawsuits against E.ON AG and U.S. subsidiaries in connection with the disposal of VEBA Electronics in 2000. 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.

In the wake of the various corporate restructurings of the past several years, shareholders have filed a number of claims (“Spruchstellenverfahren”). The claims contest the adequacy of share exchange ratios or cash settlements paid to former shareholders of the acquired companies. The claims impact the Central Europe and Pan-European Gas market units, as well as the VEBA-VIAG merger itself. Because the share exchange ratios and settlements were determined by outside experts and reviewed by other auditing firms, E.ON believes that the exchange ratios and settlements are correct.

The U.S. Securities and Exchange Commission (“SEC”) has requested that E.ON provide it with information for an investigation focusing in particular on the preparation of its financial statements for the fiscal years 2000 through 2003, including the accounting treatment and depreciation of its power plant assets, its accounting for and consolidation of former subsidiaries (Degussa and Viterra) and their shareholdings, the nature of the services performed by the independent public accountants appointed by E.ON, disclosures with regard to the Company’s long-term fuel procurement contracts, and its 2002 Annual Report on Form 20-F, in particular the process of its preparation and its conformity with U.S. GAAP. E.ON is in close contact with the SEC and will cooperate fully. A similar request that also covers additional items, including aspects of E.ON’s 2003 Annual Report on Form 20-F, has been made to the independent public accountants appointed by E.ON.

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(27)	Supplemental Disclosure of Cash Flow Information

The following table indicates supplemental disclosures of cash flow information:


€ in millions		2005		2004		2003

Cash paid during the year for
	Interest, net of amounts capitalized		966		1,101		1,082
	Income taxes, net of refunds		1,059		1,360		1,022
Non-cash investing and financing activities
	Increase of stakes in subsidiaries in exchange for distribution of E.ON AG shares to minority shareholders		35		182		153
	Loan notes issued in lieu of cash purchase price payments for Caledonia		595		—		—
	Exchange and contribution of assets as part of acquisitions		171		—		—

The deconsolidation of shareholdings and operations resulting from divestments led to reductions of €7,160 million (2004: €231 million; 2003: €13,153 million) related to assets and €4,510 million (2004: €186 million; 2003: €11,306 million) related to provisions and liabilities. Cash and cash equivalents divested herewith amounted to €45 million (2004: €19 million; 2003: €214 million).

In 2005, cash provided by operating activities increased significantly over the preceding year. The increase was due primarily to changes in tax payments, and in particular to the change in the VAT treatment of gas transactions in the Pan-European Gas market unit. Other positive influences were provided by higher prepayments by customers in December at the Pan-European Gas market unit, the increase in gross margin at the Central Europe market unit and by effects resulting from the elimination of currency swaps in the Corporate Center. These improvements were partly offset by pension fund contributions at the U.K. market unit, increased contributions to the VKE fund at the Central Europe market unit and storm damage payments at the Nordic market unit. In 2004, cash provided by operating activities increased over the preceding year, this was due entirely to developments in the core energy business. The principal contributors to this increased cash flow were the U.K. and Nordic market units, particularly through the consolidation of Midlands Electricity and Graninge, price adjustments in the retail sector, and reductions of net working capital. In addition, certain one-time events that negatively affected cash flow in 2003 did not recur.

Cash provided by investing activities was positive in 2005. In particular, the sale of Viterra and Ruhrgas Industries generated large positive cash flows. Investments in property, plant and equipment, particularly power plants and grids, were higher than in 2004. However, because payments for acquisitions declined markedly, net investment by the Group actually declined.

The marked reduction of financial debts and higher dividend distributions are reflected in the negative cash flow from financing activities.

Purchase prices for acquisitions of subsidiaries totaled €1,336 million (2004: €1,004 million; 2003: €5,531 million). In 2005, this includes the loan notes issued in lieu of cash purchase price payments for the €595 million acquisition of Caledonia. Cash and cash equivalents acquired in connection with the acquisitions amounted to €275 million (2004: €110 million; 2003: €352 million). The purchases resulted in assets amounting to €3,892 million (2004: €2,680 million; 2003: €21,321 million) and in provisions and liabilities totaling €1,922 million (2004: €2,569 million; 2003: €9,806 million).

The presentation of Consolidated Statement of Cash Flows for 2004 and 2003 has been revised to provide additional information for cash flows from operating, investing and financing activity of discontinued operations.


(28)	Derivative Financial Instruments and Hedging Transactions

Strategy and Objectives

During the normal course of business, the Company is exposed to foreign currency risk, interest rate risk and commodity price risk. 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 eliminate or limit these risks.

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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.

E.ON AG has enacted general risk management guidelines for the use of derivative interest and foreign currency instruments as well as for commodity risk management that constitute a comprehensive framework for the entire Group. The market units have also adopted specific risk management guidelines to manage the appropriate risks arising from their respective activities. The market units’ guidelines operate within the general risk management guidelines of E.ON AG. As part of the Company’s framework for interest rate, foreign currency and commodity risk management, an enterprise-wide reporting system is used to monitor each reporting unit’s exposures to these risks and their long-term and short-term financing needs. The creditworthiness of counterparties is monitored on a regular basis.

Commodity derivatives are subject to the specific market unit’s risk management guidelines. The market units involved in such activities enter into commodity derivatives for price risk management, system optimization, load balancing and margin improvement. Any use of derivatives is only allowed within limits established and monitored by a board independent from the trading operations. Proprietary trading activities are subject to particularly strict limits. The risk ratios and limits used mainly include Profit at Risk and Value at Risk figures, as well as volume, credit and book limits. Additional key elements of risk management are the clear division of duties between scheduling, trading, settlement and control, as well as a risk reporting independent from the trading operations.

Hedge accounting in accordance with SFAS 133 is used primarily for interest rate derivatives regarding hedges of long-term debts, for foreign currency derivatives regarding hedges of net investments in foreign operations and long-term receivables and debts denominated in foreign currencies. For commodities, potentially volatile future cash flows from planned purchases and sales of electricity and from gas supply requirements are hedged.

Fair Value Hedges

The Company uses fair value hedge accounting specifically in the exchange of fixed-rate commitments in loans and long-term 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 transactions. The ineffective portion of fair value hedges as of December 31, 2005, resulted in a gain of €1 million (2004: €2 million; 2003: €2 million) and is included in other operating income and other operating expenses. Interest rate fair value hedges are reported under “Interest and similar expenses (net).”

Cash Flow Hedges

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 interest-bearing loans and long-term 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 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, 2005, the hedged transactions in place included foreign currency cash flow hedges with maturities of up to 12 years (2004: up to 20 years) and up to 27 years (2004: 28 years) for interest rate cash flow hedges. Planned commodity cash flow hedges have maturities of up to 3 years (2004: up to 3 years).

The amount of ineffectiveness for cash flow hedges recorded for the year ended December 31, 2005, was a gain of €1 million (2004: €1 million). For the year ended December 31, 2005, reclassifications from “Accumulated other comprehensive income” for cash flow hedges resulted in a loss of €208 million (2004: €117 million gain). The Company estimates that reclassifications from “Accumulated other comprehensive

F-71

income” for cash flow hedges in the next twelve months will result in a gain of €68 million. 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 portion of cash flow hedges are classified as other operating income or other operating expenses. Interest rate cash flow hedges are reported under “Interest and similar expenses (net).” The early termination of a cash flow hedge resulting from the probability that the hedged transaction would not occur resulted in a gain of €34 million recognized in other operating income.

Net Investment Hedges

The Company uses foreign currency loans, foreign currency forwards, FX swaps and cross-currency swaps to protect the value of its net investments in its foreign operations denominated in foreign currencies. For the year ended December 31, 2005, the Company recorded an amount of €825 million (2004: €1,060 million) in “Accumulated other comprehensive income” within stockholders’ equity due to changes in fair value of derivative and foreign currency transaction results of non-derivative hedging instruments.

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, swap 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 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 rate risk are determined by discounting future cash flows using market interest rates over the remaining term of the instrument. Discounted cash values are determined for interest rate, cross-currency and cross-currency interest-rate swaps for each individual transaction as of the balance-sheet date. Interest exchange amounts are considered with an effect on current results at the date of payment or accrual.

	•	Equity swaps are valued on the basis of the stock prices of the underlying equities, taking into consideration any financing 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 “Financial receivables and other financial 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 by the use of valuation models that include average probabilities and take into account individual contract details and variables.

Losses of €39 million (2004: €0 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.

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The following two tables include both derivatives that qualify for SFAS 133 hedge accounting treatment and those that do not qualify.


			December 31, 2005					December 31, 2004
Total Volume of Foreign Currency, Interest-Rate and
Equity-Based Derivatives			Nominal		Fair			Nominal		Fair
€ in millions			value		value			value		value

FX forward transactions
	Buy			4,091.3		79.2			4,238.2		(41.3	)
	Sell			8,331.2		(81.7	)		5,328.6		134.2
FX currency options
	Buy			227.7		32.8			782.7		46.7
	Sell			139.6		(39.0	)		422.2		(36.4	)

Subtotal				12,789.8		(8.7	)		10,771.7		103.2

Cross-currency swaps
	up to 1 year			1,734.7		34.7			499.1		(7.0	)
	1 year to 5 years			8,163.2		57.8			11,033.7		484.2
	more than 5 years			6,358.4		66.6			7,163.8		236.3
Cross-currency interest-rate swaps
	up to 1 year			125.0		13.1			102.3		1.4
	1 year to 5 years			316.4		5.0			125.0		12.1
	more than 5 years			—		—			297.4		(38.5	)

Subtotal				16,697.7		177.2			19,221.3		688.5

Interest-rate swaps
	Fixed-rate payer
		up to 1 year		612.2		(11.8	)		371.0		(5.4	)
		1 year to 5 years		1,294.9		(44.1	)		2,092.5		(107.9	)
		more than 5 years		1,033.5		(18.0	)		373.3		(36.6	)
	Fixed-rate receiver
		up to 1 year		—		—			23.3		0.3
		1 year to 5 years		5,364.4		64.3			3,914.0		100.6
		more than 5 years		1,196.4		(20.7	)		147.0		4.5

Subtotal				9,501.4		(30.3	)		6,921.1		(44.5	)

Interest-rate options
	Buy
		up to 1 year		—		—			554.6		(7.2	)
		1 year to 5 years		—		—			—		—
		more than 5 years		—		—			—		—
	Sell
		up to 1 year		—		—			110.9		(2.0	)
		1 year to 5 years		—		—			—		—
		more than 5 years		—		—			—		—

Subtotal				0.0		0.0			665.5		(9.2	)

Equity swaps				—		—			63.8		103.0

Subtotal				0.0		0.0			63.8		103.0

Total				38,988.9		138.2			37,643.4		841.0

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							Thereof Trading

Total Volume of Electricity, Gas, Coal, Oil and		December 31, 2005					December 31, 2005					December 31, 2004
Emissions-Related
Financial Derivatives		Nominal		Fair			Nominal		Fair			Nominal		Fair
€ in millions		value		value			value		value			value		value

Electricity forwards
	up to 1 year		15,379.4		24.0			14,221.3		(64.0	)		7,521.9		41.6
	1 year to 3 years		4,722.5		(116.1	)		4,228.7		(95.0	)		2,306.2		(39.9	)
	4 years to 5 years		54.4		(5.0	)		12.0		(0.5	)		59.6		(0.4	)
	more than 5 years		9.6		0.8			1.9		(0.1	)		7.5		(1.0	)

Subtotal			20,165.9		(96.3	)		18,463.9		(159.6	)		9,895.2		0.3

Exchange-traded electricity forwards
	up to 1 year		3,316.7		(103.6	)		2,402.8		49.6			3,085.4		(93.3	)
	1 year to 3 years		1,621.4		(18.1	)		985.4		49.8			1,309.9		(9.9	)
	4 years to 5 years		17.6		(1.4	)		17.6		(1.4	)		—		—
	more than 5 years		1.9		0.1			1.9		0.1			—		—

Subtotal			4,957.6		(123.0	)		3,407.7		98.1			4,395.3		(103.2	)

Electricity swaps
	up to 1 year		88.3		(21.6	)		—		—			29.7		0.3
	1 year to 3 years		—		—			—		—			3.1		(0.1	)
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			88.3		(21.6	)		0.0		0.0			32.8		0.2

Electricity options
	up to 1 year		—		—			—		—			8.8		(0.2	)
	1 year to 3 years		—		—			—		—			—		—
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			0.0		0.0			0.0		0.0			8.8		(0.2	)

Exchange-traded electricity options
	up to 1 year		12.1		(0.7	)		12.1		(0.7	)		64.9		(1.5	)
	1 year to 3 years		71.7		(0.2	)		71.7		(0.2	)		132.6		(1.6	)
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			83.8		(0.9	)		83.8		(0.9	)		197.5		(3.1	)

Coal forwards and swaps
	up to 1 year		839.4		(46.0	)		127.2		(2.8	)		1,541.6		26.8
	1 year to 3 years		439.9		(3.0	)		51.3		(1.9	)		851.2		18.3
	4 years to 5 years		31.9		(1.4	)		—		—			112.0		1.1
	more than 5 years		—		—			—		—			—		—

Subtotal			1,311.2		(50.4	)		178.5		(4.7	)		2,504.8		46.2

Oil derivatives
	up to 1 year		845.0		106.1			103.5		0.6			405.0		28.5
	1 year to 3 years		341.7		59.1			—		—			266.0		28.1
	4 years to 5 years		—		—			—		—			2.8		—
	more than 5 years		—		—			—		—			—		—

Subtotal			1,186.7		165.2			103.5		0.6			673.8		56.6

Gas forwards
	up to 1 year		4,628.7		380.8			483.8		(65.2	)		1,606.8		77.4
	1 year to 3 years		4,226.9		541.4			250.5		(8.8	)		1,117.9		131.7
	4 years to 5 years		763.7		27.4			61.7		1.5			426.0		2.0
	more than 5 years		92.6		(17.7	)		—		—			—		—

Subtotal			9,711.9		931.9			796.0		(72.5	)		3,150.7		211.1

Carryover			37,505.4		804.9			23,033.4		(139.0	)		20,858.9		207.9

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							Thereof Trading

Total Volume of Electricity, Gas, Coal, Oil and		December 31, 2005					December 31, 2005					December 31, 2004
Emissions-Related
Financial Derivatives		Nominal		Fair			Nominal		Fair			Nominal		Fair
€ in millions		value		value			value		value			value		value

Carryover			37,505.4		804.9			23,033.4		(139.0	)		20,858.9		207.9

Gas swaps
	up to 1 year		1,987.3		277.4			1,340.7		3.4			1,908.1		78.1
	1 year to 3 years		1,645.0		306.8			594.0		0.8			1,513.9		143.6
	4 years to 5 years		737.0		86.9			—		—			503.1		(7.0	)
	more than 5 years		1,892.3		7.9			—		—			373.8		(24.2	)

Subtotal			6,261.6		679.0			1,934.7		4.2			4,298.9		190.5

Gas options
	up to 1 year		43.3		(16.7	)		—		—			34.1		(7.6	)
	1 year to 3 years		—		—			—		—			24.5		(7.7	)
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			43.3		(16.7	)		0.0		0.0			58.6		(15.3	)

Emissions-related derivatives
	up to 1 year		98.4		4.9			92.3		0.8			28.8		(0.5	)
	1 year to 3 years		24.3		1.6			20.2		0.2			5.9		(0.1	)
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			122.7		6.5			112.5		1.0			34.7		(0.6	)

Exchange-traded emissions-related derivatives
	up to 1 year		11.4		0.3			8.9		0.3			—		—
	1 year to 3 years		5.6		0.3			1.4		0.2			—		—
	4 years to 5 years		—		—			—		—			—		—
	more than 5 years		—		—			—		—			—		—

Subtotal			17.0		0.6			10.3		0.5			0.0		0.0

Total			43,950.0		1,474.3			25,090.9		(133.3	)		25,251.1		382.5

Counterparty Risk from the Use of Derivative Financial Instruments

The Company is exposed to credit (or repayment) risk and market risk through the use of derivative instruments. If the counterparty fails to fulfill its performance obligations under a derivative contract, the Company’s counterparty risk will equal the positive market value of the derivative. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, assumes no repayment risk.

In order to minimize the credit risk in derivative instruments, the Company enters into transactions only with counterparties such as financial institutions, commodities exchanges, energy distributors and broker-dealers that satisfy the Company’s internally-established minimum requirements for the creditworthiness of counterparties.

The credit-risk management policy that has been established throughout the Group entails the systematic monitoring of the creditworthiness of counterparties and a regular assessment of credit risk. The credit ratings of all counterparties to derivative financial instruments are reviewed using the Company’s established credit approval criteria. The subsidiaries involved in electricity, gas, coal, oil and emissions-related derivatives also perform thorough credit checks on their counterparties and monitor creditworthiness on a regular basis. The Company receives and pledges collateral in connection with long-term interest and currency hedging derivatives in the banking sector. Furthermore, collateral is required when entering into transactions in commodity derivatives with counterparties of a low degree of creditworthiness. Derivative transactions are generally executed on the basis of standard agreements that allow for the netting of all outstanding transactions with individual contracting partners. For currency and interest-rate derivatives in the banking sector, this netting option is reflected in the accounting treatment. Exchange-traded electricity forward and option contracts and emission rights having an aggregate nominal value of €5,058 million as of December 31, 2005, bear no counterparty risk.

In summary, as of December 31, 2005, the Company’s derivative financial instruments had the following credit structure and lifetime. The continuing netting of outstanding transactions with positive and negative market

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values is not shown in the table below, even though the greater part of the transactions was completed on the basis of contracts that do allow netting. The counterparty risk is the sum of the positive fair values.


	December 31, 2005

	Total				Up to 1 Year				1 to 5 Years				More than 5 Years

Rating of Counterparties			Counter-				Counter-				Counter-				Counter-
Standard & Poor’s and/or Moody’s	Nominal		party		Nominal		party		Nominal		party		Nominal		party
€ in millions	value		risk		value		risk		value		risk		value		risk

AAA and Aaa through AA- and Aa3		28,821.5		2,557.9		11,489.8		1,036.7		11,738.9		994.6		5,592.8		526.6
AA- and A1 or A+ and Aa3 through A- and A3		19,604.5		1,108.4		8,416.0		787.4		8,791.6		314.9		2,396.9		6.1
A- and Baa1 or BBB+ and A3 through BBB- or Baa3		4,805.1		652.1		3,503.1		450.8		997.8		201.3		304.2		—
BBB- and Ba1 or BB+ and Baa3 through BB- and Ba3		1,403.0		182.4		944.1		142.7		372.4		38.8		86.5		0.9
Other (1)		23,246.3		2,648.2		15,276.2		2,067.9		5,760.1		530.1		2,210.0		50.2

Total		77,880.4		7,149.0		39,629.2		4,485.5		27,660.8		2,079.7		10,590.4		583.8


(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.


(29)	Non-Derivative Financial Instruments

The Company estimates the fair value of its non-derivative financial instruments using available market information and appropriate valuation methodologies. The interpretation of market data to generate estimates of fair value requires considerable judgement. Accordingly, the estimates are not necessarily indicative of the amounts the Company would realize for its non-derivative financial instruments under current market conditions.

The estimated book values and fair values of non-derivative financial instruments as of December 31, 2005 and 2004, are summarized in the following table:


		December 31, 2005				December 31, 2004

€ in millions		Book value		Fair value		Book value		Fair value

Assets
	Loans		1,100		1,112		1,438		1,477
	Securities		10,420		10,420		8,617		8,617
	Financial receivables and other financial assets		2,019		2,019		2,124		2,124
	Cash and deposits at banking institutions		5,859		5,859		4,233		4,233

Total			19,398		19,410		16,412		16,451

Liabilities
	Financial liabilities		14,362		15,421		20,301		21,168

The Company used the following methods and assumptions to estimate the fair value of each class of financial instruments whose value it is practicable to estimate:

The carrying amounts of cash and cash equivalents are reasonable estimates of their fair values. The Company calculates the fair value of loans and other financial instruments by discounting the future cash flows by the current interest rate for comparable instruments. The fair values of funds and marketable securities are based on their quoted market prices or on other appropriate valuation techniques.

Fair values for financial liabilities are estimated by discounting expected cash flows for payments on principal and interest payments, using market interest rates currently available for debt with similar terms and remaining maturities. The carrying amount of commercial paper and borrowings under revolving short-term credit facilities is assumed as the fair value due to the short maturities of these instruments.

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The Company believes that the overall credit risk related to its non-derivative financial instruments is insignificant. The counterparties with whom agreements on non-derivative financial instruments are entered into are also subjected to regular credit checks as part of the Group’s credit risk management policy. There is also regular reporting on counterparty risks in the E.ON Group.


(30)	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 at cost. Transactions with related parties are summarized as follows:


€ in millions	2005		2004

Income		5,408		4,846
Expenses		2,913		2,530
Receivables		2,263		1,686
Liabilities		2,161		1,973

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.

Accounts receivable from related companies consist mainly of trade receivables and of a subordinated loan to ONE in the amount of €162 million (2004: €469 million). Interest income recognized on this loan amounted to €11 million in 2005 (2004: €14 million). In May 2005, shareholder loans to ONE were partially converted to equity; the E.ON share of the converted loans amounted to €223 million. In December 2005, ONE repaid €95 million of the remaining shareholder loans to E.ON. As a consequence of a refinancing measure undertaken at ONE in October 2004, E.ON is no longer liable for a guarantee it issued to a bank consortium in 2003 in order to provide additional financial support in the event that ONE is or may become unable to comply with specified debt covenants. The total maximum obligation of E.ON under this agreement was €194 million.

Liabilities of E.ON payable to related companies include €241 million (2004: €1,513 million) in trade payables to operators of jointly-owned nuclear power plants. These payables bear interest at 1.0 percent per annum (2004: between 1.0 and 1.95 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 2005 of €1,253 million resulting from fixed-term deposits undertaken by the jointly-owned nuclear power plants at the Central Europe market unit.

(31) Segment Information

The reportable segments of the E.ON Group are presented in line with the Company’s internal organizational and reporting structure. E.ON’s business is subdivided into the core energy business and other activities. The core energy business includes the market units Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest, as well as the Corporate Center. The 42.9 percent interest in Degussa accounted for at equity is reported under other activities.


	•	The Central Europe market unit, led by E.ON Energie AG, Munich, Germany, 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 lead company of this market unit is E.ON Ruhrgas AG, Essen, Germany.

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	•	The U.K. market unit encompasses the integrated energy business in the United Kingdom. This market unit is led by E.ON UK plc, Coventry, U.K.

	•	The Nordic market unit, which is led by E.ON Nordic AB, Malmö, Sweden, focuses on the integrated energy business in Northern Europe. It operates through the integrated energy company E.ON Sverige AB, Malmö, Sweden, and through E.ON Finland Oyj, Espoo, Finland, primarily in Sweden and Finland.

	•	The U.S. Midwest market unit, led by E.ON U.S. LLC, Louisville, Kentucky, U.S., is primarily active in the regulated energy market in the U.S. state of Kentucky.

	•	The Corporate Center contains those interests managed directly by E.ON AG that have not been allocated to any of the other segments, E.ON AG itself and the consolidation effects at the Group level.

In accordance with U.S. accounting principles, E.ON reports segments or material business units to be disposed of as discontinued operations.

In 2005, this particularly includes the activities of the disposed entities Viterra and Ruhrgas Industries, as well as WKE, which has not been disposed of as yet. The corresponding figures as of December 31, 2005, as well as those for the preceding periods, have been adjusted for all components of the discontinued operations.

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 book gains and losses on disposals, cost-management and restructuring expenses, and other non-operating income and expenses. Due to the adjustments accounted for under non-operating earnings, the key figures by segment may differ from the corresponding U.S. GAAP figures reported in the Consolidated Financial Statements.

Below is the reconciliation of adjusted EBIT to “Income/(Loss) from continuing operations before income taxes and minority interests” as shown in the Consolidated Financial Statements:


€ in millions	2005			2004			2003

Adjusted EBIT		7,333			6,787			5,707
Adjusted interest income (net)		(1,027	)		(1,031	)		(1,515	)
Net book gains		491			589			1,257
Cost-management and restructuring expenses		(29	)		(100	)		(479	)
Other non-operating earnings		440			110			195

Income/(Loss) from continuing operations before income taxes and minority interests		7,208			6,355			5,165
Income taxes		(2,276	)		(1,850	)		(1,145	)
Minority interests		(553	)		(478	)		(445	)
Income/(Loss) from continuing operations		4,379			4,027			3,575

Income/(Loss) from discontinued operations, net		3,035			312			1,512
Cumulative effect of changes in accounting principles, net		(7	)		—			(440	)

Net income		7,407			4,339			4,647

Net book gains in 2005 are due primarily to the sale of securities (€371 million). In addition, the transfer of the stake in TEAG resulted in a gain of €90 million. In 2004, net book gains resulted primarily from the sale of E.ON’s interests in EWE and VNG (€317 million), the sale of securities (€221 million) and the sale of Degussa shares (€51 million). In 2003, book gains consisted largely of gains from the sale of shares in Bouygues Telecom (€840 million), from the sale of shares in Degussa (€168 million) and from the sale of securities held by the Central Europe market unit (€165 million). In addition, €160 million in book gains were realized from the sale of interests at the Central Europe and U.K. market units. These gains were primarily offset by a book loss of €76 million on the disposal of a stake in HypoVereinsbank held by the Central Europe market unit.

Cost-management and restructuring expenses in 2005 declined from their 2004 level to €29 million. They arose primarily in the U.K. market unit as a result of the integration of Midlands Electricity into the market unit. In 2004, cost-management and restructuring expenses were recorded mainly at the U.K. market unit (€63 million), primarily as a result of the integration of Midlands Electricity, and at the Central Europe market unit (€37 million), primarily at the two regional utilities E.ON Hanse AG, Quickborn, Germany, and E.ON Westfalen

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Weser AG, Paderborn, Germany. In 2003, restructuring expenses were recorded at the Central Europe market unit (€358 million) and included, among others, expenses relating to the creation of the regional utilities E.ON Hanse and E.ON Westfalen Weser and to further early-retirement regulations, and at the U.K. market unit (€121 million), relating to the integration of the TXE Europe operations.

Other non-operating earnings primarily include unrealized gains from the marking to market of energy derivatives at the U.K. market unit. These derivatives are used to hedge against fluctuations in prices. In the fourth quarter of 2005, the fair value of these derivatives held within the Group increased by more than €600 million on aggregate as a result of the strong increase in gas prices. At the end of 2005, the marking to market of derivatives resulted in a gain of approximately €1,200 million. On the other hand, an impairment charge recorded by Degussa at its Fine Chemicals division translated into a negative effect on earnings in the amount of €347 million through E.ON’s direct ownership interest in Degussa (42.9 percent). The costs resulting from the severe storm in Sweden at the beginning of the year amounted to approximately €140 million. Additional negative effects on earnings were attributable to impairments in the area of generation recorded at cogeneration facilities in the U.K. market unit (€129 million) and to an adjustment of deferred taxes (€103 million) undertaken at an at-equity holding of the Corporate Center. The 2004 value primarily reflected the positive effects from the marking to market of derivatives (approximately €290 million). This gain was partially offset by impairment charges on real estate and short-term securities at the Central Europe market unit and by non-recurring charges on investments at the Central Europe and U.K. market units, among others. In 2003, other non-operating earnings primarily reflected the positive effects from the required marking to market of derivatives (€494 million). This was offset by the impairment charge taken by Degussa with respect to its Fine Chemicals division, which reduced E.ON’s other non-operating earnings by €187 million.

Segment information for the periods indicated is as follows:


		Central Europe									Pan-European Gas									U.K.									Nordic

€ in millions		2005			2004			2003			2005			2004(1)			2003(1)			2005			2004			2003			2005			2004			2003

External sales			24,047			20,540			18,983			16,835			12,671			11,530			10,102			8,480			7,915			3,369			3,281			2,776
Intersegment sales			248			212			270			1,079			556			389			74			10			8			102			66			48

Total sales			24,295			20,752			19,253			17,914			13,227			11,919			10,176			8,490			7,923			3,471			3,347			2,824

Depreciation and amortization			(1,298	)		(1,121	)		(1,447	)		(387	)		(334	)		(371	)		(586	)		(575	)		(426	)		(379	)		(420	)		(386	)
Impairments(3)			(56	)		(185	)		(45	)		(16	)		(94	)		(4	)		(1	)		—			—			(8	)		—			(1	)
Adjusted EBIT			3,930			3,602			2,979			1,536			1,344			1,401			963			1,017			610			806			701			546
	Thereof: earnings from companies accounted for at equity(4)		189			143			290			509			419			406			17			43			36			9			10			21
Intangible assets and property plant and equipment			1,519			1,388			1,255			263			105			169			565			511			322			407			350			369
Financial assets			658			1,139			871			268			509			442			361			(8	)		66			131			390			896

Investments			2,177			2,527			2,126			531			614			611			926			503			388			538			740			1,265

Total assets			60,531			55,537			54,808			30,746			22,720			22,928			19,177			14,986			12,610			11,193			11,289			10,662


		U.S. Midwest									Corporate Center									Core Energy Business									Other Activities(2)

€ in millions		2005			2004(1)			2003(1)			2005			2004(1)			2003(1)			2005			2004(1)			2003(1)			2005		2004(1)		2003(1)

External sales			2,045			1,718			1,771			1			52			141			56,399			46,742			43,116			—		—		993
Intersegment sales			—			—			—			(1,503	)		(844	)		(716	)		—			—			(1	)		—		—		1

Total sales			2,045			1,718			1,771			(1,502	)		(792	)		(575	)		56,399			46,742			43,115			—		—		994

Depreciation and amortization			(195	)		(185	)		(192	)		(12	)		(22	)		(19	)		(2,857	)		(2,657	)		(2,841	)		—		—		(59	)
Impairments(3)			—			—			—			(1	)		(18	)		(26	)		(82	)		(297	)		(76	)		—		—		—
Adjusted EBIT			365			354			318			(399	)		(338	)		(323	)		7,201			6,680			5,531			132		107		176
	Thereof: earnings from companies accounted for at equity(4)		17			17			17			9			(42	)		33			750			590			803			132		107		105
Intangible assets and property plant and equipment			227			247			411			9			11			(24	)		2,990			2,612			2,502			—		—		36
Financial assets			—			—			—			(71	)		467			4,200			1,347			2,497			6,475			—		—		—

Investments			227			247			411			(62	)		478			4,176			4,337			5,109			8,977			—		—		36

Total assets			9,296			7,643			8,367			(6,186	)		(5,794	)		(5,971	)		124,757			106,381			103,404			1,805		7,681		8,446

F-79


		E.ON Group

€ in millions		2005			2004(1)			2003(1)

External sales			56,399			46,742			44,109
Intersegment sales			—			—			—

Total sales			56,399			46,742			44,109

Depreciation and amortization			(2,857	)		(2,657	)		(2,900	)
Impairments(3)			(82	)		(297	)		(76	)
Adjusted EBIT			7,333			6,787			5,707
	Thereof: earnings from companies accounted for at equity(4)		882			697			908
Intangible assets and property plant and equipment			2,990			2,612			2,538
Financial assets			1,347			2,497			6,475

Investments			4,337			5,109			9,013

Total assets			126,562			114,062			111,850


(1)	Adjusted for discontinued operations.

(2)	The other activities of the E.ON Group include the 42.9 percent interest in Degussa accounted for at equity in the Consolidated Financial Statements. In addition, the balance-sheet data reported by segment also include the at-equity carrying amount of Degussa and the total assets and liabilities of Viterra, which in 2004 was still reported under other activities.

(3)	For all periods presented, the impairment charges recognized in adjusted EBIT differed from the impairment charges recorded in accordance with U.S. GAAP. In 2005, the difference was the result of impairments recorded in the area of generation, specifically power-heat coupling plants in the U.K. market unit. In 2004, the difference was due to impairment charges on real property, on a municipal utility investment at the Central Europe market unit, and on an Asian power plant investment at the U.K. market unit, all of which were included in non-operating earnings. In 2003, the deviation was due to the impairment charge on an Asian power plant investment at the U.K. market unit, which was also included in non-operating earnings.

(4)	For all periods presented, the earnings contributing to adjusted EBIT from companies accounted for at equity differed from the at-equity results recorded in accordance with U.S. GAAP. In 2005, this was the result of impairment charges included in non-operating earnings. They relate to the Fine Chemicals division of Degussa and to deferred tax assets of an at-equity holding of the Corporate Center. In 2004, the impairment charges on a municipal utility investment at the Central Europe market unit and on an Asian power plant investment at the U.K. market unit were responsible for the difference. In 2003, the deviation was due to the reclassification of at equity earnings from RAG in other non-operating earnings and to the impairment charge on the U.K. market unit’s Asian power plant investment, which was recorded in other non-operating earnings.

An additional adjustment in the internal profit analysis relates to interest income, which is adjusted on an economic basis. In particular, the interest component of expenses resulting from increases in provisions for pensions is reclassified from personnel costs to interest income. The interest components of allocations to other long-term provisions are treated in the same way to the extent that, in accordance with U.S. GAAP, these provisions are reported on different lines in the income statement.

Net interest income is largely unchanged from 2004. The loss of the positive one-time effect from the amendment of the Endlagervorausleistungsverordnung is offset primarily by the markedly improved net financial position.


€ in millions	2005			2004			2003

Interest and similar expenses (net) as shown in Note 6		(736	)		(1,062	)		(978	)
(+) Non-operating interest income, net (1)		(39	)		151			(62	)
(-) Interest portion of long-term provisions		252			120			475

Adjusted interest income, net		(1,027	)		(1,031	)		(1,515	)


(1)	This figure is calculated by adding interest expenses and subtracting interest income. In 2005, non-operating interest income primarily related to an eliminated provision for interest. In 2004, non operating interest-net income primarily reflected tax-related interest.

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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 company) and property, plant and equipment information by geographic area:


								Europe (Eurozone
		Germany						excluding Germany)						Europe (other)						United States						Other						Total

€ in millions		2005		2004		2003		2005		2004		2003		2005		2004		2003		2005		2004		2003		2005		2004		2003		2005		2004		2003

External sales
	by location of customer		33,557		28,621		27,124		3,030		2,179		2,235		17,743		14,110		12,407		1,990		1,770		2,051		79		62		292		56,399		46,742		44,109
	by location of company		36,635		30,028		28,484		1,476		1,462		1,546		16,243		13,482		11,827		1,980		1,711		2,073		65		59		179		56,399		46,742		44,109
Property, plant and equipment			19,010		23,171		23,418		1,339		1,283		1,331		16,819		15,327		13,898		4,072		3,693		4,044		83		89		106		41,323		43,563		42,797

Information on Major Customers and Suppliers

In all periods presented, E.ON’s customer structure 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.

E.ON procures the majority of its gas inventory from Russia and Norway.


(32)	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 May 4, 2006, total remuneration to members of the Supervisory Board is €3.8 million (2004: €3.3 million).

There were no loans to members of the Supervisory Board in 2005.

The Supervisory Board’s compensation structure, as well as the amounts for each member of the Supervisory Board, are shown in “Item 6: Directors, Senior Management and Employees.”

Board of Management

Total remuneration to members of the Board of Management in 2005 amounted to €22.5 million (2004: €17.3 million). This consisted of base salary, bonuses, other compensation elements and stock options. In accordance with the new statutory provisions regarding publication of compensation of Board of Management members (Gesetz über die Offenlegung der Vorstandsvergütungen, VorstOG) the included stock options are quoted at their fair value on the date they were issued.

Total payments to former members of the Board of Management and their beneficiaries amounted to €5.4 million (2004: €5.2 million). The previous year’s value of total remuneration of the current and former members of the Board of Management was adjusted in accordance with the new statutory provisions regarding publication of compensation of Board of Management members. Provisions of €89.0 million (2004: €83.5 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 2005 fiscal year.

The Board of Management’s compensation structure, as well as the amounts for each member of the Board, are shown in “Item 6: Directors, Senior Management and Employees.”

F-81


(33)	Subsequent Events

E.ON will acquire full ownership of the gas trading and storage business of the Hungarian oil and gas company MOL. The two companies had first agreed in November 2004 that E.ON would acquire 75 percent of the gas trading and storage business and 50 percent of the gas importer Panrusgaz. The European Commission approved the acquisition, subject to certain conditions. Under these conditions, MOL must divest itself entirely of the gas storage and gas trading business. Accordingly, it was agreed on January 12, 2006, that E.ON would also acquire the remaining 25 percent of both companies. The aggregate purchase price for the complete stake is now approximately €450 million. In addition, E.ON will assume financial debts of approximately €600 million. It was further agreed that, depending on regulatory developments, compensatory payments would be made through the end of 2009 if that should become necessary for a subsequent adjustment of the purchase price. The transaction will be completed by the end of March 2006.

Under an order dated January 13, 2006, the German Federal Cartel Office prohibited E.ON Ruhrgas from implementing existing long-term gas supply contracts with regional and local gas distributors and from entering into new contracts identical or similar in nature. This dispute relates to the enforceability of long-term gas supply contracts, which have been customary in the German natural gas market for delivery to distributors since the beginning of the natural gas industry itself. The differing legal opinions, which touch on basic principles like freedom of contract and competition, as well as on the security of the energy supply, can only be resolved definitively by the courts. E.ON Ruhrgas has therefore filed a complaint against the order with the State Superior Court in Düsseldorf, along with an emergency petition to prevent it from taking immediate effect.

E.ON Nordic and the Finnish energy group Fortum Power and Heat Oyj (“Fortum”) signed an agreement on February 2, 2006, under which Fortum will acquire E.ON Nordic’s entire interest in E.ON Finland. These 10,246,565 shares constitute 65.56 percent of the capital stock and voting rights of E.ON Finland. The total purchase price is approximately €380 million (€37.12 per share). The transaction is subject to the approval of the Finnish competition authority. E.ON Finland is listed on the Helsinki Stock Exchange. Moreover, the City of Espoo, which at 34.24 percent is the second largest shareholder of E.ON Finland, entered into an agreement with Fortum on January 18, 2006, whereby the City also sells and transfers its entire shareholding in E.ON Finland once E.ON Nordic has transferred its E.ON Finland shares to Fortum. Through this agreement, E.ON Nordic satisfies its obligations under a call option for all shares of E.ON Finland owned by E.ON Nordic, which it had entered into with Fortum in 2002. Fortum exercised the option in January 2005. In response to Fortum exercising its option, E.ON Nordic had replied that, in view of the position held by the City of Espoo concerning restrictions on share transfers based on the shareholders’ agreement between E.ON Nordic and the City of Espoo, E.ON Nordic was not in a position to deliver the E.ON Finland shares. In response, Fortum filed a Request for Arbitration against E.ON Nordic with the International Chamber of Commerce in February 2005. The Espoo City Council consented on January 16, 2006, that both the city itself and E.ON Nordic sell their respective interests in E.ON Finland to Fortum. This decision was declared enforceable with immediate effect by the leadership of the city. When the transaction between E.ON Nordic and Fortum is completed, the companies will simultaneously terminate the arbitration proceedings related to the transfer of the E.ON Finland shares. In connection with the acquisition, E.ON and Fortum reached agreement on a settlement of all related remaining open matters. This agreement involves an additional €16 million payment by Fortum to E.ON.

In February 2006, E.ON Energie and RWE AG, Essen, Germany, signed an agreement concerning the exchange of holdings in the Czech Republic and Hungary. Its implementation, which is planned for the current fiscal year, is subject to the approval of the responsible committees and competition authorities.

On February 21, 2006, E.ON made an offer to acquire 100 percent of the shares and American Depositary Shares of Endesa S.A. (“Endesa”), Madrid, Spain, for a price of €27.50 per share in cash. Endesa is Spain’s largest electric utility, which also has significant activities in Latin America and Italy. The total consideration offered for Endesa is approximately €29.1 billion. The total volume of the transaction, including the approximately €26.1 billion in net debt, provisions and minority interests reported by Endesa as of December 31, 2005, is approximately €55.2 billion. The completion of the offer is conditional upon E.ON acquiring at least

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50.01 percent of the share capital of Endesa and upon the annual shareholders meeting of Endesa resolving to make certain amendments to Endesa’s by-laws. E.ON will file notice of its intended acquisition with Spain’s General Secretary of Energy (Secretario General de Energía) and with the European Commission. The relevant approvals are not conditions of the offer. E.ON expects to be able to complete the transaction by mid-2006. However, no assurance can be given that E.ON will be able to complete the transaction successfully on the proposed terms or at all.

On January 27, 2006, RAG made public its previously issued stock purchase offer to Degussa’s minority shareholders, thereby continuing the implementation of its framework agreement concerning the disposal of E.ON’s 42.9 percent stake in Degussa. The acceptance period ended on February 27, 2006. RAG has announced that it and E.ON now hold at least 95 percent of Degussa stock, the figure named in the stock purchase offer.

On March 8, 2006, E.ON made an initial contribution of €2.6 billion in connection with the contractual trust arrangement (CTA) which was established in 2006 to provide for future pension benefit payments to employees of German group companies. This contribution will result in a significant reduction of E.ON’s pension provision.

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 9, 2006


	E.ON AG


	By:	/s/ Dr. Erhard Schipporeit



	Dr. Erhard Schipporeit
	Member of the Board of Management and
	Chief Financial Officer

	/s/ Michael C. Wilhelm

	Michael C. Wilhelm
	Senior Vice President Accounting