E.ON International Finance BV

OFFERING MEMORANDUM
CONFIDENTIAL
E.ON International Finance B.V.
Amsterdam, The Netherlands
U.S. $3,000,000,000
consisting of
U.S.$2,000,000,000 5.80% Notes due 2018
U.S.$1,000,000,000 6.65% Notes due 2038
With an unconditional and irrevocable guarantee as to payment of principal and interest from
E.ON AG
The notes due 2018 (the “2018 Notes”) will bear interest at a rate of 5.80% per year and the notes due 2038 (the “2038
Notes” and, together with the 2018 Notes, the “Notes”) will bear interest at a rate of 6.65% per year. Interest on the Notes will
be payable semi-annually in arrears on October 30 and April 30 of each year, commencing on October 30, 2008. The 2018
Notes and 2038 Notes will mature on April 30, 2018, and April 30, 2038, respectively. The Notes will be issued by E.ON
International Finance B.V. (the “Issuer”) and will be unconditionally guaranteed by E.ON AG (the “Guarantor”). See
“Description of the Notes.”
The Issuer may, at its option, redeem the Notes in whole or in part at any time by paying a “make whole premium” as
specified herein. See “Description of the Notes — Optional Redemption.” The Issuer may also redeem the Notes at the
Issuer’s (or, if applicable, the Guarantor’s) option, in whole but not in part, at 100% of their principal amount then outstanding
plus accrued interest if certain tax events occur as described in this offering memorandum. Upon the occurrence of certain
change of control events, each holder of Notes (a “Holder”) may require the Issuer to repay all or a portion of its Notes as
more particularly described under “Description of the Notes — Holders’ Option to Repayment upon a Change in Control”.
The Issuer does not intend to apply to list the Notes on any securities exchange.
Investing in the Notes involves risks. See “Risk Factors” beginning on page 22.
The Notes have not been and will not be registered under the U.S. Securities Act of 1933, as amended (the “Securities
Act”). The Notes may be offered or sold in the United States only to Qualified Institutional Buyers as defined in, and in
reliance on, Rule 144A under the Securities Act (“Rule 144A”) or outside the United States to non-U.S. persons in reliance on
Regulation S under the Securities Act (“Regulation S”). Prospective investors that are Qualified Institutional Buyers are
hereby notified that sellers of Notes may be relying on the exemption from the provisions of Section 5 of the Securities Act
provided by Rule 144A. The Notes are not transferable except in accordance with the restrictions described under “Transfer
Restrictions.”
Issue Price: 99.578% of the principal amount of the 2018 Notes and 99.572% of the principal amount of the 2038
Notes.
The Notes will be represented by one or more global notes registered in the name of the nominee of The Depositary
Trust Company (“DTC”), as depositary. Beneficial interests in the Notes will be shown on, and transfers thereof will be
effected through, records maintained by DTC, Clearstream Banking, société anonyme (“Clearstream”) and Euroclear Bank
S.A/N.V. (“Euroclear”), and their respective participants. See “Transfer Restrictions.”
The Initial Purchasers (as defined in “Plan of Distribution”) expect to deliver the Notes against payment in immediately
available funds on or about April 22, 2008.
Joint Book-Running Managers
Banc of America Securities LLC
Deutsche Bank Securities
Goldman, Sachs & Co.
JPMorgan
Co-Managers
Lehman Brothers
Merrill Lynch & Co.
RBS Greenwich Capital
The date of this offering memorandum is April 15, 2008.
TABLE OF CONTENTS
Page
CERTAIN DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PRESENTATION OF FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AVAILABLE INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXCHANGE RATE INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OPERATING AND FINANCIAL REVIEW AND PROSPECTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DIRECTORS AND SENIOR MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DESCRIPTION OF THE NOTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
BOOK-ENTRY; DELIVERY AND FORM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TAXATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TRANSFER RESTRICTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
INDEPENDENT ACCOUNTANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LIMITATIONS ON ENFORCEMENT OF U.S. LAWS AGAINST THE GUARANTOR, THE ISSUER,
THEIR MANAGEMENT, AND OTHERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GENERAL INFORMATION ABOUT THE ISSUER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
5
6
7
8
22
35
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37
38
90
180
189
199
204
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216
220
221
222
234
F-1
You should rely on the information contained in this offering memorandum. We have not, and the
Initial Purchasers have not, authorized any other person to provide you with different information. If
anyone provides you with different or inconsistent information, you should not rely on it. You should
assume that the information appearing in this offering memorandum is accurate as of the date on the front
cover of this offering memorandum only. Our business, financial condition, results of operations and
prospects may have changed since that date.
This offering memorandum is confidential. You are authorized to use this offering memorandum solely for
the purpose of considering the purchase of the Notes described in this offering memorandum. You may not
reproduce or distribute this offering memorandum, in whole or in part, and you may not disclose any of the
contents of this offering memorandum or use any information herein for any purpose other than considering a
purchase of the Notes. You agree to the foregoing by accepting delivery of this offering memorandum.
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED
STATUTES (“RSA”) WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A
SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW
HAMPSHIRE IMPLIES THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE
AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT ANY EXEMPTION
OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE
SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS
OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR
TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE
PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE
PROVISIONS OF THIS PARAGRAPH.
1
This offering memorandum has been prepared on the basis that any offer of Notes in any Member State of
the European Economic Area which has implemented the Prospectus Directive (2003/71/EC) (each, a “Relevant
Member State”) will be made pursuant to an exemption under the Prospectus Directive, as implemented in that
Relevant Member State, from the requirement to publish a prospectus for offers of Notes. Accordingly any
person making or intending to make an offer in that Relevant Member State of Notes which are the subject of the
offering contemplated in this offering memorandum may only do so in circumstances in which no obligation
arises for the Issuer or any of the Initial Purchasers to publish a prospectus pursuant to Article 3 of the Prospectus
Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive, in each case, in relation
to such offer. Neither the Issuer nor the Initial Purchasers have authorised, nor do they authorise, the making of
any offer of Notes in circumstances in which an obligation arises for the Issuer or the Initial Purchasers to
publish or supplement a prospectus for such offer.
Each Initial Purchaser, other than Goldman, Sachs & Co., represents and agrees with the Issuer that it has
not offered or sold and will not offer or sell any of the Notes in The Netherlands other than through one or more
investment firms acting as principals and having the Dutch regulatory capacity to make such offers or sales.
Each investor in the Notes will be deemed to make certain representations, warranties and
agreements regarding the manner of purchase and subsequent transfers of the Notes. These
representations, warranties and agreements are described in “Transfer Restrictions.”
The Initial Purchasers make no representation or warranty, expressed or implied, as to the accuracy or
completeness of such information, and nothing contained in this offering memorandum is, or shall be relied upon
as, a promise or representation by the Initial Purchasers. Neither we, nor the Initial Purchasers, nor any of our or
their respective representatives make any representation to any offeree or purchaser of the Notes offered hereby
regarding the legality of an investment by such offeree or purchaser under applicable legal investment or similar
laws. You should consult with your own advisors as to legal, tax, business, financial and related aspects of a
purchase of the Notes. Notwithstanding anything herein to the contrary, investors may disclose to any and all
persons, without limitation of any kind, the U.S. federal or state income tax treatment and tax structure of the
offering and all materials of any kind (including opinions or other tax analyses) that are provided to the investors
relating to such tax treatment and tax structure. However, any information relating to the U.S. federal income tax
treatment or tax structure shall remain confidential (and the foregoing sentence shall not apply) to the extent
reasonably necessary to enable any person to comply with applicable securities laws. For this purpose, “tax
structure” means any facts relevant to the U.S. federal or state income tax treatment of the offering but does not
include information relating to the identity of the issuer of the securities, the issuer of any assets underlying the
securities, or any of their respective affiliates that are offering the securities.
IN CONNECTION WITH THE OFFERING, BANC OF AMERICA SECURITIES LLC, ACTING FOR
THE BENEFIT OF THE INITIAL PURCHASERS, MAY PURCHASE AND SELL NOTES IN THE OPEN
MARKET. THESE TRANSACTIONS MAY INCLUDE OVER-ALLOTMENT, SYNDICATE COVERING
AND STABILIZING TRANSACTIONS. OVER-ALLOTMENT INVOLVES SALES OF NOTES IN EXCESS
OF THE PRINCIPAL AMOUNT OF THE NOTES TO BE PURCHASED IN THE OFFERING, WHICH
CREATES A SHORT POSITION. SYNDICATE COVERING INVOLVE PURCHASES OF THE NOTES IN
THE OPEN MARKET AFTER THE DISTRIBUTION HAS BEEN COMPLETED IN ORDER TO COVER
SHORT POSITIONS CREATED. STABILIZING TRANSACTIONS CONSIST OF CERTAIN BIDS OR
PURCHASES OF NOTES MADE FOR THE PURPOSE OF PEGGING, FIXING OR MAINTAINING THE
PRICE OF THE NOTES. ANY STABILIZATION ACTION OR OVER-ALLOTMENT MUST BE
CONDUCTED BY THE RELEVANT STABILIZING MANAGER(S) (OR PERSON(S) ACTING ON
BEHALF OF ANY STABILIZING MANAGER(S)) IN ACCORDANCE WITH ALL APPLICABLE LAWS
AND RULES.
2
IN CONNECTION WITH THIS OFFERING, THE INITIAL PURCHASERS ARE NOT ACTING
FOR ANYONE OTHER THAN THE ISSUER AND WILL NOT BE RESPONSIBLE TO ANYONE
OTHER THAN THE ISSUER FOR PROVIDING THE PROTECTIONS AFFORDED TO THEIR
CLIENTS NOR FOR PROVIDING ADVICE IN RELATION TO THE OFFERING.
NOTICE TO INVESTORS IN THE UNITED KINGDOM
This offering memorandum is for distribution within the United Kingdom only to persons who (i) have
professional experience in matters relating to investments falling within Article 19(5) of the Financial Services
and Markets Act 2000 (Financial Promotion) Order 2005 (as amended, the “Financial Promotion Order”), (ii) are
persons falling within Article 49(2)(a) to (d) of the Financial Promotion Order, (iii) are outside the United
Kingdom or (iv) are persons to whom an invitation or inducement to engage in investment activity (within the
meaning of section 21 of the Financial Services and Markets Act 2000) in connection with the issue or sale of
any Notes may otherwise lawfully be communicated or caused to be communicated (all such persons together
being referred to as “Relevant Persons”). This document is directed only at Relevant Persons and must not be
acted on or relied on by persons who are not Relevant Persons. Any investment or investment activity to which
this document relates is available only to Relevant Persons and will be engaged in only with Relevant Persons.
NOTICE TO INVESTORS IN THE EUROPEAN ECONOMIC AREA
In relation to each member state of the European Economic Area which has implemented the Prospectus
Directive (each, a “Relevant Member State”), each Initial Purchaser has represented and agreed that with effect
from and including the date on which the Prospectus Directive is implemented in that Relevant Member State
(the “Relevant Implementation Date”), it has not made and will not make an offer of Notes to the public in that
Relevant Member State, except that it may, with effect from and including the Relevant Implementation Date,
make an offer of Notes to the public in that Relevant Member State:
•
to legal entities which are authorized or regulated to operate in the financial markets or, if not so
authorized or regulated, whose corporate purpose is solely to invest in securities;
•
to any legal entity which has two or more of: (i) an average of at least 250 employees during the last
financial year; (ii) a total balance sheet of more than €43,000,000; and (iii) an annual net turnover of
more than €50,000,000, as shown in its last annual or consolidated accounts;
•
to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus
Directive) subject to obtaining the prior consent of the Initial Purchasers for any such offer; or
•
in any other circumstances falling within Article 3(2) of the Prospectus Directive,
provided that no such offer of Notes shall require the Issuer or any of the Initial Purchasers to publish a
prospectus pursuant to Article 3 of the Prospectus Directive.
For the purposes of this provision, the expression an “offer of Notes to the public” in relation to any Notes
in any Relevant Member State means the communication in any form and by any means of sufficient information
on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe
to the Notes, as the same may be varied in that Relevant Member State by any measure implementing the
Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive
2003/71/EC and includes any relevant implementing measure in each Relevant Member State.
3
CERTAIN DEFINITIONS
“E.ON,” the “Company,” “we”, “us”, “our”, the “E.ON Group” or the “Group” refers to E.ON AG and its
consolidated subsidiaries. The “Guarantor” refers to E.ON AG.
“VEBA” refers to VEBA AG and its consolidated subsidiaries prior to its merger with VIAG AG and the
name change from VEBA AG to E.ON AG. “VIAG” or the “VIAG Group” refers to VIAG AG and its
consolidated subsidiaries prior to its merger with VEBA.
“PreussenElektra” refers to PreussenElektra AG and its consolidated subsidiaries, which merged with
Bayernwerk AG and its consolidated subsidiaries to form E.ON’s German and continental European energy
business in the Central Europe market unit, consisting of E.ON Energie AG and its consolidated subsidiaries
(“E.ON Energie”).
“E.ON Ruhrgas” refers to E.ON Ruhrgas AG (formerly Ruhrgas AG or “Ruhrgas”) and its consolidated
subsidiaries, which collectively comprise E.ON’s gas business in the Pan-European Gas market unit.
“E.ON UK” refers to E.ON UK plc (formerly Powergen UK plc or “Powergen”) and its consolidated
subsidiaries, which collectively comprise E.ON’s U.K. energy business in the U.K. market unit. Until
December 31, 2003, Powergen and its consolidated subsidiaries, including LG&E Energy LLC (“LG&E
Energy”), which was held by Powergen until its transfer to a direct subsidiary of E.ON AG in March 2003,
formed E.ON’s former Powergen division (“Powergen Group”).
“E.ON Sverige” refers to E.ON Sverige AB (formerly Sydkraft AB or “Sydkraft”) and its consolidated
subsidiaries, and “E.ON Finland” refers to E.ON Finland Oyj and its consolidated subsidiaries, which
collectively comprised E.ON’s Nordic energy business in the Nordic market unit until the disposal of E.ON
Finland.
“E.ON U.S.” refers to E.ON U.S. LLC (formerly LG&E Energy) and its consolidated subsidiaries, which
collectively comprise E.ON’s U.S. energy business in the U.S. Midwest market unit. Until December 31, 2003,
E.ON U.S. formed the U.S. business of the Powergen Group.
“Viterra” refers to Viterra AG and its consolidated subsidiaries, which collectively comprised E.ON’s real
estate business in the other activities segment.
“Degussa” refers to Degussa AG and its consolidated subsidiaries, which collectively comprised E.ON’s
chemicals business in the other activities segment.
“VEBA Oel” refers to VEBA Oel AG and its consolidated subsidiaries, which collectively comprised
E.ON’s former oil division.
“VAW” refers to VAW aluminium AG and its consolidated subsidiaries, which collectively comprised
E.ON’s former aluminum division.
As used in this offering memorandum, “euro” or “€” means the single unified currency that was introduced
in Germany on January 1, 1999; “U.S. dollar,” “U.S.$,” “USD” or “$” means the lawful currency of the United
States of America; “GBP” means the lawful currency of the United Kingdom; and “CHF” means the lawful
currency of Switzerland. “Germany” means the Federal Republic of Germany.
A watt is a standard measure of electric power. “kW” means kilowatt, which is equal to 1,000 watts, “MW”
means megawatt, which is equal to 1,000 kilowatts, or one million watts, “GW” means gigawatt, which is equal
to 1,000 megawatts, and “TW” means terawatt, which is equal to 1,000 gigawatts. MW is a standard measure of
electric power plant generating capacity. “kWh” means kilowatt-hour and is a standard unit of energy. “MWh”
means megawatt-hour, which is equal to 1,000 kilowatt-hours, “GWh” means gigawatt-hour, which is equal to
1,000 megawatt-hours, and “TWh” means terawatt-hour, which is equal to 1,000 gigawatt-hours.
4
PRESENTATION OF FINANCIAL DATA
Accounting Principles
In 2002, the European Parliament and the European Council mandated the adoption of International
Financial Reporting Standards (“IFRS”), as adopted by the European Union (“EU”), by companies whose
securities are publicly traded on a regulated market in an EU member state, in respect of fiscal years beginning
on or after January 1, 2005. E.ON made use of the option available under German law for companies that had
been preparing their consolidated financial statements in accordance with generally accepted accounting
principles in the United States (“U.S. GAAP”) and whose stock was officially listed for public trading in a
non-EU member state to defer the mandatory adoption of IFRS until 2007. Until December 31, 2006, E.ON
prepared its financial statements in accordance with U.S. GAAP. E.ON’s American Depositary Shares (“ADSs”)
were listed on the New York Stock Exchange until September 7, 2007. The Company deregistered and
terminated its reporting obligations with the U.S. Securities and Exchange Commission (the “SEC”) as of
December 2007.
E.ON’s consolidated financial statements for the year ended December 31, 2007, as included in this offering
memorandum, have been prepared in accordance with IFRS 1, First-time Adoption of International Financial
Reporting Standards (“IFRS 1”). These consolidated financial statements have also been prepared in accordance
with Article 315a (1) of the German Commercial Code (Handelsgesetzbuch, or “HGB”) and with those IFRS and
International Financial Reporting Interpretations Committee (“IFRIC”) interpretations that had been adopted by
the European Commission for use in the EU as of the end of the fiscal year, and whose application was
mandatory as of December 31, 2007. In addition, E.ON has elected the voluntary early adoption of IFRS 8,
Operating Segments (“IFRS 8”). E.ON’s consolidated financial statements through the year ended December 31,
2006 were prepared in accordance with U.S. GAAP. For information about the effects of the transition from U.S.
GAAP to IFRS, see Note 35 of the Notes to Consolidated Financial Statements.
The analysis of E.ON’s consolidated results and those of its individual market units in 2007 and 2006
presented in this offering memorandum under “Operating and Financial Review and Prospects” has been
prepared using the financial statements prepared in accordance with IFRS. As E.ON has not prepared any
financial statements for 2005 in accordance with IFRS, the parallel year-on-year analysis of our results for 2005
and 2006 (see “Operating and Financial Review and Prospects — Year Ended December 31, 2006 Compared
with Year Ended December 31, 2005”) has been prepared on the basis of E.ON’s U.S. GAAP consolidated
financial statements (included in our Annual Report on Form 20-F for the fiscal year ended December 31, 2006
and incorporated herein by reference). Unless otherwise indicated, financial data for 2006 appearing outside of
such year-on-year analysis (e.g., in the analysis of Liquidity and Capital Resources and that of Cash Flow and
Capital Expenditures) (see “Operating and Financial Review and Prospects — Liquidity and Capital Resources”),
has been prepared in accordance with IFRS.
Sales
Unless otherwise indicated, sales are presented net of electricity and energy taxes.
Non-GAAP Measures
E.ON uses “adjusted EBIT” as the measure pursuant to which the Group evaluates the performance of its
segments and allocates resources to them. Adjusted EBIT is an adjusted figure derived from income/(loss) from
continuing operations (before intra-Group eliminations when presented on a segment basis) before income taxes
and interest income. Adjustments include net book gains resulting from disposals, as well as cost-management
and restructuring expenses and other non-operating earnings of an exceptional nature. In addition, net interest
income is adjusted using economic criteria and excluding certain special items, (i.e., the portions of interest
expense that are non-operating). During all relevant periods, E.ON has used adjusted EBIT as its primary
segment reporting measure, originally in accordance with Statement of Financial Accounting Standards
5
(“SFAS”) No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS 131”) under
U.S. GAAP, and now in accordance with IFRS 8. However, on a consolidated Group basis, adjusted EBIT is
considered a non-GAAP measure that should be reconciled to the most directly comparable GAAP measure.
Adjusted EBIT should not be considered in isolation as a measure of E.ON’s profitability and should be
considered in addition to, rather than as a substitute for the most directly comparable GAAP measures. In
particular, there are material limitations associated with the use of Adjusted EBIT as compared with such GAAP
measures, including the limitations inherent in E.ON’s determination of each of the adjustments noted above.
E.ON seeks to compensate for those limitations by providing below a detailed reconciliation of adjusted EBIT to
income from continuing operations before income taxes and minority interests and net income, the most directly
comparable GAAP measures, as well as the more detailed textual analysis of year-on-year changes in the key
components of each of the reconciling items appearing under the caption “Operating and Financial Review and
Prospects — Results of Operations — E.ON Group — Reconciliation of Adjusted EBIT” for each of the relevant
periods. As a result of these limitations and other factors, adjusted EBIT as used by E.ON may differ from, and
not be comparable to, similarly titled measures used by other companies. For further details, see Note 33 of the
Notes to Consolidated Financial Statements.
E.ON has calculated operating data for Group companies appearing in this document using actual amounts
derived from Group books and records. The Company has obtained market-related data such as the market
position of Group companies from publicly available sources such as industry publications. The Company has
relied on the accuracy of information from publicly available sources without independent verification, and does
not accept any responsibility for the accuracy or completeness of such information.
Incorporation of Certain Financial Statements by Reference
We incorporate by reference herein our consolidated financial statements, and accompanying notes and
report of independent registered public accounting firm, at December 31, 2006 and 2005 and for the years ended
December 31, 2006, 2005 and 2004, filed as part of our annual report on Form 20-F for the fiscal year ended
December 31, 2006 filed with the SEC on March 7, 2007 (the “Form 20-F for 2006”). No materials from the SEC
website or any other source other than those specifically identified above are incorporated by reference into this
offering memorandum.
Any statement contained in the information that is incorporated by reference will be modified or superseded
for all purposes to the extent that a statement contained in this offering memorandum modifies or is contrary to
that previous statement. Any statement so modified or superseded will not be deemed a part of this offering
memorandum except as so modified and superseded.
AVAILABLE INFORMATION
For so long as any of the Notes remain outstanding and are “restricted securities” within the meaning of
Rule 144(a)(3) under the Securities Act and during any period in relation thereto during which the Guarantor is
neither subject to sections 13 or 15(d) of the Exchange Act nor exempt from reporting pursuant to Rule 12g32(b) under the Exchange Act, the Issuer and the Guarantor will make available on request to each holder in
connection with any resale thereof and to any prospective purchaser of such Notes from such holder, in each case
upon request, the information specified in and meeting the requirements of Rule 144A(d)(4) under the Securities
Act.
A copy of the Fiscal and Paying Agency Agreement is available to prospective investors in the Notes upon
request, at no charge, from HSBC Bank USA, N.A., at 10 East 40th Street, New York, NY10016.
6
FORWARD-LOOKING STATEMENTS
This offering memorandum contains certain forward-looking statements and information relating to E.ON
that are based on beliefs of its management, as well as assumptions made by and information currently available
to E.ON. When used in this offering memorandum, the words “anticipate,” “believe,” “estimate,” “expect,”
“intend,” “plan” and “project” and similar expressions, as they relate to E.ON or its management, are intended to
identify forward-looking statements. Such statements reflect the current views of E.ON with respect to future
events and are subject to certain risks, uncertainties and assumptions. Many factors could cause the actual results,
performance or achievements of E.ON to be materially different from any future results, performance or
achievements that may be expressed or implied by such forward-looking statements, including, among others,
strong competition in our core energy operations that could depress margins, changes in applicable laws and
regulations as well as the introduction of new laws and regulations, rising fuel prices, unreliable gas supplies
from Russia, revenues that fluctuate by season and according to the weather, volume and price risks inherent in
our long-term gas supply contracts, cancellation of contracts due to government action, unsuccessful acquisitions
and investments, environmental liabilities, power outages or shutdowns involving our electricity operations,
litigation, actions by regulators and competition authorities and actions by credit rating agencies, and various
other factors, both referenced in this offering memorandum, including under “Risk Factors”, and not referenced
in this offering memorandum. Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual results may vary materially from those described in this offering
memorandum as anticipated, believed, estimated, expected, intended, planned or projected. E.ON does not intend
or assume any obligation to update or revise these forward-looking statements after the date of this offering
memorandum in light of developments which differ from those anticipated.
7
SUMMARY
This summary highlights some information from this offering memorandum, and it may not contain all of the
information that is important to you. You should read the following summary together with the more detailed
information regarding E.ON and the Notes being sold in this offering included in this offering memorandum.
BUSINESS OVERVIEW
Our Business
We are the largest industrial group in Germany, measured on the basis of our market capitalization of
approximately €92 billion at December 31, 2007. For the year ended December 31, 2007, we had sales of €68.7
billion, having sold 471 TWh of power and 1,212 TWh of gas. At year end, we employed 87, 815 people.
As of December 31, 2007, our core energy business was organized into the following five market units:
Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest.
Central Europe. E.ON Energie AG (“E.ON Energie”) is the lead company of our Central Europe market
unit. E.ON Energie is one of the largest non-state-owned European power companies in terms of electricity sales.
E.ON Energie’s core business consists of the ownership and operation of power generation facilities and the
transmission, distribution and sale of electricity and, to a lesser extent, gas and heat, to interregional, regional and
municipal utilities, traders and industrial, commercial and residential customers. Furthermore, E.ON Energie
operates waste incineration facilities. The Central Europe market unit owns interests in and operates power
stations with a total installed capacity of approximately 37,200 MW, of which Central Europe’s attributable share
is approximately 28,500 MW (not including mothballed, shutdown and cold reserve plants). In 2007, E.ON
Energie supplied approximately 17 percent of the electricity consumed by end users in Germany. In 2007, the
Central Europe market unit recorded revenues of €32.0 billion and an adjusted EBIT of €4.7 billion. For a
definition of adjusted EBIT, see “— Summary Consolidated Financial Data.”
Pan European Gas. E.ON Ruhrgas AG (“E.ON Ruhrgas”) is the lead company of the Pan-European Gas
market unit and is responsible for all of E.ON’s non-retail gas activities in continental Europe. E.ON Ruhrgas is
one of the leading non-state-owned gas companies in Europe and the largest gas company in Germany in terms
of gas sales, with 712.8 billion kilowatt hours (“kWh”) of gas sold in 2007. E.ON Ruhrgas’ principal business is
the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas purchases nearly all of its natural gas
from producers in six countries: Russia, Norway, the Netherlands, Germany, the United Kingdom and Denmark.
E.ON Ruhrgas sells this gas to supra-regional and regional distributors, municipal utilities and industrial
customers in Germany and increasingly also delivers gas to customers in other European countries. In addition,
E.ON Ruhrgas is active in gas transmission within Germany via a network of approximately 11,611 kilometers
(“km”) of gas pipelines and operates a number of underground storage facilities in Germany. E.ON Ruhrgas also
holds numerous stakes in German and other European gas transportation and distribution companies, as well as a
6.4 percent shareholding in OAO Gazprom, Russia’s main natural gas exploration, production, transportation and
marketing company. In 2007, the Pan-European Gas market unit recorded revenues of €22.7 billion and adjusted
EBIT of €2.6 billion.
U.K. E.ON UK plc (formerly Powergen UK plc) (“E.ON UK”) is the lead company of the U.K. market unit
and is one of the leading integrated electricity and gas companies in the United Kingdom. E.ON UK and its
associated companies are involved in electricity generation, distribution, retail and trading. As of December 31,
2007, E.ON UK owned or through joint ventures had an attributable interest in 10,581 MW of generation
capacity. E.ON UK served approximately 8.0 million electricity and gas customer accounts at December 31,
2007 and its Central Networks business served 4.9 million customer connections. In 2007, the U.K. market unit
recorded sales of €12.6 billion and an adjusted EBIT of €1.1 billion.
8
Nordic. E.ON Nordic AB (“E.ON Nordic”) is the lead company of the Nordic market unit. E.ON Nordic’s
principal business, carried out mainly through E.ON Sverige AB (“E.ON Sverige”), is the generation,
distribution, sale and trading of electricity, gas and heat and waste, mainly in Sweden. E.ON Sverige is the
second-largest Swedish utility (on the basis of electricity sales and production capacity). E.ON Nordic is the
largest shareholder in E.ON Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent voting
interest. Statkraft (“Statkraft” refers to Statkraft AS and its consolidated subsidiaries), the other shareholder in
E.ON Sverige and E.ON AG have on October 12, 2007 signed a letter of intent stating that E.ON AG will take
over Statkraft’s 44.6 percent interest in E.ON Sverige’s share capital in the second or third quarter of 2008. As of
December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power stations with a total installed
capacity of approximately 18,300 MW, of which its attributable share was approximately 7,400 MW (not
including mothballed and shutdown power plants). In 2007, E.ON Nordic recorded sales of €3.3 billion, and
adjusted EBIT of €670 million.
U.S. Midwest. E.ON U.S. LLC (“E.ON U.S.”) is the lead company of the U.S. Midwest market unit. E.ON
U.S. is a diversified energy services company with businesses in power generation, retail gas and electric utility
services, as well as asset-based energy marketing. E.ON U.S.’s power generation and retail electricity and gas
services are located principally in Kentucky, with a small customer base in Virginia and Tennessee. As of
December 31, 2007, E.ON U.S. owned or controlled aggregate generating capacity of approximately 7,500 MW.
In 2007, E.ON U.S. served more than one million customers. In 2007, the U.S. Midwest market unit recorded
sales of €1.8 billion, and adjusted EBIT of €388 million.
Corporate Center. The Corporate Center consists of E.ON AG itself, those interests owned directly and
indirectly by E.ON AG that have not been allocated to any of the other segments, including its remaining
telecommunications interests (until their disposal), and for 2007 the newly acquired companies Airtricity Inc. and
Airtricity Holdings (Canada) Ltd. (collectively “Airtricity”), ENERGI E2 Renovables Ibéricas S.L.U. (“E2-I”)
and OAO OGK-4 (“OGK-4”). The Corporate Center’s results also reflect consolidation effects at the Group
level, including the elimination of intersegment sales.
The following table sets forth the sales of E.ON’s market units (as well as the Corporate Center) for 2007
and 2006:
2007
(€ in millions)
Central Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pan-European Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nordic(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Midwest(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate Center(1)(2)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32,029
22,745
12,584
3,339
1,819
(3,785)
Total Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68,731
%
46.6
33.1
18.3
4.9
2.6
(5.5)
100.0
2006
(€ in millions)
27,197
22,947
12,518
2,827
1,930
(3,328)
64,091
%
42.5
35.8
19.5
4.4
3.0
(5.2)
100.0
(1) Excludes the sales of certain activities now accounted for as discontinued operations. For more details, see “Operating and Financial
Review and Prospects — Acquisitions and Dispositions” and Note 4 of the Notes to Consolidated Financial Statements.
(2) Includes primarily the parent company and effects from consolidation, as well as the results of certain other interests, as noted above.
(3) Excludes intercompany sales.
Most of E.ON’s operations are in Germany. German operations produced 59.1 percent of E.ON’s revenues
(measured by location of operation) in 2007 (2006: 60.8 percent). E.ON also has a significant presence outside
9
Germany representing 40.9 percent of revenues by location of operation for 2007 (2006: 39.2 percent). In 2007,
53.7 percent (2006: 54.5 percent) of E.ON’s revenues were derived from customers in Germany and 46.3 percent
(2006: 45.5 percent) from customers outside Germany. For more details about the segmentation of E.ON’s
revenues by location of operation and customers for the years 2007 and 2006, see Note 33 of the Notes to
Consolidated Financial Statements. At December 31, 2007, E.ON had 87,815 employees, approximately 39.4
percent of whom were employed in Germany. For more information about employees, see “Business —
Employees.”
Recent Developments
New Market Units
Since January 1, 2008, E.ON has been organized into nine different market units having added the Energy
Trading, Italy, Russia and Climate & Renewables market units. After completing the acquisition of Viesgo and
additional generation capacity from Endesa in Spain, these operations are expected to be organized in a new tenth
market unit. For information about the planned acquisition, see “Business — History and Development of the
Company.” Until the end of 2008, the results of each of the new market units other than Energy Trading will be
reported as part of the Corporate Center segment; Energy Trading’s results will be reported separately. The detailed
discussion of each of the five existing market units that follows is based on their operations as of year-end 2007, and
thus does not fully reflect intra-Group transfers of assets or operations to the new market units.
Energy Trading. E.ON Energy Trading AG (“EET”) is the lead company of the Energy Trading market
unit. EET began operations in January 2008, and combines all our European trading activities, including those
relating to electricity, gas, coal, oil and CO2 emission allowances. We have created EET with the goal of taking
advantage of the opportunities created by the increasing integration of Europe’s power and gas markets and those
present in global commodity markets.
Russia. E.ON Russia Power (“E.ON Russia”) is the lead company of the E.ON Russia market unit. E.ON
Russia oversees our power business in Russia. In October 2007, we acquired a majority stake in the Russian
power generation company OGK-4. E.ON now holds 76.1 percent of OGK-4’s capital stock. OGK-4 operates
five conventional power stations at different locations with a total installed capacity of 8.6 gigawatts (“GW”).
For additional details on the OGK-4 acquisition, see “Operating and Financial Review and Prospects —
Acquisitions and Dispositions.”
Italy. E.ON Italia S.p.A. (“E.ON Italia”) is the lead company of the Italy market unit. E.ON Italia manages
our power and gas business in Italy, and is active in Italy’s wholesale power and gas markets and in natural gas
sales. The expected acquisition of 80% of Endesa Italia, with approximately 7.200 MW of generating capacity in
Italy will further enhance our generation portfolio. For information about the planned acquisition, see “Operating
and Financial Review and Prospects — Acquisitions and Dispositions”
Climate & Renewables. E.ON Climate & Renewables GmbH (“C&R”) is the lead company of the
Climate & Renewables market unit. C&R is responsible for managing and expanding our global renewables
business and for coordinating climate-protection projects. C&R has about 760 MW of generating capacity in
Europe and approximately 250 MW in North America.
Valuation of Viesgo and Endesa assets
On March 28, 2008, our Board of Management and Supervisory Board approved the acquisition from
Acciona S.A. and Enel S.p.A. of a substantial package comprising the Enel subsidiary Enel Viesgo in Spain and
power plants and other shareholdings of Endesa in Spain, France and Italy (such acquired Endesa operations,
“Endesa Europe”). The valuation process of the assets, which was agreed on April 2, 2007 as the basis for
10
determining the final enterprise value of the asset package, has now been completed on schedule. The transaction
value totals approximately €11.8 billion: €2 billion for Viesgo, €750 million for the additional Spanish
generation assets, and €9.1 billion for Endesa Europe. On the basis of a consolidated net debt of approximately
€2.9 billion, the equity purchased would amount to approximately €8.9 billion. The final net debt figure still has
to be determined according to the provisions of the agreement of April 2, 2007. The completion of the transaction
is likely to take place in the third quarter of 2008 once all permits are available.
Our Strategy
Introduction
We have five key beliefs about sustainable market success:
•
Vertical integration — Being present in all parts of the value chain in Generation/Gas Exploration &
Production (Upstream), Supply & Trading (Midstream) and Sales (Downstream) will be the long-term
winning business model for energy utilities.
•
Convergence of power & gas — Since convergence of the power and gas markets creates economies of
scope, a strong presence in both markets will be a key competitive advantage and driver for value creation.
•
Strong market positions in a competitive market environment — In liberalized markets, scale is a key
competitive edge. Competitive markets with strong integrated players with a long-term view provide the
best reliability and security of supply.
•
Growth — Organic growth is a prerequisite for continuous value creation. Given rather moderate
growth rates in mature markets, external growth is required to create above-average value.
•
Value from experience — A leading player can create more value from holding energy assets even in
disconnected markets based on its experience and expertise of managing a broad range of assets in
different energy markets.
Based on these beliefs, we pursue a clear strategic direction and business model.
An Integrated Power and Gas Business. We pursue an integrated power and gas business model that builds
on leading positions in our respective markets. In doing so, we seek to develop positions throughout the energy
value chain, including positions in infrastructure where they are seen as enhancing our access to markets and
customers.
A Clear Geographical Focus. We seek to strengthen our leading positions and performance in our existing
markets (Central Europe, Pan European Gas, U.K., Nordic and U.S. Midwest) as well as in our new markets in
Russia, Spain and Italy. We also see further growth opportunities in neighboring markets in Southeast Europe
and in Turkey. We also seek to grow our renewables and Joint Implementation/Clean Development Mechanism
(“JI/CDM”) business in attractive global markets.
Clear Strategic Priorities. Our first priority is to strengthen and grow our position in our core European
markets. In generation we seek to expand our generation capacity in Europe by 50 percent by 2010, as compared
to May 2007. We intend to integrate and strengthen the assets we expect to acquire in Spain, Italy and France
from Enel/Acciona. We also seek to significantly expand our renewables portfolio and our climate protection
efforts in the JI/CDM framework. We have set ourselves the objective to reduce our specific CO2 emissions by 50
percent by 2030 compared to the levels of 1990. We aim to strengthen our gas supply position through our own
production and potentially through liquefied natural gas (“LNG”).
Strict Investment Criteria. In following this model, we apply strict strategic and financial criteria to each
potential investment, focusing on those which management believes exhibit the potential for material value
creation.
11
Strategy
Building on this model, our corporate strategy is to maximize the value of our portfolio of focused energy
businesses through:
•
Creating value from the further increasing convergence of European energy markets (e.g., as the United
Kingdom becomes a net importer of gas and can take advantage of greater pipeline capacity connecting
it to continental Europe, we will be able to supply its retail gas business in the United Kingdom from
our Pan European Gas supply business);
•
Creating value from vertical integration (i.e., establishing a presence in all parts of the value chains for
both power and gas);
•
Creating value from the convergence of the electricity and gas value chains (e.g., offering retail
electricity and gas customers energy from a single source), thus providing us with opportunities to
realize economies of scale in servicing costs while increasing customer loyalty;
•
Enhancing operational performance through identifying and transferring best practice for common
activities throughout our different market units (e.g., effective programs for enhancing our electricity
generation, distribution and retailing businesses);
•
Improving our competitive position in our target markets, through both organic and external growth by
pursuing selective investments which contribute to these objectives or provide stand alone valuecreation opportunities, as described below;
•
Creating a common corporate culture under the One E.ON initiative, which seeks to enhance integration
of all market units and their subsidiaries under the E.ON banner so as to help us realize our vision and
strategic goals, while maintaining our commitment to corporate social responsibilities; and
•
Tapping value-enhancing growth potential in new markets such as Southeast Europe and Turkey.
The investment plan 2008-2010 focuses on growth in conventional power generation, renewables and gas.
Investments will amount to approximately €50 billion within that period.
The financial strategy of E.ON consists of the following four elements:
(1) E.ON’s target rating is a single A flat/A2 rating. This rating target was already determined in the context of
the offer for the Endesa takeover and was confirmed in May 2007. In comparison to the previous rating
target of a strong single A, the new rating target allows for a higher level of indebtedness and thus improves
the efficiency of E.ON’s capital structure, whilst at the same time ensuring access to the capital markets.
(2) For the future management of the capital structure, E.ON has introduced a new steering measure, the Debt
Factor, which is the ratio between Economic Net Debt (a new key figure which supplements net financial
position with provisions for pensions and provisions for waste management and asset retirement obligations
(less prepayments)) and adjusted EBITDA. E.ON is targeting a Debt Factor of 3, which is derived from the
target rating.
(3) Going forward, E.ON intends to actively manage its capital structure. Based on the Debt Factor, the capital
structure will be monitored continuously and optimized if necessary. If the Debt Factor is significantly
above 3, strict discipline regarding investments will be required. In case of investments with strategic
importance, financing measures with a countereffect or capital increases will be carried out. If it becomes
apparent that the Debt Factor will sustainably fall below 3, E.ON will return more capital to its shareholders,
for example by paying out higher dividends or buying back stock. However, priority will be given to valuecreating investments.
(4) The target for the dividend payout ratio and thus for regular dividends continues to be a range between 50
and 60 percent of adjusted net income.
12
E.ON has been conducting a share buyback program with a volume of approximately €7 billion. The share
buyback program is planned to be completed by the end of 2008, by which time we will also be able to achieve
the targeted Debt Factor. As of December 31, 2007, we had repurchased 27,974,944 of our shares under this
program. In December 2007, we cancelled 25,000,000 shares, thereby reducing E.ON’s capital stock.
Apart from the overall strategy, we have set a number of specific objectives for our market units in
implementing our corporate strategy within each of our target markets, namely:
Central Europe — Fortifying strong market position and developing new growth potential through:
•
Preparing for generation reinvestments.
•
Broadening scope of power generation.
•
Hedging retail positions in Eastern Europe with generation assets.
•
Realizing regional and power/gas downstream synergies.
•
Integrating and strengthening assets acquired under our agreement with Enel/Acciona in France and
Poland.
•
Participating in privatization processes in Southeast Europe providing new growth opportunities.
Pan European Gas — Strengthening and diversifying E.ON Ruhrgas’ current position through:
•
Expanding own gas production to at least 10 billion m3/year.
•
Examining entry possibilities into the LNG business.
•
Strengthening cooperation and partnership with producers.
•
Further expansion of our pan-European gas supplier role.
•
Investing in selected infrastructure projects to secure European gas supply: import infrastructure,
interconnectors, storage investments.
U.K. — Strengthening our U.K. businesses through:
•
Investing in more diverse and less CO2-intensive generation, including renewables.
•
Continued cost improvements in distribution and retail.
•
Investing in flexible gas storage assets and gas supply infrastructure as the U.K. shifts to a net-importer
gas position.
Nordic — Strengthening our position through:
•
Growth through opportunities for consolidation in the fragmented Nordic market.
•
Further developing a diversified generation portfolio.
•
Identifying acquisition opportunities providing synergies in distribution, retail and heating in Sweden,
Denmark and Finland.
U.S. Midwest — Focusing on optimizing E.ON U.S.’s current operations through:
•
Maintaining a sustainable competitive position through a stable regulatory environment in Kentucky and
strong local market coverage.
13
•
Continuing performance improvement of existing business.
•
Making focused capital investments in generation.
•
Growth in the long-term through consolidation opportunities in a fragmented market.
14
SUMMARY CONSOLIDATED FINANCIAL DATA
Through the fiscal year ending December 31, 2006, we prepared our consolidated financial statements in
accordance with U.S. GAAP, but have adopted IFRS as our primary set of accounting principles as of January 1, 2007.
We have restated our consolidated financial statements for the year ended and as at December 31, 2006, in accordance
with IFRS for comparative purposes. The summary consolidated financial data presented below as of and for each of
the years in the two-year period ended December 31, 2007 has been excerpted from or is derived from, and should be
read in conjunction with, our consolidated financial statements and related notes, prepared in accordance with IFRS, as
of and for each of the years in the two-year period ended December 31, 2007, included herein.
Year Ended December 31,
IFRS
IFRS
2007
2006
(in millions, except share amounts)
Statement of Income Data:
Sales including electricity and energy taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales excluding electricity and energy taxes(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(Loss) from continuing operations before income taxes . . . . . . . . . . . . . .
Income/(Loss) from continuing operations after income taxes(2) . . . . . . . . . . . . . .
Income/(Loss) from discontinued operations(3) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic earnings/(Loss) per share from continuing operations . . . . . . . . . . . . . . . . .
Basic earnings (Loss) per share from discontinued operations, net(3) . . . . . . . . . .
Basic earnings per share from net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Data:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquid Funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial liabilities (non-current and current) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-current financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of authorized shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Financial Data:
Adjusted EBIT(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
€
70,761
68,731
9,683
7,394
330
7,724
7,204
520
10.55
0.51
11.06
€
137,294
7,075
21,464
15,915
49,374
667,000,000
€
€
9,208
67,653
64,091
5,347
5,307
775
6,082
5,586
496
7.31
1.16
8.47
127,575
6,189
13,472
10,029
48,712
692,000,000
8,356
(1) Laws in Germany and other European countries in which E.ON operates require the seller of electricity to collect electricity taxes and
remit such amounts to tax authorities. Similar laws also require the seller of natural gas to collect and remit natural gas taxes to tax
authorities.
(2) Before minority interest of €520 million for 2007, as compared with €496 million for 2006.
(3) For more details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for each
period and Note 4 of the Notes to Consolidated Financial Statements.
(4) Adjusted EBIT is the measure pursuant to which we have evaluated the performance of our segments and allocated resources to them.
Adjusted EBIT is derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment
basis) before income taxes and minority interests, excluding interest income, and adjusted for items that management believes are nonrecurring items. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and
other non-operating earnings of a non-recurring nature. In addition, interest income is adjusted using economic criteria. In particular, the
interest portion of additions to provisions for pensions and nuclear waste management is allocated to adjusted interest income. On a
consolidated Group basis adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable
IFRS measure, net income. Adjusted EBIT should not be considered in isolation as a measure of our profitability and should be
considered in addition to, rather than as a substitute for, net income. In particular, there are material limitations associated with the use of
adjusted EBIT as compared with such IFRS measure, including the limitations inherent in our determination of each of the adjustments
noted above. We seek to compensate for these limitations by providing a detailed reconciliation of adjusted EBIT to net income, the most
directly comparable IFRS measure, in “Operating and Financial Review and Prospects” on page 52. As a result of these limitations and
other factors, adjusted EBIT as used by us may differ from, and not be comparable to, similarly titled measures used by other companies.
15
The summary consolidated financial data presented below as of and for each of the years in the two-year
period ended December 31, 2006 has been excerpted from or is derived from and should be read in conjunction
with, our consolidated financial statements and related notes, prepared in accordance with U.S. GAAP, as of and
for each of the years in the two-year period ended December 31, 2006, incorporated herein by reference.
Year Ended December 31,
U.S. GAAP
U.S. GAAP
2006
2005
(in millions, except share amounts)
Statement of Income Data:
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . €
67,759 €
56,141
64,197
51,616
Sales excluding electricity and petroleum taxes(1) . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(Loss) from continuing operations before income taxes . . . . . . . . . . . . . .
5,133
7,152
Income/(Loss) from continuing operations after income taxes and before
5,456
4,891
minority interests(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(Loss) from continuing operations after income taxes . . . . . . . . . . . . . . .
4,930
4,355
127
3,059
Income/(Loss) from discontinued operations, net applicable income taxes(3) . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,057
7,407
Basic earnings/(Loss) per share from continuing operations . . . . . . . . . . . . . . . . .
7.48
6.61
0.19
4.64
Basic earnings (Loss) per share from discontinued operations, net(3) . . . . . . . . . . .
7.67
11.24
Basic earnings per share from net income(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Data:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . €
127,232 €
126,562
Non-current financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,959
10,555
47,845
44,484
Shareholder’s equity(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of authorized shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 692,000,000
692,000,000
Other Financial Data:
8,150
7,293
Adjusted EBIT(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1) Laws in Germany and other European countries in which E.ON operates require the seller of electricity to collect electricity taxes and
remit such amounts to tax authorities. Similar laws also require the seller of natural gas to collect and remit natural gas taxes to tax
authorities.
(2) Before minority interest of €526 million for 2006 according to U.S. GAAP, and €536 million for 2005 according to U.S. GAAP.
(3) For more details, see “Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for each
period and Note 4 of the Notes to Consolidated Financial Statements.
(4) Includes earnings per share from the first-time application of new U.S. GAAP standards of negative €0.01 in 2005. There was no such
effect on 2006.
(5) Under U.S. GAAP equal to stockholders’ equity, after minority interests.
(6) Adjusted EBIT is the measure pursuant to which we have evaluated the performance of our segments and allocated resources to them.
Adjusted EBIT is derived from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment
basis) before income taxes and minority interests, excluding interest income, and adjusted for items that management believes are nonrecurring items. Adjustments include net book gains resulting from disposals, as well as cost-management and restructuring expenses and
other non-operating earnings of a non-recurring nature. In addition, interest income is adjusted using economic criteria. In particular, the
interest portion of additions to provisions for pensions and nuclear waste management is allocated to adjusted interest income. On a
consolidated Group basis adjusted EBIT is considered a non-GAAP measure that must be reconciled to the most directly comparable
U.S. GAAP measure, net income. Adjusted EBIT should not be considered in isolation as a measure of our profitability and should be
considered in addition to, rather than as a substitute for, net income. In particular, there are material limitations associated with the use of
adjusted EBIT as compared with such U.S. GAAP measure, including the limitations inherent in our determination of each of the
adjustments noted above. We seek to compensate for these limitations by providing a detailed reconciliation of adjusted EBIT to net
income, the most directly comparable U.S. GAAP measure, in “Operating and Financial Review and Prospects” on page 65. As a result
of these limitations and other factors, adjusted EBIT as used by us may differ from, and not be comparable to, similarly titled measures
used by other companies.
16
THE OFFERING
The following summary contains basic information about the Notes and is not intended to be complete. It does
not contain all the information that is important to you. For a more complete understanding of the Notes, please
refer to the section of this offering memorandum entitled “Description of the Notes”.
Issuer . . . . . . . . . . . . . . . . . . . . . . . . . . . E.ON International Finance B.V. (the “Issuer”).
Guarantor . . . . . . . . . . . . . . . . . . . . . . . E.ON AG (the “Guarantor”).
Securities offered . . . . . . . . . . . . . . . . . . $2,000,000,000 aggregate principal amount of 5.80% senior notes due
2018 (the “2018 Notes”)
$1,000,000,000 aggregate principal amount of 6.65% senior notes due
2038 (the “2038 Notes” and, together with the 2018 Notes, the
“Notes”). The Notes will be unconditionally and irrevocably
guaranteed by the Guarantor. The Notes will mature on April 30, 2018
and April 30, 2038, respectively, and are redeemable prior to maturity
as described in “Description of the Notes — Optional Redemption” and
“Description of the Notes — Optional Tax Redemption”.
Issue price . . . . . . . . . . . . . . . . . . . . . . . . 99.578% of the principal amount of the 2018 Notes and 99.572% of
the principal amount of the 2038 Notes.
Ranking of the Notes . . . . . . . . . . . . . . . The Notes will be the direct, unconditional, unsecured and
unsubordinated general obligations of the Issuer. The Notes will rank
pari passu among themselves, without any preference of one over the
other by reason of priority of date of issue or otherwise, and at least
equally with all other unsecured and unsubordinated general
obligations of the Issuer from time to time outstanding.
Ranking of the guarantees . . . . . . . . . . Each Note will benefit from an unconditional and irrevocable
guarantee by the Guarantor (each a “Guarantee” and collectively the
“Guarantees”). The Guarantees will be the direct, unconditional,
unsecured and unsubordinated general obligations of the Guarantor.
The Guarantees will rank pari passu among themselves, without any
preference of one over the other by reason of priority of date of issue
or otherwise, and at least equally with all other unsecured and
unsubordinated general obligations of the Guarantor from time to
time outstanding.
Minimum denomination . . . . . . . . . . . . The Notes will be issued in denominations of $1,000 and integral
multiples of $1,000 in excess thereof.
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . The 2018 Notes will bear interest at the rate per annum of 5.80% and
the 2038 Notes will bear interest at the rate per annum of 6.65%, in
each case from April 22, 2008. Interest on the Notes will be payable
semiannually in arrears on October 30 and April 30 of each year,
commencing on October 30, 2008 (or, if any such date is not a
business day, on the next succeeding business day) until the principal
17
of the Notes is paid or duly made available for payment. Interest on
the Notes will be calculated on the basis of a 360-day year consisting
of twelve 30-day months. Interest on the Notes will be paid to the
persons in whose names the Notes (or one or more predecessor Notes)
are registered on the October 15 and April 15, as the case may be,
immediately preceding the applicable interest payment date, whether
or not such date is a business day.
Business day . . . . . . . . . . . . . . . . . . . . . . The term “business day” means any day other than a day on which
commercial banks or foreign exchange markets are permitted or required
to be closed in New York City, London, Frankfurt am Main or
Amsterdam. If the date of payment of interest on or principal of the Notes
or the date fixed for redemption of any Note is not a business day, then
payment of interest or principal need not be made on such date, but may
be made on the next succeeding business day with the same force and
effect as if made on the date of payment of interest on or principal of the
Notes or the date fixed for redemption, and no interest shall accrue for the
period after such date.
Additional amounts . . . . . . . . . . . . . . . . The Issuer (and/or the Guarantor) will make all payments in respect
of the Notes without withholding or deduction for or on account of
any present or future taxes or duties of whatever nature imposed or
levied by way of withholding or deduction at source by or on behalf
of any jurisdiction in which the Issuer or Guarantor is incorporated,
organized, or otherwise tax resident or any political subdivision or
any authority thereof or therein having power to tax (the “Relevant
Taxing Jurisdiction”) unless such withholding or deduction is
required by law. In such event, the Issuer or, as the case may be, the
Guarantor will pay to the Holders such additional amounts (the
“Additional Amounts”) as shall be necessary in order that the net
amounts received by the holders of the Notes (the “Holders” and each
a “Holder”), after such withholding or deduction, shall equal the
respective amounts of principal and interest which would otherwise
have been receivable in the absence of such withholding or deduction;
except that no such Additional Amounts shall be payable on account
of any taxes or duties in the circumstances described below under
“Description of the Notes — Additional Amounts.”
References to principal or interest in respect of the Notes include any
Additional Amounts, which may be payable as set forth in the Fiscal
and Paying Agency Agreement.
Optional redemption . . . . . . . . . . . . . . . The Notes may be redeemed at any time, at the Issuer’s option, as a
whole or in part, upon not less than 30 nor more than 60 days’ prior
notice, at a redemption price equal to the greater of:
•
100% of the aggregate principal amount of the Notes to be
redeemed; and
•
as determined by the Independent Investment Banker (as defined
below), the sum of the present values of the remaining scheduled
payments of principal and interest on the Notes to be redeemed
18
(not including any portion of such payments of interest accrued to
the date of redemption) discounted to the redemption date on a
semiannual basis (assuming a 360-day year consisting of twelve
30-day months) at the Treasury Rate described herein plus 35
basis points,
plus, in each case described above, accrued and unpaid interest on the
principal amount being redeemed to (but excluding) the redemption date.
Optional tax redemption . . . . . . . . . . . . The Notes may be redeemed at any time, at the Issuer’s (or, if
applicable, the Guarantor’s) option, as a whole, but not in part, upon
not less than 30 nor more than 60 days’ prior notice, at a redemption
price equal to 100% of the principal amount of the Notes then
outstanding plus accrued and unpaid interest on the principal amount
being redeemed (and all Additional Amounts, if any) to (but
excluding) the redemption date, if (i) as a result of any change in, or
amendment to, the laws, treaties, regulations or rulings of a Relevant
Taxing Jurisdiction or in the interpretation, application or
administration of any such laws, treaties, regulations or rulings
(including a holding, judgment or order by a court of competent
jurisdiction) which becomes effective on or after the issue date (any
such change or amendment, a “Change in Tax Law”), the Issuer or (if
a payment were then due under the guarantee, the Guarantor) would
be required to pay Additional Amounts and (ii) such obligation
cannot be avoided by the Issuer (or the Guarantor) taking reasonable
measures available to it.
No notice of redemption may be given earlier than 90 days prior to
the earliest date on which the Issuer (or the Guarantor) would be
obligated to pay the additional amounts if a payment in respect of the
Notes were then due.
Holders’ option to repayment upon a
Change in Control . . . . . . . . . . . . . . . As is described in detail below under “Description of the
Notes — Holders’ Option to Repayment upon a Change in Control,”
in the event that (i) a Change of Control of the Guarantor occurs, and,
within the Change of Control Period (as defined below), a Ratings
Downgrade (as defined below) in respect of that Change of Control
occurs or is announced, any Holder may, by submitting a redemption
notice, demand from the Issuer repayment as of the Effective Date (as
defined below) of any or all of its Notes which have not otherwise
been declared due for early redemption, at their principal amount plus
interest accrued until (but excluding) the effective date (and all
Additional Amounts, if any).
Negative Pledge . . . . . . . . . . . . . . . . . . . So long as any of the Notes remains outstanding neither the Issuer nor
the Guarantor will create or permit to subsist any mortgage, charge,
pledge, lien or other encumbrance upon any or all of its present or
future assets to secure for the benefit of the holders of any present or
future Bond Issue the repayment of such present or future Bond Issue
without at the same time, or prior thereto, securing such Notes or the
19
Guarantees, as the case may be, equally and rateably therewith.
“Bond Issue” means any indebtedness of the Issuer or the Guarantor
which is, in the form of, or is represented by, any bond, security,
certificate or other instrument which is or is capable of being listed,
quoted or traded on any stock exchange or in any securities market
(including any over-the-counter market) and any guarantee or other
indemnity in respect of such indebtedness.
Use of proceeds . . . . . . . . . . . . . . . . . . . The Issuer intends to on-lend substantially all of the net proceeds
from the sale of the Notes to the Guarantor and/or entities owned
directly or indirectly by the Guarantor for general corporate purposes,
which may include financing of recently announced acquisitions.
Book-entry form . . . . . . . . . . . . . . . . . . The Notes will initially be issued to investors in book-entry form
only. Fully-registered Global Notes (as defined below) representing
the total aggregate principal amount of the Notes will be issued and
registered in the name of a nominee for DTC, the securities
depositary for the Notes, for credit to accounts of direct or indirect
participants in DTC, including Euroclear and Clearstream. Unless and
until Notes in definitive certificated form are issued, the only Holder
will be Cede & Co., as nominee of DTC, or the nominee of a
successor depositary. Except as described in this offering
memorandum, a beneficial owner of any interest in a Global Note will
not be entitled to receive physical delivery of definitive Notes.
Accordingly, each beneficial owner of any interest in a global Note
must rely on the procedures of DTC, Euroclear, Clearstream, or their
participants, as applicable, to exercise any rights under the Notes.
Governing law . . . . . . . . . . . . . . . . . . . . The Notes, the Guarantees and the fiscal and paying agency
agreement related thereto, will be governed by, and construed in
accordance with, the laws of the State of New York.
Selling restrictions . . . . . . . . . . . . . . . . . The Notes have not been registered under the U.S. Securities Act of
1933 (the “Securities Act”) or any state securities law. Unless they
are registered, the Notes may not be offered or sold except pursuant to
an exemption from or in a transaction not subject to the registration
requirements of the Securities Act and applicable state securities laws
and may only be transferred in accordance with the restrictions set out
in “Transfer Restrictions.” See, also, “Plan of Distribution”.
Additional Notes . . . . . . . . . . . . . . . . . . The Issuer may, from time to time, without notice to or the consent of
the Holders, create and issue Additional Notes, maturing on the same
maturity date and having the same terms and conditions as the
previously outstanding Notes of that series (the 2018 Notes or the
2038 Notes) in all respects (or in all respects except for the issue date
and the amount and the date of the first payment of interest thereon)
in accordance with applicable laws and regulations and pursuant to
the Fiscal and Paying Agency Agreement (including with respect to
the Guarantor and the Guarantees). Additional Notes issued in this
manner shall be consolidated with and form a single series with
previously outstanding Notes.
20
Listing and trading . . . . . . . . . . . . . . . . The Notes will not be listed on any securities exchange.
Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . A2/A (Moody’s/Standard & Poor’s).
Fiscal agent, principal paying agent,
transfer agent and registrar . . . . . . . The fiscal agent, principal paying agent, transfer agent and registrar is
HSBC Bank USA, N.A.
CUSIPs . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 Notes: 268789 AA2 (Rule 144A).
2018 Notes: N 3033QAT9 (Regulation S).
2038 Notes: 268789 AB0 (Rule 144A).
2038 Notes: N 3033QAU6 (Regulation S).
ISINs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 Notes: US 268789 AA24 (Rule 144A).
2018 Notes: USN 3033QAT96 (Regulation S).
2038 Notes: US 268789 AB07 (Rule 144A).
2038 Notes: USN3033QAU69 (Regulation S).
21
RISK FACTORS
Prospective investors in the Notes should carefully consider the following information in conjunction with
the other information contained or incorporated by reference into this document.
External Risks
Our core energy operations face strong competition, which could depress margins.
Since 1998, liberalization of the electricity markets in the EU has greatly altered competition in the German
electricity market, which was formerly characterized by numerous strong competitors. Following liberalization,
significant consolidation has taken place in the German market, resulting in four major interregional utilities:
E.ON, RWE AG (“RWE”), Vattenfall Europe AG (“Vattenfall Europe”) and EnBW Energie Baden-Württemberg
AG (“EnBW”). In addition, the market for electricity trading has become more liquid and competitive, with a
total trading volume of approximately 1,273 terrawatt hours (“TWh”) on the European Energy Exchange (EEX)
spot and futures market in 2007, and additional volumes being traded on the over-the-counter market.
Liberalization of the German electricity market also caused prices to decrease beginning in 1998, although prices
have increased since 2001. Retail prices now exceed 1998 levels, and prices for sales to distributors and
industrial customers have also increased. These price increases have generally been driven by increases in the
price of fuel, as well as regulatory and other costs, with the result that competitive pressure on margins continues
to exist. Higher wholesale prices are also expected to lead to the construction of new generation facilities,
thereby increasing competition and the pressure on margins when such facilities come into operation. Although
we intend to compete vigorously in the changed German electricity market, we cannot be certain that we will be
able to develop our business as successfully as our competitors. For information about regulatory changes that
are affecting the German electricity market, see the discussion on changes in laws and regulations below.
Outside Germany, the electricity markets in which we operate are also subject to strong competition. We
have significant U.K. and Swedish operations in electricity generation, distribution and supply, on both the
wholesale and retail levels. Increased competition from new market entrants and existing market participants
could adversely affect our U.K. or Swedish market share in both the retail and wholesale sectors. We cannot
guarantee we will be able to compete successfully in the United Kingdom, the Nordic countries, Eastern Europe,
Italy, Russia or other electricity markets where we are already present or in new electricity markets we may
enter. E.ON Ruhrgas also faces risks associated with increased competition in the gas sector.
Changes in applicable laws and regulations as well as the introduction of new laws and regulations could
materially and adversely affect our financial condition and results of operations.
In each of our operations, we must comply with a number of laws and government regulations. For more
information on laws and regulations affecting our core energy business, including additional details on each of
the regulatory regimes discussed below, see “Business — Regulatory Environment.” From time to time,
regulatory changes or new laws, including applicable tax laws, and regulations may be introduced, which may
negatively affect our businesses, financial condition and results of operations.
For example, the EU adopted new electricity and gas directives in 2003 which required changes to the
electricity and gas industries of some EU member states, including Germany. One of the requirements was that
an independent regulatory authority be established in each member state to oversee access to the electricity and
gas networks. According to the directives, this regulatory body should have the authority to set or approve
network charges or, alternatively, the methodologies used for calculating them, as well as the power to control
compliance with the charges or methodologies once they are set. In Germany, the relevant legislation came into
force in July 2005 and the German legislature authorized the Federal Network Agency (Bundesnetzagentur, or
the “BNetzA,” previously called the Regulatory Authority of Telecommunications and Post) to act as the
required independent regulatory body. The new German energy legislation and the appointment of the BNetzA to
oversee access to German electricity and gas networks has changed the previous system of negotiated third-party
22
network access in the electricity and gas industries in Germany. Although the new legislation has already come
into force, we cannot yet predict all of the consequences of the new system, as the exact interpretation of some of
the new regulatory rules is still pending. However, the BNetzA has interpreted some of the new regulatory rules
and ordinances to reach conclusions that are different than those reached by, and in some cases less favorable to,
us as well as other German utilities. For example, the new German energy law contains two phases of regulation,
and in the initial phase, the BNetzA and the state level regulators had to approve those network charges that were
calculated by the network operators using a cost-based rate-of-return model unless certain exemptions apply.
Thus the BNetzA and the state level regulators effectively set the network charges for network operators ex-ante.
In 2006, the BNetzA reduced the allowed network charges submitted for its approval by the E.ON Energie
electricity and gas distribution network operators, as described in “Regulatory Environment — Germany:
Electricity — Electricity Network Charges.” In doing so, the BNetzA used a different interpretation of the new
ordinance than that used by the E.ON Energie network operators (and the majority of German network operators)
to calculate their network charges. In 2006, the BNetzA also announced that the reduced charges would be
applicable from earlier dates than those which we believe should apply, so that German network operators
(including E.ON Energie’s) would need to reduce network charges in an amount equal to the difference between
the calculated network charges as submitted to the BNetzA and the allowed network charges approved by the
BNetzA for the time period in dispute. While some of the BNetzA’s interpretations have now been formalized
through a revision of the network charges ordinance, others, as well as the question of applicable dates, will have
to be decided by the German courts, and no assurance can be given as to the outcome of those proceedings.
By the end of June and September 2007, respectively, our electricity and gas network operators entered into
the second round of cost-based network tariff regulation by submitting applications to the regulatory authority.
Approval of these applications was expected by January 1, 2008 in respect of electricity and April 1, 2008 in
respect of gas, but approval has been delayed. For further information see “Regulatory Environment —
Germany: Electricity” and “— Germany: Gas.” No assurance can be given that new tariffs will not have a
negative effect on our results of operations or it may, in individual cases, be necessary to record impairment
charges on our network operators.
The current cost-based rate-of-return model for network tariffs in Germany will be replaced by an incentive
regulation system, which was established by a new ordinance that came into force on November 6, 2007. The
approved revenues for network operators set under the incentive regulation system will initially be based upon
the costs recognized by the regulatory authority in the second round of cost-based network tariff regulation and
will start on January 1, 2009. It is expected that approved revenues will be reset at the beginning of 2014 in
respect of electricity and at the beginning of 2013 in respect of gas. By January 1, 2019, network operators will
be expected to reduce their costs to the level of the most efficient operator along individual cost reduction paths,
reflected by reduced approved revenues. Efficiency will be measured by means of a complicated benchmarking
system. Moreover, a general efficiency factor of 1.25 percent per year in the first five-year period (a four-year
period for gas) and 1.5 percent in the second five-year-period, will be added. As an incentive to achieve
improved efficiency under the incentive regulation system, it is expected that if operators reduce their costs at a
rate greater than the required rate, operators will be able to retain the additional amounts saved by such cost
reductions. We plan to compensate for the negative impact of revenue caps by further reducing operating costs
through various efficiency-raising programs.
In the gas market, the gas industry developed an industry-wide gas network access model in order to comply
with the new legislation, and the agreed model, with two variants for gas transportation, was finalized in
mid-2006. Shortly thereafter, one of the variants for gas transportation was challenged in legal proceedings and
in November 2006 the BNetzA issued an industry-wide decision requiring a so-called two-contract-model for all
gas transportation and distribution companies, forcing them to offer customers only two contracts, one for the
entry and one for the exit-point in their market area, thus requiring related changes in all transportation and sales
contracts and in the gas network operators’ cooperation agreement, which have since come into effect.
In addition, in November 2006 a new network connection ordinance came into force in Germany which
increases potential liability for network operators for damages caused by energy supply disturbances.
23
Sweden has enacted new legislation concerning electricity distribution which requires customer
compensation for power blackouts lasting more than 12 hours. As discussed below, in early 2007 a severe storm
resulted in a power outage in Sweden that affected approximately 170,000 E.ON Sverige customers, and many of
these customers are entitled to compensation under the new law.
In 2005, the EU adopted a directive requiring member states to establish a greenhouse gas emissions
allowance trading scheme, under which emissions are capped and permits to emit a specified amount of carbon
dioxide (“CO2 emission certificates”) are allocated to affected power stations and other industrial installations.
All EU member states have already passed the required legislation and allocated the necessary CO2 emission
certificates for the first phase of the scheme, mostly free of charge. The trial phase (2005-2007) of the trading
scheme has ended and market has moved into the Kyoto phase which will run from 2008-2012. In this current
phase, the European Commission has reduced the total amount of emissions certificates given compared to
2005-07. By using the actual emissions from 2005 as a reference point, the European Commission has decided to
allocate 2,080 million CO2 emission certificates annually, which is more than 200 million certificates/year fewer
than in the initial phase of the trading scheme. Member states have developed national allocation plans for the
Kyoto phase that will result in a reduced number of CO2 emission certificates being issued, which could further
impact our operations. The German national allocation plan has now been accepted by the EC (after rejection in
November 2006) and passed as the Allocation Act 2008-20012 (Zuteilungsgesetz 2008-2012, or “ZUG 2012”) by
both houses of the German Parliament in the summer of 2007. The total allocation amount in Germany has been
reduced by 50 million CO2 emission certificates/year to 453 million CO2 emission certificates/year, which means
a significant shortage, especially for the energy sector, as the reduction is taken almost completely from the
budget for the energy sector. Out of the total allocation amount of 453 million CO2 emission certificates/year,
40 million CO2 emission certificates/year will be released by a government agency according to market prices
from 2008 on; from 2010 on it will be auctioned. These 40 million CO2 emissions certificates/year are taken from
the budget of the energy sector as well. This reduction in the volume of authorized emissions available to the
energy sector has meant that E.ON’s free allocation of certificates has been reduced, and E.ON has therefore to
purchase a potion of its required certificates in Germany on the market.
The European Commission published as part of a package of measures on climate and energy policy the
proposal of a new directive for the EU Emissions Trading Scheme for the period after 2012 on January 23, 2008.
For more information, see “Business — Environmental Matters — Europe” and “Business — Regulatory
Environment — EU/Germany: General Aspects (Electricity and Gas) — New European Energy Policy.”
In the United States, possible federal or state energy legislation or industry initiatives could include
mandatory or voluntary targets for the production and use of renewable energy and limits or charges on the
emission of greenhouse gases, though we are unable to predict if any such legislation or initiatives will be
established. If established, such legislation and/or initiatives could have a material negative effect on our
financial condition and results of operations including increased capital expenditures or operating costs, reduced
customer demand or changed prices and availabilities of key input or output goods, services or commodities.
In addition, in the summer of 2005 the Competition Directorate-General of the European Commission
launched a sector inquiry concerning the electricity and gas markets in the EU. This investigation is based on
Article 17 of Regulation 1/2003 and assesses the competition conditions in European gas and electricity markets.
It cannot be excluded that this inquiry could result in individual antitrust proceedings against us and/or legislative
initiatives (at the EU or national level) in the electricity sector that would seek to increase the current level of
competition in the EU energy market. In its final report issued on January 10, 2007, the European Commission
has identified the following barriers to a fully functioning internal energy market: market concentration, vertical
foreclosure, lack of market integration and transparency and price formation.
The findings in the final report of the sector inquiry in January 2007 led the European Commission to focus
its activities on the concerns identified in the report, such as: achieving adequate unbundling of network and
supply activities, removing the regulatory gaps, in particular for cross-border issues, addressing market
24
concentration and barriers to entry, as well as increasing transparency in market operations. For more
information on legal proposals of the European Commission (including ownership unbundling) see also
“Business — Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas) — New European
Energy Policy.”
In July 2007, the European Commission decided to open formal antitrust proceedings against us, E.ON
Ruhrgas, E.ON Gastransport, MEGAL and Gaz de France for an alleged infringement of Article 81 of the EC
Treaty involving alleged anti-competitive behavior in connection with the MEGAL pipeline operated jointly by
E.ON Ruhrgas with Gaz de France. No assurance can be given as to the outcome of these proceedings.
The European Commission also carried out investigations at the premises of several energy companies in
Europe, including E.ON AG and some of its affiliates, in May and December 2006, followed by requests for
information regarding different regulatory and energy market-related issues relating to E.ON Energie and E.ON
Ruhrgas. The European Commission is currently analyzing the respective data and has recently issued additional
requests for information. The European Commission investigated the circumstances under which a seal installed
by investigators at one of the E.ON Energie’s facilities failed and, in January 2008, fined E.ON Energie
€38 million for allegedly breaching the seal. E.ON Energie is of the opinion that the allegations are unjustified,
and therefore intends to challenge the fine in court. However, no assurance can be given that such challenge will
be successful. To settle pending investigations in the electricity sector, E.ON is prepared to divest its 380 kilovolt
and 220 kilovolt extra-high-voltage transmission system and 4,800 MW of generating capacity in Germany.
After conducting a market test, the European Commission will make a legally binding decision and not continue
any antitrust proceedings against E.ON’s electricity operations in this respect.
Regulatory and legal actions can also affect the prices we may charge customers. For example:
•
In March 2008, the BNetzA launched an investigative procedure against the German power transmission
system operators, including E.ON subsidiary E.ON Netz GmbH, Bayreuth (“E.ON Netz”). E.ON Netz is
charged by market participants (Lichtblick/bne) to have purchased excessive amounts of balancing
power over the past two years and to have overcharged grid customers accordingly.
•
In December 2007, an amendment of the German law against restraints on competition (Gesetz gegen
Wettbewerbsbeschränkungen, or “GWB”) entered into force.
•
As noted above, in Germany the BNetzA has reduced the allowed network charges which were
submitted for approval by our electricity and gas distribution network operators in 2006. The approved
network charges were based on a different interpretation of Germany’s new energy law by the BNetzA
than that used by our network operators (and the majority of German network operators) to calculate
their network charges.
•
In Germany, the state antitrust authorities as well as the German Federal Cartel Office
(Bundeskartellamt, or “FCO”) regularly examine gas tariffs of utilities for household customers to
determine whether these prices constitute market abuse. Our companies have always delivered any
information requested in connection with such inquiries, and no formal proceedings are currently
pending.
•
The FCO has opened proceedings against E.ON Energie and RWE with respect to an alleged abuse of a
dominant position in the energy market by including the costs for CO2 emission certificates obtained at
no charge in the calculation of their energy prices for industrial customers. In December 2006, RWE
received a statement of objections but has since settled the proceedings with the FCO by entering into
binding agreements to auction generation capacity to industrial customers in the years 2008 to 2011 for
delivery in the years 2009 to 2012. E.ON Energie has also conducted negotiations with the FCO and is
finalizing a settlement with the FCO on the basis of the auction of generation capacity, combined with
the option to sell off an interest in a generation plant. At present, the parties involved have been given
the opportunity by the FCO to comment on the settlement findings in the first quarter of 2008. We
cannot provide any assurance that the result of these negotiations will not harm our business or results of
operations.
25
•
Electricity and gas prices and sales practices throughout the German energy sector have also been
subject to certain legal proceedings. Currently, fifty-four customers of E.ON Hanse AG (“E.ON Hanse”)
have brought a claim asserting that recent price increases violate certain provisions of the German Civil
Code (Bürgerliches Gesetzbuch). In order to support its case that the price increases were reasonable
within the meaning of applicable law, E.ON Hanse has disclosed the basis on which it calculates prices
for household customers to the District Court (Landgericht) in Hamburg. The court is currently
examining E.ON Hanse’s submissions in this respect. In an unrelated proceeding, E.ON Westfalen
Weser AG (“E.ON Westfalen Weser”) has brought suit against a group of customers that have refused
to pay the increased prices. No assurances can be given as to the outcome of either of these proceedings.
In November 2007, the Superior Court of Schleswig Holstein ruled against E.ON Hanse, resulting in a
decision for 30,000 customers with respect to price increases of electricity used for residential heating.
The Court found that terms and conditions for the price increases were not sufficiently transparent and
were too vague, but has not yet issued a ruling with any binding effect on our business practices.
However, no assurance can be given as to the outcome of these or similar proceedings.
•
With effect from April 2005, regulators in the United Kingdom renewed a price control framework for
electricity distribution customers that is in effect through the five-year period ending March 2010.
•
In the United States, the rates for E.ON U.S.’s retail electric and gas customers in Kentucky, its
principal area of operations, are set by state regulators and remain in effect until such time as an
adjustment is sought and approved. E.ON U.S.’s affected utilities applied for and received increases in
regulated tariffs effective as of July 1, 2004.
For additional information on these developments, see “Business — Regulatory Environment.” For all of
our operations, adverse changes in price controls, rate structures or the level of competition could have an
adverse effect on our financial condition and results of operations.
Rising fuel prices could materially and adversely affect our results of operations and financial condition.
A significant portion of the expenses of our regional market units are made up of fuel costs, which are
heavily influenced by prices in the world market for oil, natural gas, fuel oil and coal. Similarly, the majority of
E.ON Ruhrgas’ expenses are for purchases of natural gas under long-term take-or-pay contracts that link the gas
prices to that of fuel oil and other competing fuels. The prices for such commodities have historically been
volatile and there is no guarantee that prices will remain within projected levels. The price of oil in particular
rose in 2006 and reached a new all-time high of over 110 U.S. dollars per barrel in early 2008. Our electricity
operations do maintain some flexibility to shift power production among different types of fuel, and we are also
partially hedged against rising fuel prices. However, increases in fuel costs could have an adverse effect on our
operating results or financial condition if we are not able (or not permitted by regulatory authorities) to shift
production to lower-cost fuel or to adjust our rates to offset such increases in fuel prices on a timely or complete
basis.
For more information about E.ON Ruhrgas’ take-or-pay contracts, see “— Operational Risks — E.ON
Ruhrgas’ long-term gas supply contracts expose it to volume and price risks, and it has had to terminate certain
of its long-term sales contracts due to a negative decision by the FCO” below. We could also incur losses if our
hedging strategies are not effective. For more information about our hedging policies and the instruments used,
see “— Financial Risks” below; also see “Operating and Financial Review and Prospects — Quantitative and
Qualitative Disclosures about Market Risk.” E.ON Ruhrgas is also currently involved in two international
arbitration proceedings against producers with respect to price adjustments in the period between 1998 and 2005.
In addition, as our fuel costs increase, we seek, to the extent possible, to pass along such increased costs to
our customers. Such increased costs alone or together with a worsening of the overall economic situation,
including the retail credit environment, in any of our markets, may make it more difficult for our customers to
make required payments to us, which typically increases our bad debt expense and damages our financial
condition and results of operations.
26
Recent events have heightened concerns about the reliability of Russian gas supplies, on which E.ON Ruhrgas
depends.
E.ON Ruhrgas currently obtains nearly thirty percent of its total gas supply from Russia pursuant to longterm supply contracts it has entered into with OOO Gazexport (now Gazprom export), a subsidiary of OAO
Gazprom (“Gazprom”) (in which E.ON Ruhrgas holds a 3.5 percent direct interest and an additional stake of
2.9 percent). Recent events in some countries of the former Soviet Union have heightened concerns in parts of
Western Europe about the reliability of Russian gas supplies. Historically cold temperatures in Russia in the
winter of 2005-2006 increased gas consumption, leading some Western European countries to report declines in
pressure in gas pipelines and shortfalls in the volume of gas they received from Russia. In addition, a dispute
between Russia and Ukraine over the imposition of significant price increases on Russian gas delivered to
Ukraine at the beginning of 2006 led to interruptions in the supply of Russian gas to Ukraine (and through
Ukraine to other countries) in the early days of January 2006. In late 2006, a similar price dispute between Russia
and Belarus led to Belarus blocking the transit of gas and oil through that country, while in early 2007 Poland
attempted to raise transit fees charged to Gazprom for Russian gas and oil being shipped to Western Europe
through Poland, leading to speculation that Gazprom might retaliate by halting gas and oil shipments. Economic
or political instability or other disruptive events in any “transit country” through which Russian gas must pass
before it reaches its final destination in Western Europe can have a material adverse effect on the supply of such
gas, and all such events are completely outside the control of E.ON Ruhrgas. Although E.ON Ruhrgas has to date
not experienced any interruptions in supply or declines in delivered gas volumes below those which are
guaranteed to it under its long-term contracts, no assurance can be given that such interruptions or declines will
not occur. The terms of E.ON Ruhrgas’ long-term supply contracts for Russian gas require that the contracted
volumes of gas be delivered to E.ON Ruhrgas at the German border, with the risk of ownership only passing to
E.ON Ruhrgas at that point, but provide that such obligations can be suspended due to events of force majeure.
Any prolonged interruption or decline in the amount of gas delivered to E.ON Ruhrgas under its contracts with
Gazprom, its subsidiaries or any other party would result in E.ON Ruhrgas having to use its storage reserves to
make up the shortfall with respect to amounts it is contracted to deliver to customers, and could have a material
adverse effect on E.ON’s results of operations and financial condition.
Our revenues and results of operations fluctuate by season and according to the weather, and we expect these
fluctuations to continue.
The demand for electric power and natural gas is seasonal, with our operations generally experiencing
higher demand during the cold weather months of October through March and lower demand during the warm
weather months of April through September. The exception to this is our U.S. power business, where hot weather
results in an increased demand for electricity to run air conditioning units. As a result of these seasonal patterns,
our revenues and results of operations are higher in the first and fourth quarters and lower in the second and third
quarters, with the U.S. power business having its highest revenues in the third quarter and secondary peaks in the
first and fourth quarters. Revenues and results of operations for all of our energy operations can be negatively
affected by periods of unseasonably warm weather during the autumn and winter months, as occurred at certain
of our market units in both 2006 and 2007. Our Nordic operations could be negatively affected by a lack of
precipitation (which would lead to a decline in hydroelectric generation, as occurred in 2006) and our European
energy operations could also be negatively affected by a summer with higher than average temperatures to the
extent our plants were required to reduce or shut down operations due to a lack of water needed for cooling the
plants. We expect seasonal and weather-related fluctuations in revenues and results of operations to continue.
Particularly severe weather can also lead to power outages, as discussed in more detail below.
Operational Risks
Our core energy businesses operate technologically complex production facilities and transmission systems.
Operational failures or extended production downtimes could negatively impact our financial condition and
results of operations. Our businesses are also subject to risks in the ordinary course of business such as the loss of
27
personnel or customers, and losses due to bad debts. We believe we have appropriate risk control measures in
effect to counteract and address these types of risks. The following are additional operational risks we face:
E.ON Ruhrgas’ long-term gas supply contracts expose it to volume and price risks, and it has had to terminate
certain of its long-term sales contracts due to a negative decision by the FCO.
As is typical in the gas industry, E.ON Ruhrgas enters into long-term gas supply contracts with natural gas
producers to secure the supply of almost all the gas E.ON Ruhrgas purchases for resale. These contracts, which
generally have terms of around 20 to 25 years, require E.ON Ruhrgas to purchase minimum amounts of natural
gas over the period of the contract or to pay for such amounts even if E.ON Ruhrgas does not take the gas, a
standard industry practice known as “take or pay.” The minimum amounts are generally about 80 percent of the
firmly contracted quantities. Historically, E.ON Ruhrgas has also entered into long-term gas sales contracts with
its customers, although these contracts are shorter than gas supply contracts with natural gas producers. Aspects
of E.ON Ruhrgas’ long-term gas sales contracts have been challenged by the FCO, as described in more detail
below. In addition, the majority of these gas sales contracts do not include fixed take-or-pay provisions. Since
E.ON Ruhrgas’ gas supply contracts have significantly longer terms than its gas sales contracts, and commit
E.ON Ruhrgas to paying for a minimum amount of gas over a long period, E.ON Ruhrgas is exposed to the risk
that it will have an excess supply of natural gas in the long term should it have fewer committed purchasers for
its gas in the future and be unable to otherwise sell its gas on favorable terms. Such a shortfall could result if a
significant number of E.ON Ruhrgas’ customers (or their end customers) shifted from natural gas to other forms
of energy or if E.ON Ruhrgas’ customers began to acquire increased volumes of gas from other sources. The
ministerial approval we obtained for the acquisition of Ruhrgas required E.ON Ruhrgas to divest its stakes in two
gas distributors, as well as granting these distributors the right to terminate their gas sales contracts with E.ON
Ruhrgas. The ministerial approval also gave most of E.ON Ruhrgas’ distribution customers the right to reduce
the amounts of natural gas purchased from E.ON Ruhrgas. However, the majority of E.ON Ruhrgas’ customers
have decided not to exercise these options.
In January 2006, the FCO issued a decision prohibiting E.ON Ruhrgas from enforcing its existing long-term
gas sales contracts with regional and local distribution companies after October 1, 2006 and from entering into
new sales contracts with those customers that are identical or similar in nature. For details on this decision and
the effect on E.ON Ruhrgas, see “Operating and Financial Review and Prospects — Acquisitions and
Dispositions — Pan-European Gas.” E.ON Ruhrgas believes that the FCO is overlooking the negative impact its
decision would have on security of supply and that by excluding suppliers from competing to supply additional
volume, the FCO has inadmissibly interfered with freedom of contract. Therefore, E.ON Ruhrgas has appealed
against the decision issued by the FCO. In June 2006, the State Superior Court (Oberlandesgericht) in Düsseldorf
decided in summary proceedings that E.ON Ruhrgas would not be granted temporary relief. Consequently, E.ON
Ruhrgas had to terminate the supply contracts with regional and local distribution companies that were covered
by the FCO decision as of October 2006. In the summer of 2007, E.ON Ruhrgas concluded new contracts having
a duration of only one or two years with virtually all of the regional and local distribution companies whose prior
contracts it had been required to cancel. In October 2007, the State Superior Court of Düsseldorf decided in a full
proceeding that the FCO decision was lawful. E.ON Ruhrgas is currently challenging the State Superior Court’s
decision before the Federal Supreme Court of Justice (Bundesgerichtshof). This appeal proceeding is expected to
last through 2009. No assurance can be given that E.ON Ruhrgas will be successful in the appeal proceeding, or
otherwise be allowed to conclude contracts that exceed the combination of supply share and duration set by the
decision of the FCO and/or bid for the remaining volumes.
If these or other developments were to cause the volume of gas E.ON Ruhrgas is able to sell to fall below
the volume it is required to purchase, the take-or-pay provisions of some of E.ON Ruhrgas’ gas supply contracts
may become applicable, which would negatively affect its results of operations. In addition, due to increasing
competition linked to the liberalization of the gas market and the entry of new competitors, E.ON Ruhrgas may
not be able to renew some of its existing gas sales contracts as they expire, or to gain new contracts. This may
also have the effect of leaving E.ON Ruhrgas with an excess supply of natural gas and/or decrease margins.
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As is standard in the gas industry, the price E.ON Ruhrgas pays for gas under its long-term gas supply
contracts is calculated on the basis of complex formulas incorporating variables based on current market prices
for fuel oil, gas oil, coal and/or other competing fuels, with prices being automatically re-calculated periodically,
usually quarterly, by reference to market prices of the relevant fuels during a prior period. Price terms in E.ON
Ruhrgas’ gas sales contracts are generally pegged to the price of competing fuels and provide for automatic
quarterly price adjustments based on fluctuations in underlying fuel prices, again by reference to market prices
during a prior period. Since E.ON Ruhrgas’ supply and sales contracts are generally indexed to different types of
oil and related fuels, in different proportions and are adjusted according to different formulas, E.ON Ruhrgas’
margins for natural gas may be significantly affected in the short term by variations in the price of oil or other
fuels, which are generally reflected in prices payable under its supply contracts before they are reflected in prices
paid under sales contracts, the so-called “time lag” effect. Although E.ON Ruhrgas seeks to manage this risk by
matching the general terms of its portfolio of sales contracts with those of its supply contracts, there can be no
assurance that it will always be successful in doing so, particularly in the short term. For more information on
E.ON Ruhrgas’ gas supply and sales contracts, see “Operating and Financial Review and Prospects —
Acquisitions and Dispositions — Pan-European Gas.”
If our plans to make selective acquisitions and investments to enhance our core energy business are
unsuccessful, our future earnings and share price could be materially and adversely affected.
Our business strategy involves selective acquisitions and investments in our core business area of energy.
This strategy depends in part on our ability to successfully identify and acquire companies that enhance our
business on acceptable terms. In order to obtain the necessary approvals for acquisitions, we may be required to
divest other parts of our business, or to make concessions or undertakings which materially affect our operations.
We may not be able to make required divestments on acceptable terms, which could interfere with our declared
business strategy and/or adversely affect our business. For example, our efforts to obtain control of Ruhrgas
through a series of purchases from the holders of Ruhrgas interests were initially blocked by the FCO and then by
a series of plaintiffs who succeeded in convincing the State Superior Court in Düsseldorf to issue a temporary
injunction preventing us from completing the transaction. In order to receive the ministerial approval of the
German Economics Ministry that overruled the initial decision of the FCO, we were required to make significant
concessions, including committing to divest certain operations, to have E.ON Ruhrgas sell a significant quantity
of natural gas at auction (with opening bids set at below-market prices) and to offer certain customers the option
of reducing the volume of gas they had contracted for. In addition, in settling the claims of the plaintiffs who had
received the temporary injunction, we agreed to divest certain of our operations, to provide certain of the
plaintiffs with energy supply contracts and network access, and to make certain infrastructure improvements, as
well as making financial payments. Each of these matters delayed completion of the Ruhrgas acquisition and had
the effect of increasing the cost of the transaction to us. Legal challenges and competing bids also had a
significant effect on our proposed acquisition of Endesa, S.A. (“Endesa”), which we were unable to complete on
the terms we originally contemplated.
In addition, there can be no assurances that we will be able to achieve the benefits we expect from any
acquisition or investment. For example, we may fail to retain key employees, may be unable to successfully
integrate new businesses with our existing businesses, may incorrectly judge expected cost savings, operating
profits or future market trends and regulatory changes, or may spend more on the acquisition, integration and
operations of new businesses than anticipated. Legal challenges may also have an impact. Especially large
acquisitions present particularly difficult challenges. Investments and acquisitions in new geographic areas or
lines of business require us to become familiar with new markets and competitors and expose us to commercial
and other risks, as well as additional regulatory regimes relating to the acquired businesses that may be stricter
than the ones we are currently subject to. Because of the risks and uncertainty associated with acquisitions and
investments, any acquired businesses or investments may not achieve the profitability we expect.
29
We could be subject to environmental liability associated with our nuclear and conventional power operations
that could materially and adversely affect our business. In addition, new or amended environmental laws and
regulations may result in significant increases in costs for us.
Under German law, the owner of an electric power generation facility is subject to liability provisions that
guarantee comprehensive compensation to all injured parties in the event of environmental damages caused by
the facility. In addition, there has been some relaxation in the evidence required under the German
Environmental Liability Law (Umwelthaftungsgesetz) to establish, prove and quantify environmental claims.
Under German law and in accordance with contractual indemnities, we may still be subject to future
environmental claims with respect to alleged historical environmental damage arising from certain of our
discontinued and disposed of operations, including, but not limited to, the VEBA Oel oil business, the VAW
aluminum operations and the Klöckner & Co AG distribution and logistics businesses, as well as Degussa’s
chemicals operations. If claims were to be asserted against us in relation to environmental damages and plaintiffs
were successful in proving their claims, such claims could result in material losses to us.
German law also provides that in the case of a nuclear accident in Germany, the owner of the reactor, the
factory or the nuclear material storage facility is subject to liability provisions that guarantee comprehensive
compensation to all injured parties. Under German nuclear power regulations, the owner is strictly liable, and the
geographical scope of its liability is not limited to Germany. E.ON’s Swedish nuclear power stations also expose
us to liability under applicable Swedish law. In 2006, an inquiry opened by the Swedish government proposed
both unlimited liability for nuclear plant operators and that such operators be obligated to purchase additional
insurance coverage, although it is unclear what effect the inquiry’s proposals of new legislation will have. We do
not operate or have interests in nuclear power plants outside of Germany, Sweden and Switzerland, including in
the United Kingdom, the United States, Russia or the countries in Eastern Europe in which we operate. We take
extensive safety and risk management measures in the operation of our nuclear power operations, and have
mandatory insurance with respect to our nuclear operations. However, any claims against us arising in the case of
a nuclear power accident could exceed the coverage of such insurance, and cause material losses to us.
We expect that we will incur costs associated with future environmental compliance, especially compliance
with clean air laws. For example, the U.S. Environmental Protection Agency (“EPA”) has introduced regulations
regarding the reduction of nitrogen oxide (“NOx”) and sulphur dioxide (“SO2”) emissions from electricity
generating units. These regulations require E.ON U.S. to make significant additional capital expenditures in
pollution control equipment. E.ON U.S. expects to incur total costs of $0.8 billion in installing these pollution
controls during the 2008 through 2010 time period, and expects to recover a significant portion of these costs
over time from customers of its regulated utility businesses. In the United Kingdom, legislation to implement the
EU Large Combustion Plants Directive has been adopted, which requires E.ON UK to make decisions as to
whether it will invest in enhanced pollution control devices, reduce operating time at certain of its plants or
consider closing certain plants in the future.
Similarly, the German government has amended an ordinance of the German Federal Pollution Control Act
(Bundesimmissionsschutzgesetz, or “BImSchG”) to introduce lower emission limits for air pollutants such as
carbon monoxide and NOx. This amendment requires both E.ON Energie and E.ON Ruhrgas to make
investments in pollution control devices. In addition, a draft for the 37th BImSchV has been published that
foresees a further tightening of NOX-emissions limit values. The new emission limits could come into force in
2013 and could have an impact on the design of new power plants and the maintenance of our existing ones.
Currently, none of our market units can predict the extent to which their respective operations will be
affected by the new legislation and/or regulations. Revisions to existing environmental laws and regulations and
the adoption of new environmental laws and regulations may result in significant increases in our costs. Any such
increase in costs that cannot be fully recovered from customers may adversely affect our operating results or
financial condition.
The German government has decided on an extensive national package to reduce greenhouse gas emissions
by increasing the share of renewable resources in power and heat generation and promoting energy savings. The
30
package contemplates the amendment of existing laws and/or the creation of new laws. We cannot predict the
effects of any such amendments or new laws, which will depend in large measure on the behavior of consumers.
The national package is designed to incentivize consumers to act with more awareness of environmental issues
and to invest more into environmental-friendly, but more expensive, technology to cover their final energy needs.
Our current expectation is that such national package will not come into force before early 2009. We can give no
assurances that consumers will act in the manner contemplated by such national package and that such national
package, if implemented, will not harm our business and results of operations through a reduction in sales
volumes or otherwise.
Although environmental laws and regulations have an increasing impact on our activities in almost all the
countries in which we operate, it is impossible to predict accurately the effect of future developments in such
laws and regulations on our future earnings and operations. For example, the EU has published a package of
measures for a new energy policy which includes ambitious targets for cutting greenhouse gas emissions, but we
cannot predict when or in what form these measures might be passed into law, or how we might be impacted. For
additional detail, see the discussion on changes in laws and regulations above. Some risk of environmental costs
and liabilities is inherent in our particular operations and products, as it is with other companies engaged in
similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. For more
information on environmental matters, see “Business — Environmental Matters.”
If power outages or shutdowns involving our electricity operations occur, our business and results of
operations could be negatively affected.
Significant parts of Europe and North America have experienced major power outages in recent years. The
reasons for these blackouts vary, although generally they involved a locally or regionally inadequate balance
between power production and consumption, with single failures triggering a cascade-like shutdown of lines and
power plants following overload or voltage problems. The likelihood of this type of problem has increased in
recent years following the liberalization of EU electricity markets, partly due to an emphasis on unrestricted
cross-border physically-settled electricity trading that has resulted in a substantially higher load on the
international network, which was originally designed mainly for purposes of mutual assistance and operations
optimization. As a result, there are transmission bottlenecks at many locations in Europe, and the high load has
resulted in lower levels of safety reserves in the network. In Germany, where power plants are located in closer
proximity to population centers than in many other countries, the risk of blackouts is lower due to shorter
transmission paths and a strongly meshed network. In addition, the spread of a power failure is less likely in
Germany due to the organization of the German power grid into four balancing zones. Nevertheless, our German
or international electricity operations could experience unanticipated operating or other problems leading to a
power failure or shutdown. For example:
•
On January 8-9, 2005, a severe storm hit Sweden, destroying the electricity distribution grid in some
areas in the south of the country. Approximately 250,000 E.ON Sverige customers were affected by the
resulting power outage, and some customers were left without electricity for several weeks. In 2005,
E.ON Sverige recorded related costs for rebuilding its distribution grid and compensating customers of
€142 million.
•
In July 2006, a transmission-related incident at the Forsmark nuclear power plant in Sweden (in which
E.ON Sverige owns a minority interest) resulted in an emergency shutdown of the plant and subsequent
modifications to the plant’s transmission infrastructure. Reviews of similar infrastructure at other
reactors following the Forsmark incident took a number of Swedish reactors out of service for a period
of several weeks and revealed the need for a significant overhaul at the Oskarshamn I reactor operated
by E.ON Sverige, which was only restarted in January 2007.
•
On November 4, 2006, an overload in the northwestern German power transmission grid occurred,
leading to disturbances in other parts of the continental European power grid and an interruption of the
power supply for more than 15 million European households located in parts of Germany, France,
31
Belgium, the Netherlands, Italy and Spain. According to initial findings, the overload occurred after the
E.ON Netz GmbH (“E.ON Netz”, a subsidiary of E.ON Energie) control center made an erroneous
estimation in its planned interruption of a high voltage power line across the Ems river in Germany to
allow the passage of a Norwegian cruise liner. Functioning safety mechanisms and close cooperation
among European transmission system operators ensured that a full reconnection of the power grids and
stabilization of the system occurred within 38 minutes after the grid separated into three “islands”, thus
avoiding an uncontrolled blackout. E.ON Netz does not expect claims related to this incident to have
any material impact on its financial results or operations.
•
On January 14, 2007, another severe storm hit southern Sweden. Approximately 170,000 E.ON Sverige
customers were affected by the resulting power outage, and some customers were left without electricity
for up to ten days. The costs to E.ON Sverige for rebuilding its distribution grid and compensating
affected customers amounted to €95 million.
•
On January 18 and 19, 2007, a severe storm hit several European countries, damaging the electricity
distribution grid of E.ON Energie in some areas of Germany, the Czech Republic, Hungary and
Romania. In Germany, approximately 750,000 customers were disconnected from the grid (in the Czech
Republic: approximately 500,000 customers; in Hungary: approximately 90,000 customers; in Romania:
approximately 5,000 customers). Approximately 80 percent of the affected customers were reconnected
within one day, and nearly all customers were reconnected within three days. The costs of repairing the
damages were not significant.
•
On June 28, 2007, the German nuclear power plant Krümmel was shut-down because a transformer
caught fire. Since then, the renovations at the transformer building have been completed. In addition to
this, in agreement with the authorities and independent experts, wall anchors and valves are also being
examined. E.ON Kernkraft GmbH (“E.ON Kernkraft”) holds a 50 percent stake in the power plant
which is operated by Vattenfall Europe.
•
On July 18, 2007, the German nuclear power plant Brunsbüttel was shut-down due to an oil change at
the house load transformer. Further, discrepancies were noticed in connection with the mounting plates.
In agreement with the authorities and independent experts, an extensive renovation plan is being
compiled regarding wall anchors and valves. E.ON Kernkraft only holds a minority stake in the power
plant which is operated by Vattenfall Europe. Both Krümmel and Brunsbüttel are expected remain out
of service for the next several months.
The areas of the United States in which E.ON U.S. operates are also from time to time subject to severe
weather, such as ice storms, which could cause power outages. In Germany, about 40 percent of the country’s
wind turbines are connected to the power grid of E.ON Energie, mostly in the north of Germany. In the case of a
power grid failure, older wind power plants may switch off automatically, possibly causing a chain reaction and
thus increasing the impact of the original power failure in the grid. We can give no assurances that power failures
or shutdowns involving our operations will not occur in the future, or that any such power failure or shutdown
would not have a negative effect on our business and results of operations.
Financial Risks
We are exposed to financial risks that could have a material effect on our financial condition.
During the normal course of our business, we are exposed to the risk of energy price volatility, as well as
interest rate, commodity price, currency and counterparty risks. These risks are partially hedged on a Group-wide
(or market unit-wide) basis, but we may incur losses if any of the variety of instruments and strategies we use to
hedge exposures are not effective. For more information about these risks and our hedging policies and
instruments, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures
about Market Risk.” For more information about E.ON Ruhrgas’ take-or-pay contracts, see the discussion on
E.ON Ruhrgas’ long-term gas contracts above.
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We are also exposed to other financial risks. For example, we hold certain stock investments which may
expose us to the risk of stock market declines. Financial markets have experienced volatility in recent years, and
markets may decline again or become even more volatile. In addition, a significant portion of our outstanding
debt bears interest at floating rates; our interest expense will therefore increase if the relevant base rates rise. The
value of our investments in fixed rate bonds will be adversely affected by a rise in market interest rates. We also
expect the overall level of our debt to increase as we implement our new financial strategy and seek to fund our
investment plan. See “Summary — Our Business — Strategy.”
Future adverse changes in a reporting unit’s economic and regulatory environment could adversely affect
both estimated future cash flows and discount rates and could result in impairment charges to goodwill which
could materially and adversely affect E.ON’s future financial position and net income.
We also face risks arising from our energy trading operations. In general, we seek to hedge risks associated
with volatile energy-related prices (including the prices of CO2 emission certificates) by entering into fixed-price
bilateral contracts, fuel-price indexed bilateral contracts, futures and options contracts traded on commodities
exchanges, and swaps and options traded in over-the-counter financial markets. To the extent we are unable to
hedge these risks, or enter into hedging contracts that fail to address our exposure or incorrectly anticipate market
movements, we may suffer losses, some of which could be material. In addition to the risks associated with
adverse price movements, credit risk is also a factor in our energy marketing, trading and treasury activities,
where loss may result from the non-performance of contractual obligations by a counterparty. We maintain credit
policies and control procedures with respect to counterparties to protect us against losses associated with such
types of credit risk, although there can be no assurance that these policies and procedures will fully protect us.
The marking to market of many of our hedging instruments required by Financial Instruments: “Recognition and
Measurement” (“IAS 39”), has also increased the volatility of our results of operations, though it has not had a
material effect on our overall risk exposure. For example, in 2007, unrealized gains from the marking to market
of derivatives, primarily at the U.K. market unit, increased other non-operating income by €564 million. For
more information about our energy trading operations, our hedging policies and the instruments used, see
“Business — Central Europe — Trading,” “— Pan-European Gas — Trading,” “— U.K. — Energy Wholesale
— Energy Trading,” “— Nordic — Trading,” “— U.S. Midwest — Power Generation — Asset-Based Energy
Marketing” and “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures
about Market Risk.”
Risks Related to the Notes
There is no public market for the Notes.
The Notes comprise a new issue of securities for which there is currently no public market. There is no
established trading market for the Notes. The Notes are not listed or admitted for trading on any securities
exchange and we have no plans to effect such listing or admission. There can be no assurance as to the liquidity
of any market that may develop for the Notes, the ability of holders to sell their Notes, or the prices at which
holders might be able to sell their Notes.
The Notes have not been registered under the securities laws of any jurisdiction and the Notes may not be
publicly offered, sold, pledged or otherwise transferred in any jurisdiction where such registration may be
required.
Any substitution of the Issuer (as defined under “Description of the Notes”) may trigger adverse tax
consequences for the Holders of the Notes.
The Issuer will be entitled, without the consent of the Holders, at any time to substitute the Guarantor or any
Affiliate for the Issuer in accordance with the provisions, and subject to the conditions, set forth under
“Description of the Notes-Substitution of Issuer: Consolidation, Merger and Sale of Assets”. Such a substitution
may in certain circumstances be treated as a taxable exchange for U.S. federal income tax purposes. Such an
33
exchange would require Holders to recognize taxable gain or loss for U.S. federal income tax purposes. Neither
the Issuer nor the Guarantor will be liable to indemnify the Holders for any taxes payable in connection with such
substitution. Holders should consult their own tax advisers regarding the possible tax consequences of a
substitution of the Issuer.
The Notes are subject to restrictions on transfer.
The Notes are being offered in reliance upon an exemption from registration under the Securities Act and
applicable state securities laws of the United States. As such, the Notes may be transferred or resold only in a
transaction registered under or exempt from the Securities Act and applicable U.S. state securities laws. These
restrictions on transfer may have a material adverse effect on the ability of any holder of the Notes to transfer
such Notes.
Investors may experience difficulties in enforcing civil liabilities.
E.ON AG is incorporated in Germany. The majority of its directors and management (and certain of the
parties named in this document) reside outside the United States, and all, or a substantial portion of, E.ON AG’s
and such persons’ assets are located outside the United States. As a result, it may not be possible for investors to
effect service of process upon E.ON AG or such persons within the United States, or to enforce against E.ON AG
or such persons in the United States judgments obtained in the U.S. courts, including judgments predicated upon
the civil liability provisions of the federal securities laws of the United States.
Corporate disclosure in Germany may differ from that in the United States.
There may be less publicly available information about German public companies, such as E.ON, than is
regularly made available by public companies in the United States and in other jurisdictions. We ceased to be an
SEC registrant effective December 9, 2007 and, in connection therewith, ceased making filings with the SEC on
September 10, 2007.
34
USE OF PROCEEDS
We estimate that the net proceeds from the issuance and sale of the Notes will be approximately U.S.$2,969
million after deducting underwriting discounts and commissions and other expenses of the offering that are to be
borne by the Issuer. We intend that substantially all of the net proceeds will be on-lent by the Issuer to the
Guarantor and/or entities owned directly or indirectly by the Guarantor for general corporate purposes, which
may include financing of recently announced acquisitions.
35
EXCHANGE RATE INFORMATION
We publish our consolidated financial statements in euros. As used in this offering memorandum, the term
“noon buying rate” refers to the rate of exchange for euros, expressed in U.S. dollars per euro, as announced by
the Federal Reserve Bank of New York for customs purposes as the rate in The City of New York for cable
transfers payable in foreign currencies.
The table below shows noon buying rates for the periods and dates indicated. The average for each period is
computed using the noon buying rate on the last business day of each month during the period.
On April 14, 2008, the noon buying rate between euro and U.S. dollars was €1.00 = $1.58.
Year ended December 31,
High
Low
Year-end
Average
2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008 (through April 14) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.26
1.36
1.35
1.33
1.49
1.58
1.04
1.18
1.17
1.19
1.29
1.44
1.26
1.35
1.18
1.32
1.46
—
1.14
1.25
1.24
1.27
1.38
1.51
The following table shows the high and low noon buying rate for U.S. dollars per euro for each month since
September 1, 2007.
Month
High
Low
October 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
November 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
April 2008 (through April 14) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.45
1.49
1.48
1.49
1.45
1.58
1.58
1.41
1.44
1.43
1.46
1.52
1.52
1.56
36
CAPITALIZATION
The following table sets forth, on a consolidated basis, (i) the cash and cash equivalents and capitalization of
the Guarantor and its consolidated subsidiaries at December 31, 2007, in accordance with IFRS; (ii) relevant
adjustments to show the effect of this offering of Notes; and (iii) the cash and cash equivalents of the Guarantor
and its consolidated subsidiaries at December 31, 2007 as adjusted solely for the effect of this offering of Notes.
You should read this table together with our consolidated IFRS financial statements and related discussion and
analysis included herein.
As at December 31, 2007
Actual
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . € 2,887
Adjustments
(in € millions)(3)
As adjusted
€1,879
€ 4,766
Financial liabilities(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . €21,464
Shareholders’ equity:
1,734
Capital stock(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,825
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,828
Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . 10,656
Treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(616)
Reclassification related to put options on treasury stock . . . . . . . . . . . . .
(1,053)
€1,899(4)
€ 23,363
—
—
—
—
—
—
1,734
11,825
26,828
10,656
(616)
(1,053)
Total equity attributable to shareholders . . . . . . . . . . . . . . . . . . . . .
—
49,374
49,374
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . €70,838
€1,899(4)
€ 72,737
(1) Includes current and non-current financial liabilities. See Note 26 of the Notes to our Consolidated Financial
Statements on page F-68. Subsequent to December 31, 2007, there has not been a material change in our
consolidated financial liabilities. There has been no other material change since December 31, 2007 in our
consolidated capitalization or indebtedness.
(2) As of December 31, 2007, the Guarantor’s authorized share capital amounted to €1.73 billion divided into
631,622,782 registered ordinary shares with no par value.
(3) The euro equivalent of Notes offered hereby is based on a euro/U.S. dollar exchange rate of
U.S. $1.58 = €1.00, which was the noon buying rate for cable transfers payable in euro, as reported by the
Federal Reserve Bank of New York on April 14, 2008.
(4) The adjustment of €1,899 million reflects the euro equivalent of the $3,000 million principal amount of the
Notes based on a euro/U.S. dollar exchange rate of U.S. $1.58 = €1.00. The principal amount of the Notes
would not have been the financial liability recorded on our consolidated balance sheet under IFRS. Nonderivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at
amortized cost, using the effective interest method. Initial measurement takes place at fair value plus
transaction costs. In subsequent periods, the amortization and accretion of any premium or discount is
included in financial results.
37
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
This section should be read in conjunction with our consolidated financial statements for the years ended
and as at December 31, 2007 and 2006, prepared in accordance with IFRS and contained herein beginning on
page F-3, and our consolidated financial statements for the years ended and as at December 31, 2006 and 2005,
prepared in accordance with U.S. GAAP and incorporated herein by reference. See “Presentation of Financial
Data — Incorporation of Certain Financial Statements by Reference”.
Overview
On June 16, 2000, the Company completed the merger between VEBA and VIAG. The VEBA-VIAG
merger was accounted for under the purchase method of accounting. The operations of VIAG have been included
in E.ON’s financial data since July 1, 2000. For more information on the VEBA-VIAG merger, see “Business —
History and Development of the Company.”
In March 2003, E.ON completed the acquisition of all of the outstanding shares of the former Ruhrgas and
has fully consolidated Ruhrgas’ results since February 2003. The total cost of the transaction to E.ON, including
settlement costs and excluding dividends acquired, amounted to €10.2 billion. Goodwill in the amount of
€2.9 billion resulted from the purchase price allocation. In late January 2003, E.ON completed the first step of
the two-step RAG/Degussa transaction. In the first step, E.ON acquired RAG’s Ruhrgas stake and tendered
37.2 million of its shares in Degussa to RAG at the price of €38 per share, receiving total proceeds of
€1.4 billion. A gain of €168 million was realized from the sale. Following this transaction and the completion of
the tender offer to the other Degussa shareholders, RAG and E.ON each held a 46.5 percent interest in Degussa,
with the remainder being held by the public. In the second step, E.ON sold a further 3.6 percent of Degussa to
RAG on May 31, 2004, reducing its stake to 42.9 percent of Degussa. Total proceeds from this transaction
amounted to €283 million, resulting in a gain of €51 million. In December 2005, E.ON AG and RAG signed a
framework agreement on the sale of E.ON’s 42.9 percent stake in Degussa to RAG. As part of the
implementation of that framework agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft
in March 2006 and agreed on the forward sale of that entity to RAG for a purchase price of €2.8 billion (equal to
€31.50 per Degussa share). The transaction closed in July 2006, with E.ON recording a book gain of
€596 million on the forward sale. Until the completion of this transaction, E.ON and RAG operated Degussa
under joint control, and E.ON accounted for its 42.9 percent interest in Degussa under the equity method. E.ON
owns a 39.2 percent interest in RAG. For additional material on acquisitions and dispositions during the period
under review, see “— Acquisitions and Dispositions” below.
Basis Of Presentation
Accounting Principles. In 2002, the European Parliament and the European Council mandated the adoption
of IFRS, as adopted by the EU, by companies whose securities are publicly traded on a regulated market in an
EU member state, in respect of fiscal years beginning on or after January 1, 2005. E.ON made use of the option
available under German law for companies that had been preparing their consolidated financial statements in
accordance with U.S. GAAP and whose stock was officially listed for public trading in a non-EU member state
to defer the mandatory adoption of IFRS until 2007. Until December 31, 2006, E.ON prepared its financial
statements in accordance with U.S. GAAP. E.ON’s American Depositary Shares were listed on the New York
Stock Exchange until September 7, 2007, and the Company was deregistered and terminated its reporting
obligations with the Securities and Exchange Commission as of December 2007.
E.ON’s consolidated financial statements for the year ended December 31, 2007, as included in this offering
memorandum, have been prepared in accordance with IFRS 1. These consolidated financial statements have been
prepared in accordance with Article 315a (1) of the HGB and with those IFRS and IFRIC interpretations that had
been adopted by the European Commission for use in the EU as of the end of the fiscal year, and whose
application was mandatory as of December 31, 2007. In addition, E.ON has elected the voluntary early adoption
38
of IFRS 8. For information about the changes in the Group’s accounting policies as compared with the
accounting principles used in the annual consolidated financial statements for prior years, i.e., U.S. GAAP, see
Note 1 of the Notes to Consolidated Financial Statements. For information about the effects of the transition from
U.S. GAAP to IFRS, see Note 35 of the Notes to Consolidated Financial Statements.
In connection with the transition to IFRS, E.ON’s financial statements for the fiscal year 2006 have been
prepared according to IFRS, and the consolidated financial statements included in this offering memorandum
therefore contain comparable information for 2006 prepared on the basis of IFRS. Accordingly, the analysis of
E.ON’s consolidated results and those of its individual market units in 2007 and 2006 presented below has been
prepared using the financial statements prepared in accordance with IFRS. As E.ON has not prepared any
financial statements for 2005 in accordance with IFRS, the parallel year-on-year analysis of our results for 2005
and 2006 has been prepared on the basis of E.ON’s U.S. GAAP consolidated financial statements (included in
our Annual Report on Form 20-F for the fiscal year ended December 31, 2006 and incorporated herein by
reference), which are not included in this offering memorandum. Unless otherwise indicated, financial data for
2006 appearing outside of such year-on-year analysis (e.g., in the analysis of Liquidity and Capital Resources and
that of Cash Flow and Capital Expenditures), has been prepared in accordance with IFRS.
Sales. Unless otherwise indicated, sales are presented net of electricity and energy taxes.
Non-GAAP Measures. E.ON uses “adjusted EBIT” as the measure pursuant to which the Group evaluates
the performance of its segments and allocates resources to them. Adjusted EBIT is an adjusted figure derived
from income/(loss) from continuing operations (before intra-Group eliminations when presented on a segment
basis) before income taxes and interest income. Adjustments include net book gains resulting from disposals, as
well as cost-management and restructuring expenses and other non-operating earnings of an exceptional nature.
In addition, net interest income is adjusted using economic criteria and excluding certain special items, i.e., the
portions of interest expense that are non-operating. Management believes that adjusted EBIT is the most useful
segment performance measure because it better depicts the performance of individual business units independent
of changes in interest income and taxes. During all relevant periods, E.ON has used adjusted EBIT as its primary
segment reporting measure, originally in accordance with SFAS 131 under U.S GAAP, and now in accordance
with IFRS 8. However, on a consolidated Group basis, adjusted EBIT is considered a non-GAAP measure that
should be reconciled to the most directly comparable GAAP measure. Adjusted EBIT should not be considered
in isolation as a measure of E.ON’s profitability and should be considered in addition to, rather than as a
substitute for the most directly comparable GAAP measures. In particular, there are material limitations
associated with the use of Adjusted EBIT as compared with such GAAP measures, including the limitations
inherent in E.ON’s determination of each of the adjustments noted above. E.ON seeks to compensate for those
limitations by providing below a detailed reconciliation of adjusted EBIT to income from continuing operations
before income taxes and minority interests and net income, the most directly comparable GAAP measures, as
well as the more detailed textual analysis of year-on-year changes in the key components of each of the
reconciling items appearing under the caption “— Results of Operations — E.ON Group — Reconciliation of
Adjusted EBIT” for each of the relevant periods. As a result of these limitations and other factors, adjusted EBIT
as used by E.ON may differ from, and not be comparable to, similarly titled measures used by other companies.
For further details, see Note 33 of the Notes to Consolidated Financial Statements.
Segment Reporting. Until December 31, 2007, E.ON’s core energy business was divided into five regional
market units (Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest), plus the Corporate Center.
The lead company of each market unit reports directly to E.ON AG. E.ON’s financial reporting mirrors this
structure, with each of the five market units and the results of the enhanced Corporate Center (including
consolidation effects) constituting a separate segment for financial reporting purposes. Until its disposal, E.ON
also reported its only remaining telecommunications interest, a 50.1 percent stake in the Austrian mobile
telecommunications network operator ONE GmbH (“ONE”), which was accounted for at equity in E.ON’s
consolidated financial statements, under Corporate Center. For the period between Degussa’s deconsolidation
and E.ON’s disposal of its interest in July 2006, E.ON’s proportionate share of Degussa’s after-tax earnings
39
continued to be presented outside of the core energy business as part of E.ON’s “Other Activities,” which was
reported as a separate segment under U.S GAAP.
Since January 1, 2008, E.ON has been organized into nine different market units, having added the Energy
Trading, Italy, Russia and Climate & Renewables market units. If and when we will be able to close the
acquisition of Viesgo and additional generation capacity in Spain from Endesa, these operations are expected to
be organized in the new market unit Spain. For information about the planned acquisition, see “Business —
History and Development of the Company.” Until the end of 2008, the results of each of the new market units
other than Energy Trading will be reported as part of the Corporate Center segment; Energy Trading’s results
will be reported separately. For information about the new market unit structure, see “Summary — Business
Overview.”
Acquisitions And Dispositions
The following discussion summarizes each of the principal acquisitions and dispositions made by E.ON
since January 1, 2005, and is organized by business segment according to E.ON’s market unit structure as of
December 31, 2007.
Central Europe. In 2005, E.ON Energie acquired the remaining interests of 1.0 percent and 1.3 percent,
respectively, in the Czech regional electricity utilities Jihomoravská energetika a.s. and Jihoceská energetika a.s.
for a total of €5 million. As of January 1, 2005, E.ON Energie re-organized the entities and fulfilled legal
unbundling requirements by transferring the businesses of JME and JCE to three new subsidiaries. E.ON Energie
now holds 100.0 percent of each of E.ON Ceská republika, a.s., E.ON Distribuce, a.s. and E.ON Energie, a.s. No
goodwill resulted from the purchase price allocation.
In February 2005, E.ON Energie acquired 67.0 percent stakes in each of the two Bulgarian electricity
distribution companies Varna and Gorna Oryahovitza. The aggregate purchase price of €141 million, which was
subsequently reduced to €138 million, had already been paid in 2004. Goodwill of €16 million resulted from the
purchase price allocation. The companies were fully consolidated as of March 1, 2005.
In 2005, E.ON Energie increased its stake in the Hungarian gas distribution and supply company KÖGÁZ
from 31.2 percent to 98.1 percent in several steps for aggregate consideration of €27 million. No goodwill
resulted from the purchase price allocation. KÖGÁZ was consolidated as of April 1, 2005. As of December 31,
2007 E.ON Energie held 99.6 percent.
In July 2005, E.ON Energie transferred its 51.0 percent interest (49.0 percent voting interest) in
Gasversorgung Thüringen GmbH (“GVT”) and its 72.7 percent interest in Thüringer Energie AG (“TEAG”) to
Thüringer Energie Beteiligungsgesellschaft mbH (“TEB”). Municipal shareholders also transferred to TEB
interests in GVT totaling 43.9 percent. Consequently, GVT was merged into TEAG and the merged entity was
renamed E.ON Thüringer Energie AG (“ETE”). Following this reorganization, E.ON Energie held an
81.5 percent interest in TEB and TEB held a 76.8 percent interest in ETE. The consolidation of GVT as of July 1,
2005, with an acquisition cost of €168 million, led to goodwill of €58 million as a result of the purchase price
allocation. The transfer of the stakeholding in TEAG resulted in a gain of €90 million. As of December 31, 2007,
E.ON Energie held 77.0 percent of ETE.
In September 2005, E.ON Energie completed the acquisition of 100.0 percent of the Dutch electricity and
gas distributor NRE. The purchase price amounted to €79 million, with €46 million in goodwill resulting from
the purchase price allocation. NRE was consolidated as of September 1, 2005.
In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution
company Electrica Moldova — renamed E.ON Moldova — and simultaneously increased its stake in the
company to 51.0 percent by subscribing to a capital increase. The total consideration for the 51.0 percent
40
interest amounted to €102 million, with no goodwill resulting from the purchase price allocation. E.ON Moldova
was consolidated as of September 30, 2005.
In June 2005, the general meeting of Contigas passed a resolution authorizing E.ON Energie to use a
squeeze-out procedure to acquire any remaining Contigas stock still held by minority shareholders. In July 2005,
E.ON Energie acquired an additional 0.9 percent interest in Contigas through a public offer. Following the
completion of the squeeze-out in November 2005, E.ON Energie acquired the remaining 0.2 percent and now
owns 100.0 percent of Contigas. Total consideration was €45 million (of which €36 million was attributable to
the transfer of E.ON shares), resulting in goodwill from the purchase price allocation of €36 million.
In August 2006, E.ON Energie and RWE swapped certain of their respective shareholdings in Hungary and
the Czech Republic. In Hungary, E.ON Energie acquired — in addition to its existing interest of 50.02 percent —
49.9 percent of the shares of DDGÁZ, a gas distribution company (fully consolidated in 2005). RWE acquired
E.ON Energie’s interest of 16.3 percent in Fövárosi Gázmüvek Részvénytársaság. In the Czech Republic, E.ON
Energie gave up certain minority shareholdings and increased its interest in JCP (a gas distribution company) in
two steps, first acquiring additional shares from RWE to increase its existing interest of 13.1 percent to
59.8 percent, and then in September 2006 acquiring an additional 39.2 percent interest in JCP from
Oberösterreichische Ferngas AG and other minority shareholders. As of December 31, 2006, E.ON Energie held
a 99.0 percent interest in JCP, which was consolidated as of September 1, 2006. In January 2007, E.ON Energie
acquired the remaining 1.0 percent in JCP in a squeeze-out proceeding and now holds 100.0 percent of JCP. The
total consideration (for JCP and DDGÁZ) including the fair value of the swapped E.ON interest amounted to
€104 million, of which €30 million was paid in cash, with €3 million in goodwill resulting from the purchase
price allocation for DDGÁZ (the allocation for JCP resulted in no goodwill). As part of the asset swap, E.ON
Energie acquired in the Czech Republic a 25.0 percent interest in PPH and a 49.3 percent interest in PP for
€63 million.
In December 2006, E.ON Energie acquired a 49.9 percent minority interest in the waste incineration
company SOTEC GmbH. In January 2008, E.ON Energie acquired the remaining shares. Total consideration
amounted to €120 million.
In December 2006, E.ON Energie acquired 75.0 percent of the share capital of Dalmine, an Italian company
that focuses on the wholesale of electricity and gas, primarily to industrial customers. The purchase price
amounted to €47 million. The remaining shares were acquired in October 2007 for €17 million. Dalmine has
been consolidated since December 1, 2006. Goodwill of €9 million was recorded following the final purchase
price allocation.
Pan-European Gas. In November 2004, ERI signed an agreement with the Hungarian oil and gas company
MOL RT. (“MOL”) for the acquisition of interests of 75.0 percent minus one share in each of MOL’s gas trading
and gas storage units and its 50.0 percent interest in the gas importer Panrusgáz Zrt. (“Panrusgáz”). In December
2005, the European Commission approved the acquisitions of the gas trading and storage businesses subject to
certain conditions. One of these conditions is that MOL must fully divest its gas storage and trading businesses.
As a result, ERI signed an agreement providing for its acquisition of the remaining 25.0 percent plus one share of
the gas storage and trading businesses. The total consideration amounted to €445 million. In addition, ERI
assumed debt amounting to €600 million. ERI and MOL also agreed upon a purchase price adjustment
mechanism designed to reflect developments in the relevant regulatory framework through 2009. The acquisition
of the gas storage and trading units was completed by the end of March 2006, and the purchase price was
subsequently adjusted to €400 million. The initial goodwill of €205 million was reduced to €119 million after a
purchase price adjustment and the purchase price allocation. The acquisition of MOL’s 50.0 percent interest in
Panrusgáz was completed at the end of October 2006.
In June 2005, E.ON Ruhrgas acquired a 51.0 percent stake in the Romanian gas supplier S.C. Distrigaz
Nord S.A. (“Distrigaz Nord”) from the Romanian government in a two-step transaction. In the first step, E.ON
Ruhrgas acquired a 30.0 percent share in Distrigaz Nord. In the second step, which immediately followed the
41
first, this stake was increased to 51.0 percent through a capital increase. E.ON Ruhrgas paid an aggregate of
€305 million for the 51.0 percent stake; €127 million for the 30.0 percent interest and €178 million in the capital
increase. Goodwill of €60 million resulted from the purchase price allocation. Distrigaz Nord was consolidated
as of June 30, 2005 and has since been renamed E.ON Gaz România.
In November 2005, E.ON Ruhrgas acquired Caledonia Oil and Gas Ltd. (“Caledonia”), a U.K. gas
production company with interests in a number of producing gas fields and development projects in the British
North Sea, two field pipelines and 100.0 percent of a gas trading company. The seller was a group of investors
led by the private equity firm First Reserve. Caledonia was subsequently renamed E.ON Ruhrgas North Sea. The
total purchase price for the 100.0 percent interest in Caledonia amounted to €602 million and was primarily paid
through the issuance of loan notes. For more information on these loan notes, see Note 26 of the Notes to
Consolidated Financial Statements. Goodwill of €390 million resulted from the final purchase price allocation.
Caledonia was fully consolidated as of November 1, 2005.
In June 2007, E.ON Ruhrgas AG participated in the joint venture to plan a new European gas pipeline in
Scandinavia. This Skanled pipeline is to transport Norwegian gas to Norway, Sweden and Denmark. With a
15 percent stake, E.ON Ruhrgas is one of the largest partners in the European pipeline project, in which a total of
10 companies from Norway, Sweden, Denmark and Poland are involved. The total investment for the pipeline (of
which E.ON expects to bear a pro rata share) is estimated at €1,300 million according to an updated design
incorporating developments in the markets for the procurement of materials and construction services. A final
decision on construction of the pipeline is to be taken by the end of 2009. If constructed, the pipeline is then
expected to come into operation by 2012.
In August 2007, E.ON Ruhrgas acquired through its subsidiary E.ON Ruhrgas Norge AS an approximately
28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from Shell, retroactively as of January 1,
2007. E.ON Ruhgas Norge AS’ share of the investments for developing the fields is expected to be around $1.4
billion (around €1.0 billion). Skarv and Idun are both located in the northern Norwegian Sea, just below the
Arctic Circle. Gas production is expected to start in 2011.
In November 2007, E.ON Ruhrgas acquired a 10 percent stake in the Austrian gas transportation company
Baumgarten-Oberkappel Gasleitungsgesellschaft mbH. As a result, the shareholding of E.ON Ruhrgas in the
company has increased to 15 percent.
In December 2007, E.ON Ruhrgas E & P GmbH acquired a 30.05 percent stake in the Austrian holding
company EESU Holding GmbH, which subsequently acquired an indirect 25 percent stake in the Austrian
exploration company Roöhl-Aufsuchungs Aktiengesellschaft.
U.K. In the first half of 2005, E.ON UK acquired, in two tranches, 100.0 percent of the equity of Enfield
Energy Centre Ltd. (“Enfield”) from NRG, El Paso and Indeck. The total consideration amounted to
€185 million, with no goodwill resulting from the purchase price allocation. Enfield was fully consolidated as of
April 1, 2005.
In July 2005, E.ON UK acquired 100.0 percent of Holford Gas Storage Limited (“HGSL”) from Scottish
Power Energy Management Limited. The total consideration amounted to €140 million, with no goodwill
resulting from the purchase price allocation. HGSL was consolidated as of July 28, 2005.
In December 2006, E.ON UK sold its shareholding in Edenderry Power Limited to Bord na Mona plc for
€80 million, realizing a gain on the sale of €20 million.
Nordic. In September 2004, E.ON agreed further details regarding its agreement in principle with Statkraft
to sell a portion (1.6 TWh) of the generating capacity that E.ON Sverige had acquired as part of the Graninge AB
(“Graninge”) acquisition to Statkraft. In July 2005, Sydkraft and Statkraft signed the corresponding agreement,
42
whereby Statkraft would acquire a total of 24 hydropower plants. In accordance with the agreement, Statkraft
took ownership of the plants in October 2005. The total consideration amounted to €481 million, corresponding
to the assets’ book value. Because assets and liabilities were recognized at fair values as part of the purchase
price allocation following the acquisition of Graninge, the sale of the disposal group did not result in a significant
effect on income.
In August 2006, E.ON Sverige sold a 75.1 percent interest in the broadband communication business
E.ON Sverige Bredband to Tele2 for consideration of €44 million. The sale agreement also provides E.ON
Sverige with the option to put its remaining 24.9 percent interest to Tele2 within 24 months and Tele2 with the
call option to acquire E.ON Sverige’s remaining shares in E.ON Sverige Bredband in the event that E.ON
Sverige does not exercise the put option. E.ON recorded a gain of €28 million on the disposal. In June 2007,
E.ON Sverige exercised the put option on E.ON Sverige Bredband and sold the remaining 24.9 percent stake to
Tele2. E.ON recorded a gain of €9 million on the disposal.
U.S. Midwest. In June 2007, ECC sold its approximate 19.6 percent interests in the Argentine gas
distribution company, Ban and related companies for €37 million. In June 2006, ECC’s subsidiaries, LG&E
Power Inc. (“LPI”) and LG&E Power Services LLC, sold a 50.0 percent ownership interest in a 209 MW coalfired facility in North Carolina and sold the remaining operations and maintenance contracts relating to the North
Carolina plant along with four independent power generation facilities contracts for total consideration of €21
million.
Corporate Center. In December 2005, E.ON AG and RAG signed a framework agreement on the sale of
E.ON’s 42.9 percent participation in Degussa to RAG. As part of the implementation of that framework
agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft in March 2006 and agreed on the
forward sale of that entity to RAG for a purchase price of €2.8 billion. The transaction closed in July 2006, with
E.ON recording a book gain of €596 million on the forward sale. Until the completion of this transaction, E.ON
and RAG operated Degussa under joint control, and E.ON accounted for its 42.9 percent interest in Degussa
under the equity method. E.ON owns a 39.2 percent interest in RAG.
In June 2007, E.ON and its partners Telenor and Tele Danmark signed a contract to sell their shares in the
Austrian telecommunications company ONE to a consortium of bidders consisting of France Télécom and the
financial investor Mid Europa Partners. The transfer of E.ON’s 50.1 percent stake became effective on
October 2, 2007. In the fourth quarter of 2007, E.ON realized cash proceeds of €569 million from the sale
(including repayment of shareholder loans previously granted), as well as a book gain of €321 million.
In August 2007, E.ON Climate & Renewables acquired a 100.0 percent stake in E2-I. Through its affiliated
and associated companies, E2-I primarily operates wind farms in Spain and Portugal. The purchase price totaled
€481 million. E2-I and its affiliated companies were fully consolidated as of September 1, 2007. The E.ON
consolidated financial statements included revenues of €5 million and a loss of €1 million attributable to E2-I for
the period from September 1 through December 31, 2007 (after the write-down of differences in fair values from
the purchase price allocation).
In August 2007, E.ON, ThyssenKrupp and RWE came to an agreement with the foundation “RAG-Stiftung” to
sell their shares of RAG to that foundation. The three shareholding companies held a total of 90 percent of the share
capital of RAG. The block of E.ON shares was transferred on November 30, 2007, for a nominal price of €1.
In October 2007, E.ON acquired from the Russian government’s energy holding company RAO UES a
majority stake in the Russian power plant company OGK-4. After the acquisition of additional smaller tranches
following the purchase of the majority stake, E.ON held 72.7 percent of OGK-4 as of December 31, 2007. The
total cost incurred by E.ON for this acquisition, which includes a contractually agreed capital increase of
€1.3 billion to finance the investment program planned for the coming years, was €4.4 billion.
43
Under Russian capital-markets legislation, E.ON was required to make a public offer to purchase the
remainder of the shares held by the minority shareholders of OGK-4, and this offer, at a price of 3.3503 rubles
per share, was made public on November 15, 2007. The acceptance period ended on February 4, 2008. E.ON was
thus able to acquire additional shares equivalent to approximately 3.4 percent of OGK-4 and increase its total
ownership stake to approximately 76.1 percent. As was expected, RAO UES did not accept the offer for its
22.5 percent stake in OGK-4.
OGK-4 operates conventional power plants at five locations with a total installed output of 8.6 GW and
plans to build additional power plants with a capacity of approximately 2.4 GW at the existing locations by 2011.
OGK-4 was consolidated as of October 1, 2007. The E.ON consolidated financial statements included revenues
of €248 million and earnings of €3 million (after the write-down of fair value adjustments from the preliminary
purchase price allocation) attributable to OGK-4 for the period from October 1 through December 31, 2007. The
purchase price allocation for OGK-4 was not final as of December 31, 2007, because effects on property, plant
and equipment and from potential obligations, in particular, remain to be evaluated. Goodwill of €1,733 million
resulted from the preliminary purchase price allocation.
In December 2007, E.ON North America Holdings LLC acquired all the shares of Airtricity for a purchase
price of €580 million. Airtricity operates a number of wind farms in the U.S. states of Texas and New York with
a total installed capacity of around 250 MW. Additional wind farms are expected to be completed by the end of
2008. The full consolidation of the Airtricity companies took place on December 31, 2007. Goodwill of
€718 million resulted from the preliminary purchase price allocation for the business combinations of Airtricity
and E2-I.
Critical Accounting Policies And Estimates
The preparation of the consolidated financial statements requires management to make estimates and
assumptions that may influence the application of accounting principles within the Group and affect the valuation
and presentation of reported figures. Estimates are based on past experience and on additional knowledge
obtained on transactions to be reported. Actual amounts could differ from these estimates. The estimates and
underlying assumptions are reviewed on an ongoing basis. Adjustments to accounting estimates are recognized in
the period in which the estimate is revised if the change affects only that period or in the period of the revision
and subsequent periods if both current and future periods are affected. Estimates are particularly necessary for
the measurement of the value of property, plant and equipment and of intangible assets, especially in connection
with purchase price allocations, the recognition and measurement of deferred taxes, the accounting treatment of
provisions for pensions and miscellaneous provisions, as well as for impairment testing in accordance with
IAS 36, “Impairment of Assets” (“IAS 36”). The underlying principles used for estimates in each of the relevant
topics are outlined in the respective sections.
Business Combinations
In accordance with the exemption allowed under IFRS 1, the provisions of IFRS 3, “Business
Combinations” (“IFRS 3”) were not applied with respect to the accounting for business combinations that
occurred before January 1, 2006. The goodwill maintained from this period did not include any intangible assets
that had to be reported separately under IFRS. Conversely, there were no intangible assets that until now had
been reported separately that had to be included in goodwill. As no adjustment for intangible assets was required
relating to such business combinations, the goodwill reported under U.S. GAAP was maintained in E.ON’s
opening balance sheet under IFRS.
Business combinations are accounted for by applying the purchase method, whereby the purchase price is
offset against the proportional share in the acquired company’s net assets. In doing so, the values at the
acquisition date are used as a basis. The acquiree’s identifiable assets, liabilities and contingent liabilities are
recognized at their fair values, regardless of the extent attributable to minority interests. The fair values of
44
individual assets are determined using published exchange or market prices at the time of acquisition in the case
of marketable securities, for example, and in the case of land, buildings and more significant technical
equipment, generally using independent valuation reports that have been prepared by third parties. If exchange or
market prices are unavailable for consideration, fair values are determined using the most reliable information
available that is based on market prices for comparable assets or on suitable valuation techniques. In such cases,
E.ON determines fair value using the discounted cash flow method by discounting estimated future cash flows by
a weighted average cost of capital. Estimated cash flows are consistent with the internal mid-term planning data
for the next three years, followed by two additional years of cash flow projections, which are extrapolated until
the end of an asset’s useful life using a growth rate based on industry and internal projections. The discount rate
reflects specific risks inherent to the asset.
Transactions with minority shareholders are treated in the same way as transactions with equity holders.
Should the acquisition of additional shares in a subsidiary result in a difference between the cost of purchasing
the shares and the carrying amount of the minority interest acquired, that difference must be fully recognized in
equity.
Gains and losses from disposals of shares to minority shareholders are also recognized in equity, provided
that such disposals do not result in a loss of control.
Intangible assets must be recognized separately from goodwill if they are clearly separable or if their
recognition arises from a contractual or other legal right. Provisions for restructuring measures may not be
recorded in a purchase price allocation. If the purchase price paid exceeds the proportional share in the net assets
at the time of acquisition, the positive difference is recognized as goodwill. A negative difference is immediately
recognized in income.
Management utilizes certain assumptions and estimates believed to be reasonable in fair valuing assets and
liabilities assumed in a business combination. These estimates are based on historical experience and information
obtained from the management of the acquired companies and are inherently uncertain. Critical estimates used in
valuing certain assets include, but are not limited to, future expected cash flows, discount rates, the useful life
over which cash flows will occur, the acquired company’s market position and regulatory environment. Any
changes in these underlying factors and assumptions may materially affect the Company’s financial position and
net income.
Revenue Recognition
The Company generally recognizes revenue upon delivery of products to customers or upon fulfillment of
services. Delivery has occurred when the risks and rewards associated with ownership have been transferred to
the buyer, compensation has been contractually established and collection of the resulting receivable is probable.
Revenues from the sale of goods and services are measured at the fair value of the consideration received or
receivable. Revenues are presented net of sales taxes, returns, rebates and discounts, and after elimination of
intercompany sales. Revenues are generated primarily from the sale of electricity and gas to industrial and
commercial customers and to retail customers. Additional revenue is earned from the distribution of electricity
and gas, as well as from deliveries of steam and heat. Revenues from the sale of electricity and gas to industrial
and commercial customers and to retail customers are recognized when earned on the basis of a contractual
arrangement with the customer; they reflect the value of the volume supplied, including an estimated value of the
volume supplied to customers between the date of their last meter reading and period-end.
Goodwill and Intangible Assets
Goodwill
According to IFRS 3, goodwill is not amortized, but rather tested for impairment at the cash-generating unit
level on at least an annual basis. Impairment tests must also be performed between these annual tests if events or
changes in circumstances indicate that the carrying amount of the respective cash-generating unit might not be
recoverable.
45
Newly created goodwill is allocated to those cash-generating units expected to benefit from the respective
business combination. E.ON has identified the operating units one level below its primary segments as its cashgenerating units.
In a first step, E.ON determines the recoverable amount of a cash-generating unit on the basis of the fair
value (less costs to sell) using valuation procedures that make use of the Company’s internal mid-term planning
data. Valuation is based on the discounted cash flow method, and accuracy is verified through the use of
multipliers. In addition, market transactions or valuations prepared by third parties for comparable assets are used
to the extent available.
In an impairment test, the recoverable amount of a cash-generating unit is compared with its carrying
amount, including goodwill. The recoverable amount is the higher of the cash-generating unit’s fair value less
costs to sell and its value in use. If the carrying amount exceeds the recoverable amount, the goodwill allocated
to that cash-generating unit is adjusted in the amount of this difference. If the impairment thus identified exceeds
the goodwill allocated to the affected cash-generating unit, the remaining assets of the unit must be written down
in the proportion of their carrying amounts. Individual assets may not be written down if their respective carrying
amounts were to fall below the highest of the following as a result:
•
Fair value less costs to sell
•
Value in use
•
Zero
The impairment loss that would otherwise have been allocated to the asset concerned must instead be
allocated pro rata to the remaining assets of the unit. E.ON has elected to perform the annual testing of goodwill
for impairment at the cash-generating unit level in the fourth quarter of each fiscal year.
Impairment losses recognized for goodwill in a cash-generating unit may not be reversed in subsequent
reporting periods.
E.ON has goodwill totaling €16,761 million as of December 31, 2007, as compared with €15,320 million as
of December 31, 2006, resulting from various significant acquisitions in recent years. Intangible assets not
subject to amortization amounted to €1,503 million as of December 31, 2007, as compared with €1,263 million
as of December 31, 2006. Future adverse changes in a reporting unit’s economic and regulatory environment
could adversely affect both estimated future cash flows and discount rates and could result in impairment charges
to goodwill which could materially and adversely affect E.ON’s future financial position and net income.
In 2007 and 2006, no impairment charges on goodwill resulted from the testing of goodwill for impairment.
Intangible Assets
IAS 38, “Intangible Assets” (“IAS 38”) requires that intangible assets be amortized over their useful lives
unless their lives are considered to be indefinite. Intangible assets not subject to amortization are measured at
cost and must be tested for impairment annually or more frequently if events or changes in circumstances
indicate that the asset might be impaired.
Acquired intangible assets subject to amortization are classified as marketing-related, customer-related,
contract-based, and technology-based. Internally generated intangible assets subject to amortization are related to
software. Intangible assets subject to amortization are measured at cost and amortized using the straight-line
method over their expected useful lives, generally for a period between 5 and 25 years or between 3 and 5 years
for software, respectively. Useful lives and amortization methods are subject to annual verification. Intangible
assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate
that such assets may be impaired.
46
Intangible assets not subject to amortization are measured at cost and tested for impairment annually or
more frequently if events or changes in circumstances indicate that such assets may be impaired. Moreover, such
assets are reviewed annually to determine whether an assessment of indefinite useful life remains applicable.
In accordance with IAS 36, the carrying amount of an intangible asset, whether subject to amortization or
not, is tested for impairment by comparing the carrying value with its recoverable amount, which is the higher of
an asset’s value in use and its fair value less costs to sell. Should the carrying amount exceed the recoverable
amount, an impairment charge equal to the difference between the carrying amount and the recoverable amount
is recognized. If the reasons for previously recognized impairment losses no longer exist, such impairment losses
are reversed. A reversal shall not cause the carrying amount of an intangible asset subject to amortization to
exceed the amount that would have been determined, net of amortization, had no impairment loss been
recognized during the period.
If a recoverable amount cannot be determined for an individual intangible asset, the recoverable amount for
the smallest identifiable group of assets (cash-generating unit) that the intangible asset may be assigned to is
determined.
***
In 2007, impairment charges of €66 million on intangible assets not subject to amortization resulted from
the impairment tests conducted under the principles outlined above. No impairment charges have been recorded
on goodwill and intangible assets subject to amortization.
Please see Note 14(a) of the Notes to Consolidated Financial Statements for additional information about
goodwill and intangible assets.
The assumptions and conditions used to determine recoverability reflect the Company’s best estimates and
assumptions utilizing data currently available and are consistent with internal planning, but these items involve
inherent uncertainties. As a result, the accounting for such items could result in different amounts if management
used different assumptions or if different conditions occur in future periods.
Property, Plant and Equipment
Property, plant and equipment are initially measured at acquisition or production cost, including
decommissioning or restoration cost that must be capitalized, and are depreciated over their expected useful
lives, generally using the straight-line method, unless a different method of depreciation is deemed more suitable
in certain exceptional cases.
Property, plant and equipment are tested for impairment whenever events or changes in circumstances
indicate that an asset may be impaired. In such a case, property, plant and equipment are tested for impairment
according to the principles prescribed for intangible assets in IAS 36. If an impairment loss is determined, the
remaining useful life of the asset might also be subject to adjustment, where applicable. If the reasons for
previously recognized impairment losses no longer exist, such impairment losses are reversed and recognized in
income. Such reversal shall not cause the carrying amount to exceed the amount that would have been presented
had no impairment taken place during the preceding periods.
Investment subsidies do not reduce the acquisition and production costs of the respective assets; they are
instead reported on the balance sheet as deferred income.
Subsequent costs arising, for example, from additional or replacement capital expenditure are only
recognized as part of the acquisition or production cost of the asset, or else — if relevant — recognized as a
separate asset if it is probable that the Group will receive a future economic benefit and the cost can be
determined reliably.
47
Repair and maintenance costs that do not constitute significant replacement capital expenditure are
expensed as incurred.
In 2007, E.ON recorded impairment charges totaling €33 million on property, plant and equipment.
Financial Instruments
Non-Derivative Financial Instruments
Non-derivative financial instruments are recognized at fair value on the settlement date when acquired.
Unconsolidated equity investments and securities are measured in accordance with IAS 39. E.ON categorizes
financial assets as held for trading, available for sale, or as loans and receivables. Management determines the
categorization of the financial assets at initial recognition.
Securities categorized as available for sale are carried at fair value on a continuing basis, with any resulting
unrealized gains and losses, net of related deferred taxes, reported as a separate component within equity until
realized. Realized gains and losses are recorded based on the specific identification method. Unrealized losses
previously recognized in equity are recognized in financial results in the case of substantial impairment.
Reversals of impairment losses relating to equity instruments are recognized exclusively in equity.
Loans and receivables (including trade receivables) are non-derivative financial assets with fixed or
determinable payments that are not traded in an active market. Loans and receivables are reported on the balance
sheet under “Receivables and other assets.” They are subsequently measured at amortized cost, using the
effective interest method. Valuation allowances are provided for identifiable individual risks. If the loss of a
certain part of the receivables is probable, valuation allowances are provided to cover the expected loss.
Reversals of losses are recognized under “Other operating income.”
Non-derivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at
amortized cost, using the effective interest method. Initial measurement takes place at fair value plus transaction
costs. In subsequent periods, the amortization and accretion of any premium or discount is included in financial
results.
Derivative Financial Instruments and Hedging Transactions
Derivative financial instruments and separated embedded derivatives are measured at fair value as of the
trade date at initial recognition and in subsequent periods. IAS 39 requires that they be categorized as held for
trading as long as they are not a component of a hedge accounting relationship. Gains and losses from changes in
fair value are immediately recognized in net income.
Instruments commonly used are foreign currency forwards and swaps, as well as interest-rate swaps and
cross-currency swaps. Equity forwards are entered into to cover price risks on securities. In commodities, the
instruments used include physically and financially settled forwards and options related to electricity, gas, coal,
oil and emission rights. As part of conducting operations in commodities, derivatives are also acquired for
proprietary trading purposes.
IAS 39 sets requirements for the designation and documentation of hedging relationships, the hedging
strategy, as well as ongoing retrospective and prospective measurement of effectiveness in order to qualify for
hedge accounting. The Company does not exclude any component of derivative gains and losses from the
measurement of hedge effectiveness. Hedge accounting is considered to be appropriate if the assessment of
hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80 to 125
percent effective at offsetting the change in fair value due to the hedged risk of the hedged item or transaction.
48
For qualifying fair value hedges, the change in the fair value of the derivative and the change in the fair
value of the hedged item that is due to the hedged risk(s) are recognized in income. If a derivative instrument
qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is recognized in
equity (as a component of accumulated other comprehensive income) and reclassified into income in the period
or periods during which the transaction being hedged affects income. The hedging result is reclassified into
income immediately if it becomes probable that the hedged underlying transaction will no longer occur. For
hedging instruments used to establish cash flow hedges, the change in fair value of the ineffective portion is
recognized immediately in the income statement. To hedge the foreign currency risk arising from the Company’s
net investment in foreign operations, derivative as well as non-derivative financial instruments are used. Gains or
losses due to changes in fair value and from foreign currency translation are recognized separately within equity
as currency translation adjustments.
Changes in fair value of derivative instruments that must be recognized in income are classified as other
operating income or expenses. Gains and losses from interest-rate derivatives are netted for each contract and
included in interest income. Gains and losses from derivative proprietary trading instruments are shown net as
either revenues or cost of materials. Certain realized amounts are, if related to the sale of products or services,
also included in sales or cost of materials.
Unrealized gains and losses resulting from the initial measurement of derivative financial instruments at the
inception of the contract are not recognized in income. They are instead deferred and recognized in income
systematically over the term of the derivative. An exception to the accrual principle applies if unrealized gains
and losses from the initial measurement are verified by quoted market prices, observable prices of other current
market transactions or other observable data supporting the valuation technique. In this case the gains and losses
are recognized in income.
See Note 30 of the Notes to Consolidated Financial Statements for additional information regarding the
Company’s use of derivative instruments.
The use of valuation models requires E.ON to make assumptions and estimates regarding the volatility of
derivative contracts at the balance sheet date, and actual results could differ significantly due to fluctuations in
value-influencing market data. The valuation models for the interest rate and currency derivatives are based on
calculations and valuations, generally using a Group-wide financial management system that provides consistent
market data and valuation algorithms throughout the Company. The algorithms used to obtain valuations are
those which are commonly used in the financial markets. In certain cases the calculated fair value of derivatives
is compared with results which are produced by other market participants, including banks, as well as those
available through other internally available systems. The valuations of commodity instruments are delivered by
multiple use EDP-based systems in the market units, which also utilize common valuation techniques and models
as described above.
Certain electricity contracts that E.ON has entered into in the ordinary course of business meet all of the
required criteria for a derivative as defined in IAS 39, and are marked to market. However, due to the own use
exemption some of these contracts are not accounted for as derivatives under IAS 39 and therefore are not being
marked to market. As a result, any price volatility inherent in these contracts prior to delivery is generally not
reflected in the operating results of E.ON. If this exemption is disallowed or amended through future
interpretations or actions of the International Accounting Standards Board (“IASB”), the impact on future results
could be significant.
The same applies to gas contracts. The market units enter into gas purchase and sale contracts in connection
with their distribution, sale and retail activities, as well as long-term gas purchase contracts for E.ON Ruhrgas’
gas supplies and for certain subsidiaries of E.ON Energie, E.ON Sverige and the operation of E.ON UK’s
generation plants. Contracts providing for physical delivery in some countries are currently accounted for as
contracts outside the scope of IAS 39, as no functioning natural gas market mechanism or spot market exists in
49
these countries which would allow the Company to net settle the contracts. In the future, it is possible that a
functioning market mechanism or spot market for natural gas could emerge, resulting in a need to reassess the
contracts in these countries for derivatives under IAS 39. If any such reassessment resulted in contracts being
accounted for as derivatives under IAS 39, the impact on future results could be significant.
IFRS 7, “Financial Instruments: Disclosures” (“IFRS 7”), became effective in the 2007 fiscal year. The new
standard requires both quantitative and qualitative disclosures about the extent of risks arising from financial
instruments (e.g., credit, liquidity and market risks). The required information is presented in the Notes to
Consolidated Financial Statements.
Provisions for Pensions and Similar Obligations
The valuation of defined benefit obligations in accordance with IAS 19, “Employee Benefits” (“IAS 19”), is
based on actuarial computations using the projected unit credit method, with actuarial valuations performed at
year-end. The valuation encompasses both pension obligations and pension entitlements that are known on the
balance sheet date as well as economic trend assumptions made in order to reflect realistic expectations.
Actuarial gains and losses that may arise from differences between the estimated and actual number of
beneficiaries and from the underlying assumptions are recognized in full in the period in which they occur. Such
gains and losses are not reported within the Consolidated Statements of Income but rather are recognized within
the Statements of Recognized Income and Expenses (which are included in the consolidated financial statements)
as part of equity.
The service cost representing the additional benefits that employees earned under the benefit plan during the
fiscal year is reported under personnel expenses; interest expenses and expected return on plan assets are reported
under financial results.
Unrecognized past service cost is recognized immediately to the extent that the benefits are already vested
or is amortized on a straight-line basis over the average period until the benefits become vested.
The amount reported in the balance sheet represents the present value of the defined benefit obligation
adjusted for unrecognized past service cost and reduced by the fair value of plan assets. If a net asset position
arises from this calculation, the amount is limited to the unrecognized past service cost plus the present value of
available refunds and reductions in future contributions.
Payments for defined contribution pension plans are expensed as incurred and reported under personnel
costs. Contributions to government pension plans are treated like payments for defined contribution pension
plans to the extent that the Group’s obligations under these pension plans correspond to those under defined
contribution pension plans.
Provisions for Asset Retirement Obligations and Other Provisions
In accordance with IAS 37, provisions are recognized when E.ON has a legal or constructive present
obligation towards third parties as a result of a past event, it is probable that E.ON will be required to settle the
obligation, and a reliable estimate can be made of the amount of the obligation. The provision is recognized at
the expected settlement amount. Long-term obligations are reported as liabilities at the present value of their
expected settlement amounts if the interest rate effect (the difference between present value and repayment
amount) resulting from discounting is material; future cost increases that are foreseeable and likely to occur on
the balance sheet date must also be included in the measurement. Long-term obligations are discounted at the
market interest rate applicable as of the respective balance sheet date. The accretion amounts and the effects of
changes in interest rates are generally presented as part of financial results. A reimbursement related to the
provision that is virtually certain to be collected is capitalized as a separate asset. No offsetting within provisions
is permitted. Advance payments remitted are deducted from the provisions.
50
Obligations arising from the decommissioning and restoration of property, plant and equipment are
recognized during the period of their occurrence at their discounted settlement amounts, provided that the
obligation can be reliably estimated. The carrying amounts of the respective property, plant and equipment are
increased by the same amounts. In subsequent periods, capitalized asset retirement costs are amortized over the
expected remaining useful lives of the assets, and the provision is accreted to its present value on an annual basis.
Changes in estimates arise in particular from deviations from original cost estimates, from changes to the
maturity or the scope of the relevant obligation, and also as a result of the regular adjustment of the discount rate
to current market interest rates. The adjustment of provisions for the decommissioning and restoration of
property, plant and equipment for changes to estimates is generally recognized by way of a corresponding
adjustment to assets, with no effect on income. If the property, plant and equipment to be decommissioned have
already been fully depreciated, changes to estimates are recognized within the income statement.
Contingent liabilities are potential or present obligations toward third parties in which an outflow of
resources embodying economic benefits is not probable or where the amount of the obligation cannot be
measured with sufficient reliability. Contingent liabilities are generally not recognized on the balance sheet.
No provisions are established for contingent asset retirement obligations where the type, scope, timing and
associated probabilities cannot be determined reliably.
Operators of nuclear power plants are required under German nuclear law to establish sufficient financial
provisions for obligations that arise from the use of nuclear power. In accordance with IAS 37 and IFRIC 1, these
provisions include: (1) provisions for management of non-contractual obligations based on experts’ opinions and
estimates, and (2) provisions for contractual obligations based on concluded contracts. All nuclear provisions
include expenses for management of spent nuclear fuel rods, disposal of contaminated operating waste and the
decommissioning of nuclear plants. At year-end 2007, E.ON Energie had provisions in its consolidated accounts
for these purposes equal to €8.9 billion for management of non-contractual obligations and €3.3 billion for
contractual obligations.
Under Swedish law, E.ON Sverige is required to pay fees to the country’s national fund for nuclear waste
management. Each year, the Swedish Nuclear Power Inspectorate calculates the fees for the disposal of highlevel radioactive waste and nuclear power plant decommissioning based on the amount of electricity produced at
the particular nuclear power plant. The proposed fees are then submitted to government offices for approval.
Upon approval, E.ON Sverige makes the corresponding payments. In accordance with IFRIC 5, “Rights to
Interests Arising from Decommissioning, Restoration and Environmental Funds” (“IFRIC 5”), payments into the
Swedish national fund for nuclear waste management are offset by a right of reimbursement of asset retirement
obligations, which is recognized as an asset under “Other assets.” In a departure from the policy applied in
Germany, provisions for Sweden measured on the basis of the contributions to the fund are discounted at the real
interest rate.
Management utilizes certain assumptions and estimates to calculate the fair value of the obligation for
nuclear plant decommissioning and nuclear waste management. Any changes in the underlying data, the timing
in the future that the corresponding costs will be incurred, as well as changes in regulatory requirements, may
adversely affect the Company’s financial position and net income.
Income Taxes
Under IAS 12, “Income Taxes” (“IAS 12”), deferred taxes are recognized on temporary differences arising
between the carrying amounts of assets and liabilities on the balance sheet and their tax bases (balance sheet
liability method). Deferred tax assets and liabilities are recognized for temporary differences that will result in
taxable or deductible amounts when taxable income is calculated for future periods, unless those differences are
the result of the initial recognition of an asset or liability in a transaction other than a business combination that,
51
at the time of the transaction, affects neither accounting nor taxable profit/loss. IAS 12 further requires that
deferred tax assets be recognized for unused tax loss carryforwards and unused tax credits. Deferred tax assets
are recognized to the extent that it is probable that taxable profit will be available against which the deductible
temporary differences and unused tax losses can be utilized. Each of the corporate entities is assessed
individually with regard to the probability of a positive tax result in future years. Any existing history of losses is
incorporated in this assessment. For those tax assets to which these assumptions do not apply, the value of the
deferred tax assets has been reduced.
Deferred tax liabilities caused by temporary differences associated with investments in affiliated and
associated companies are recognized unless the timing of the reversal of such temporary differences can be
controlled within the Group and it is probable that, owing to this control, the differences will in fact not be
reversed in the foreseeable future.
Deferred tax assets and liabilities are measured using the enacted or substantively enacted tax rates expected
to be applicable for taxable income in the years in which temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of changes in tax rates and tax law is generally recognized
in income. Equity is adjusted for deferred taxes that had previously been recognized directly in equity. Following
passage of the 2008 corporate tax reforms in Germany, deferred taxes for domestic companies were calculated
using a total tax rate of 30 percent (2006: 39 percent). This tax rate includes, in addition to the 15 percent (2006:
25 percent) corporate income tax, the solidarity surcharge of 5.5 percent on the corporate tax rate, and the
average trade tax rate of 14 percent (2006: 13 percent) applicable to the E.ON Group. Foreign subsidiaries use
applicable national tax rates.
Note 10 of the Notes to Consolidated Financial Statements shows the major temporary differences so
recorded.
E.ON has significant deferred tax assets and liabilities totaling €6,559 million and €12,959 million,
respectively, as of December 31, 2007, which are expected to be realized through the statement of income over
extended periods of time in the future. Based on the Company’s past performance and the expectations of similar
performance in the future, it is expected that the future taxable income will more likely than not be sufficient to
permit recognition of their deferred tax assets. As of December 31, 2007, changes in value have been established
totaling €212 million for that portion of the deferred tax assets for which this criterion is not expected to be met.
New Accounting Pronouncements
The IASB issued the following accounting pronouncements in 2006, 2007 and 2008, which became
applicable or will become applicable to E.ON in 2007, 2008 and 2009:
•
IFRS 3, Business Combinations;
•
IAS 1, Presentation of Financial Statements;
•
IAS 23, Borrowing Costs;
•
IAS 27, Consolidated and Separate Financial Statements;
•
Amendment to IAS 32, Financial Instruments: Presentation and IAS 1 Presentation of Financial
Instruments;
•
IFRIC 11, IFRS 2 — Group and Treasury Share Transactions;
•
IFRIC 12, Service Concession Arrangements;
•
IFRIC 13, Customer Loyalty Programmes; and
•
IFRIC 14, IAS 19 — The Limit on a Defined Benefit Asset Minimum Funding Requirements and their
Interaction.
52
The application of some of these standards and interpretations is at the present time still subject to adoption
by the EU, which has yet to occur. For details of these pronouncements and their impact or expected impact on
the Company’s results, see Note 2 of the Notes to Consolidated Financial Statements.
Results Of Operations
E.ON’s sales in 2007 increased 7.2 percent to €68,731 million from €64,091 million in 2006. The increase
of €4,640 million was primarily attributable to increased sales at the Central Europe market unit. Net income
increased by 27.0 percent to €7,724 million in 2007 from €6,082 million in 2006, primarily reflecting higher
income from continuing operations partially offset by lower income from discontinued operations, as described
in more detail below. Cash provided by operating activities increased 21.9 percent to €8,726 million in 2007
from €7,161 million in 2006, with the increase being primarily attributable to increases at the Pan-European Gas,
U.K. and Nordic market units, which were offset in part by a decline in the cash generated by the Corporate
Center and the U.S. Midwest market unit.
In 2007, 53.7 percent of the Group’s total sales were to customers in Germany and 46.3 percent were to
customers in other parts of the world, as compared with 54.5 percent and 45.5 percent in 2006, respectively.
E.ON’s sales and earnings are influenced by a number of differing economic and other external factors. The
energy business is generally not subject to severe fluctuations in its results, but is to some extent affected by
seasonality in demand related to weather patterns. Typically, demand is higher for the Central Europe,
Pan-European Gas and U.K. market units during the winter months and for the U.S. Midwest market unit during
the summer. For a discussion of trends and factors affecting E.ON’s businesses, see the market unit descriptions
in “Summary — Business Overview” and “Risk Factors.”
Year Ended December 31, 2007 Compared With Year Ended December 31, 2006
The following table sets forth sales and adjusted EBIT, which are presented in accordance with IFRS, for
each of E.ON’s business segments for 2007 and 2006 (in each case excluding the results of discontinued
operations):
E.ON BUSINESS SEGMENT SALES AND ADJUSTED EBIT
IFRS
2007
Sales
IFRS
2006
Adjusted
EBIT
Sales
Adjusted
EBIT
(€ in millions)
Central Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,029
Pan-European Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,745
U.K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,584
Nordic(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,339
U.S. Midwest(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,819
Corporate Center(1)(2)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,785)
4,670
2,576
1,136
670
388
(232)
27,197
22,947
12,518
2,827
1,930
(3,328)
4,235
2,347
1,239
512
426
(403)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,208
64,091
8,356
68,731
(1) Excludes the sales and adjusted EBIT of certain activities now accounted for as discontinued operations. For
more details, see “— Discontinued Operations” for this period below and Note 4 of the Notes to
Consolidated Financial Statements.
(2) Includes primarily the parent company and effects from consolidation (including the elimination of
intersegment sales), as well as the results of its remaining telecommunications interests, as explained above.
Sales between companies in the same market unit are eliminated in calculating sales on the market unit
level.
(3) Includes adjusted EBIT of Degussa prior to its disposal in 2006.
For a reconciliation of adjusted EBIT to net income, see the discussion under “— E.ON Group” below.
53
E.ON Group
E.ON’s sales in 2007 increased 7.2 percent to €68,731 million from €64,091 million in 2006. The increase
of €4,640 million was primarily attributable to increased sales at the Central Europe market unit. As illustrated in
the table above, the overall increase in the Group’s sales also reflected an increase in sales at the Nordic and U.K.
market units, which more than offset decreases at the Pan-European Gas and U.S. Midwest market units and the
Corporate Center.
Sales of the Central Europe market unit increased 17.8 percent in 2007 to €32,029 million from
€27,197 million in 2006. Nordic’s sales increased by 18.1 percent to €3,339 million from €2,827 million in 2006.
Sales of the U.K. market unit increased by 0.5 percent, amounting to €12,584 million in 2007, as compared to
€12,518 million in 2006. Pan-European Gas’ sales decreased by 0.9 percent to €22,745 million in 2007 from
€22,947 million in 2006. Sales of the U.S. Midwest market unit decreased by 5.8 percent in 2007 to
€1,819 million compared with €1,930 million in 2006. The elimination of intersegment sales at the Corporate
Center resulted in the segment reporting negative sales of €3,328 million in 2006 and negative sales of
€3,785 million in 2007. The 2007 figure also reflected €252 million in sales of newly acquired companies
(primarily OGK-4 and Airtricity). The sales of each of these segments are discussed in more detail below.
Changes in inventories amounted to €22 million in 2007 as compared with €8 million in 2006.
Own work capitalized increased by 30.9 percent or €122 million to €517 million in 2007, as compared with
€395 million in 2006, mainly resulting from engineering services for new development projects. The increase
reflected an increase of own work capitalized at the Nordic market unit, primarily due to work in progress in
capital investment projects at the power distribution business at the Central Europe market unit mainly resulting
from construction within the market unit and at the Pan-European Gas market unit.
Other operating income decreased by €138 million to €7,776 million in 2007 as compared to €7,914 million
in 2006. This 1.7 percent decrease in other operating income was primarily attributable to a decrease in income
from exchange rate differences (including realized gains on currency derivatives) and lower miscellaneous other
operating income. These negative effects were partially offset by higher gains on derivative financial instruments
and higher gains on the disposal of investments and securities, which in 2007 included the book gain from the
sale of the stake in ONE. Under IFRS, we no longer net our gains and losses in respect of derivatives and
exchange rate differences, but rather report them separately as components of other operating income and other
operating expense, respectively.
Cost of materials increased by €3,515 million from €46,708 million in 2006 to €50,223 million in 2007.
This 7.5 percent increase was mainly attributable to an increase at the Central Europe market unit, reflecting
increased expenses for Central Europe’s network that primarily resulted from increased deliveries onto Central
Europe’s network of electricity pursuant to Germany’s Renewable Energy Law.
Personnel expenses increased by €68 million from €4,529 million in 2006 to €4,597 million in 2007. This
1.5 percent increase was attributable to an increase at the UK market unit, reflecting an increase in headcount,
primarily in the retail business. This effect was partially offset by lower personnel expenses at the Central Europe
market unit, primarily as a result of a decrease in provisions for early retirement programs.
Depreciation, amortization and impairment charges amounted to €3,194 million in 2007 as compared with
€3,670 million in 2006. This 13.0 percent or €476 million decrease reflected decreases at the UK market unit and
at the Central Europe market unit, as well as at the Nordic market unit, in each case resulting from the fact that
impairment charges which had been taken in 2006 did not recur in 2007. These effects were partially offset by an
increase in scheduled depreciation, as depreciation at the Corporate Center increased by €37 million from
€14 million in 2006 to €51 million in 2007 due to the newly consolidated activities, primarily OGK-4, E2-I and
Airtricity.
54
Other operating expenses decreased by 18.3 percent or €2,183 million to €9,724 million in 2007 as
compared to €11,907 million in 2006. The change in this line item was primarily attributable to lower losses on
derivative financial instruments, which generated expenses of €1,331 million in 2007, compared to expenses of
€3,052 million in 2006, primarily reflecting a change in the market value of derivatives at the U.K.,
Pan-European Gas and Nordic market units. Losses from exchange rate differences amounted to €3,218 million
in 2007, compared to €4,447 million in 2006. Miscellaneous other operating expenses increased from
€4,093 million in 2006 to €4,821 million in 2007, primarily reflecting an increase in costs for external audit and
non-audit services and consulting from €263 million in 2006 to €414 million in 2007, as well as costs of
€288 million related to the proposed Endesa acquisition.
Income/Loss from companies accounted for under the equity method amounted to €1,147 million in 2007,
compared with €748 million in 2006. This 53.3 percent or €399 million increase was primarily attributable to
higher income from companies accounted for under the equity method at the Pan-European Gas market unit.
As a result of the factors described above, income (loss) from continuing operations before financial results
and income taxes increased by 64.9 percent or €4,113 million to €10,455 million in 2007, as compared with
€6,342 million in 2006.
Financial results were negative €995 million in 2006 and negative €772 million in 2007. The improvement
resulted from lower interest and similar expenses and higher income from other equity investments mainly due to
lower impairments of other share investments at the Pan-European Gas market unit. These positive effects were
partially offset by a decrease in income from other securities, interest and similar income, primarily reflecting
lower interest income from loans and receivables. For additional information, see Note 9 of the Notes to
Consolidated Financial Statements.
In 2007, E.ON recorded an income tax expense of €2,289 million, as compared to a tax expense of
€40 million in 2006. This significant change was primarily attributable to the increase in earnings, as well as the
fact that the 2006 results had benefited from certain special tax effects. For additional information, see Note 10 of
the Notes to Consolidated Financial Statements.
Results from discontinued operations increased net income by €330 million in 2007, as compared to a
contribution to net income of €775 million in 2006. The significant decrease primarily reflected the fact that the
2006 results included a significant gain on the disposal of Degussa, as well as the significant decrease at the U.S.
Midwest market unit reflecting the results of WKE, which had generated income of €64 million in 2006 and a
loss of €81 million in 2007. For details, see Note 4 of the Notes to Consolidated Financial Statements. The
Group’s net income increased 27.0 percent, totaling €7,724 million in 2007, compared with €6,082 million in
2006. Excluding the results of discontinued operations, E.ON would have recorded net income of €7,394 million
in 2007, as compared to net income of €5,307 million in 2006.
Reconciliation of Adjusted EBIT. As noted above, E.ON uses adjusted EBIT as its segment reporting
measure in accordance with IFRS 8. On a consolidated Group basis, adjusted EBIT is considered a non-GAAP
measure that must be reconciled to the most directly comparable GAAP measure. A reconciliation of Group
adjusted EBIT to net income for each of 2007 and 2006 appears in the table below. The following paragraphs
discuss changes in the principal components of each of the reconciling items to income (loss) from continuing
operations before income taxes and minority interests. For additional details, see Note 33 of the Notes to
Consolidated Financial Statements.
55
IFRS
2007
IFRS
2006
(€ in millions)
Adjusted EBIT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted interest income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net book gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost-management and restructuring expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-operating results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,208
(960)
1,345
(77)
167
8,356
(948)
829
—
(2,890)
Income/(loss) from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,683
(2,289)
7,394
330
5,347
(40)
5,307
775
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,724
6,082
On a consolidated Group basis, adjusted EBIT increased by 10.2 percent to €9,208 million in 2007, as
compared with €8,356 million in 2006.
As detailed in the table below, adjusted interest income, net, amounted to an expense of €960 million in
2007 as compared to an expense of €948 million in 2006. Non-operating interest income, net, amounted to
income of €9 million in 2007 as compared with an expense of €97 million in 2006. In both 2006 and 2007, such
non-operating interest income primarily reflected lower expenses for liabilities related to put options (primarily
at the Corporate Center), as well as higher interest income related to derivatives at the Central Europe market
unit. In 2006, non-operating interest income primarily reflected higher interest charges related to derivatives in
the U.K. market unit that were partially offset by higher interest income at the Central Europe market unit and
the Corporate Center.
IFRS
2007
IFRS
2006
(€ in millions)
Interest income and similar expenses (net) as shown in Note 9 of the Notes to
Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(+) Non-operating interest income, net(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(951)
(9)
(1,045)
97
Adjusted interest income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(960)
(948)
(1) This net figure is calculated by adding in non-operating interest expense and subtracting non-operating
interest income.
Net book gains as used in the reconciliation of adjusted EBIT were €516 million higher than in 2006,
increasing from €829 million in 2006 to €1,345 million in 2007. In both 2006 and 2007, such net book gains
primarily resulted from the sale of interests in funds invested in securities held by the Central Europe market
unit.
Cost-management and restructuring expenses amounted to €77 million, whereas such expenses did not
occur in 2006. These expenses related to the retail operations of the U.K. market unit, as well as to the
implementation of the new internal market unit structure.
The amount reported as other non-operating results amounted to income of €167 million in 2007, as
compared to an expense of €2,890 million in 2006. The significant change in this figure over the period under
review was primarily attributable to contrasting results from the required marking to market of derivatives
(primarily at the U.K. and Pan-European Gas market units). In 2007, such marking to market resulted in our
recording income of €564 million, while in 2006 it had resulted in an expense of €1,946 million. The
improvement in the overall figure was partially offset by costs incurred for the planned acquisition of Endesa and
the storm in Sweden in January 2007. In addition, the 2006 result reflected a total of €665 million in impairment
56
charges (whereas the comparable figure for 2007 was income of €99 million). Following the BNetzA’s reduction
of allowable network charges, E.ON conducted impairment tests on E.ON’s network assets and shareholdings in
municipal distribution network operators in 2006. As a result, E.ON recorded impairment charges totaling
€374 million in its gas distribution businesses. Of this total, €266 million related to the Central Europe market
unit. The remaining impairment loss of €108 million was recorded on other shareholdings at the Pan-European
Gas market unit. Impairment tests on E.ON Energie’s electricity transmission and distribution networks did not
lead to any impairment losses. Further impairments in 2006 related to gas storage and CHP generation assets at
the U.K. market unit, as well as tangible assets at the Pan-European Gas and Nordic market units. The impact of
these impairments was partially offset by effects from the first-time consolidation of VKE at the Central Europe
market unit, which add up to €83 million.
Central Europe
For financial reporting purposes, the Central Europe market unit comprises four business units: Central
Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central
Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear
and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the
retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power
also includes the results of E.ON Benelux, which operates power generation, district heating and gas and
electricity retail businesses in the Netherlands. The Central Europe West Gas business unit reflects the results of
the regional distribution of gas and the gas retail business in Germany. The Central Europe East business unit
primarily includes the results of the regional distribution companies in Bulgaria, the Czech Republic, Hungary,
Romania and Slovakia (with the Slovak activities being valued under the equity method given E.ON Energie’s
minority interest). Other/Consolidation primarily includes the results of E.ON Energie’s business in Italy, other
national and international shareholdings, service companies and E.ON Energie AG, as well as intrasegment
consolidation effects.
Total sales of the Central Europe market unit increased by 17.8 percent to €32,029 million (including
€679 million in intersegment sales) in 2007, compared with a total of €27,197 million (including €813 million in
intersegment sales) in 2006. The overall increase of €4,832 million reflected higher sales at each of Central
Europe’s business units except for the Central Europe West Gas business unit, as described in more detail below.
The following table sets forth the sales of each business unit in the Central Europe market unit in each of the
last two years:
SALES OF CENTRAL EUROPE MARKET UNIT
IFRS
IFRS
2007
2006
(€ in millions)
Percent
Change
Central Europe West Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,293 18,829
Central Europe West Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,676 4,368
Central Europe East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,087 3,469
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
973
531
+23.7
-15.8
+17.8
+83.2
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32,029
+17.8
27,197
Sales of the Central Europe West Power business unit increased by €4,464 million or 23.7 percent from
€18,829 million in 2006 to €23,293 million in 2007. The most significant factor in the overall increase was a
greater contribution to the product mix of sales of electricity produced from renewable resources, as the volume
of such energy, which E.ON Energie is required to purchase and resell under regulatory requirements, generally
bearing significantly higher prices, increased in 2007. Higher electricity prices resulting from the global rise in
raw material and energy prices, as well as an increase in the volume of electricity sold as part of our
non-proprietary trading activities also contributed to the increase in sales.
57
Sales of the Central Europe West Gas business unit decreased by 15.8 percent from €4,368 million in 2006
to €3,676 million in 2007, with the decrease of €692 million reflecting lower volumes resulting from
unseasonably warm winter weather across many parts of Europe, as well as lower sales prices.
Sales of the Central Europe East business unit increased by 17.8 percent or €618 million, from
€3,469 million in 2006 to €4,087 million in 2007, with the increase being primarily due to higher sales in
Hungary reflecting increased prices and an increase in trading revenues. The result also reflected a positive
translation effect between the unit’s operating currencies and the euro and from the first-time inclusion of a full
year of sales from one electricity and one gas company in the Czech Republic which were consolidated as of
September 2006, as well as the first-time inclusion of one Hungarian power company in 2007.
Sales of the Other/Consolidation business unit almost doubled, increasing by €442 million to €973 million
in 2007, with the increase being primarily attributable to the full-year inclusion of sales from Dalmine in 2007.
Total power procured by the Central Europe market unit (excluding physically-settled trading activities)
rose 16.4 percent to 327.2 billion kWh in 2007, compared with 281.2 billion kWh in 2006. The increase was
primarily attributable to an increase in power procured from third parties. E.ON Energie’s own production of
power rose 2.5 percent from 131.3 billion kWh in 2006 to 134.6 billion kWh in 2007. E.ON Energie produced
approximately 41 percent of its power requirements in 2007, compared with approximately 47 percent in 2006.
Compared with 2006, purchases of electricity from third parties increased by 33.9 percent, from 137.6 billion
kWh in 2006 to 184.3 billion kWh in 2007, including the purchase of significantly higher volumes
(approximately 15 TWh) of electricity generated from renewable resources pursuant to Germany’s Renewable
Energy Law. Electricity purchased from jointly operated power stations decreased by 32.4 percent from 12.3
billion kWh in 2006 to 8.3 billion kWh in 2007, primarily as a result of continuing outages at jointly owned
nuclear power stations Krümmel and Brunsbüttel, both of which are operated by Vattenfall.
In 2007, the Central Europe market unit contributed adjusted EBIT of €4,670 million, a 10.3 percent
increase from a total of €4,235 million in 2006. The following table sets forth the adjusted EBIT of each business
unit in the Central Europe market unit in each of the last two years:
ADJUSTED EBIT OF CENTRAL EUROPE MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Central Europe West Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,145 3,636
Central Europe West Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
200
270
Central Europe East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
361
266
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(36)
63
+14.0
-25.9
+35.7
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,670
+10.3
4,235
Adjusted EBIT at the Central Europe West Power business unit increased by €509 million from
€3,636 million in 2006 to €4,145 million in 2007. This 14.0 percent increase was primarily attributable to higher
wholesale electricity prices which could be passed on to customers, and to the revaluation of nuclear provisions,
mainly due to a decision to calculate them on the basis of a significant component of internal financing.
Additionally, the 2006 result reflected certain negative effects recorded in the prior-year period that did not recur
in 2007. These positive effects were partially offset by higher electricity procurement costs, provisions for
obligations in the grid business, higher expenditures resulting in particular from an increase in the amount of
renewable-source electricity delivered onto the network and lower results from network activities. Adjusted
EBIT was also negatively affected by the fact that the 2006 results reflected €220 million in income mainly from
the sale of equity interests and from the release of provisions. The outages at the German power plants Krümmel
and Brunsbüttel and higher costs for maintenance and information technology also reduced overall adjusted
EBIT. Higher group internal cost allocation and the first-time inclusion of results from a start-up retail company
also burdened the results.
58
Adjusted EBIT of the Central Europe West Gas business unit decreased by 25.9 percent to €200 million in
2007, compared with €270 million in 2006. The lower result was primarily due to the unusually warm winter,
which resulted in a decrease in gas sales volumes.
The Central Europe East business unit contributed adjusted EBIT of €361 million in 2007, a 35.7 percent
increase from €266 million in 2006, largely reflecting higher gross margins in Hungary and Romania, higher
results from equity-accounted investees in the Czech Republic as well as in Slovakia, the inclusion of a full year
of earnings from two companies in the Czech Republic (JCP and Teplárna Otrokovice) and translation effects.
These positive effects were partly offset by weather related lower sales volumes in the Czech Republic and by
higher procurement costs in Bulgaria.
Central Europe’s Other/Consolidation business unit recorded adjusted EBIT of negative €36 million in
2007, compared with an adjusted EBIT of €63 million in 2006. This negative change primarily resulted from
higher personnel costs, the impairment of available-for-sale securities reflecting market price declines, higher
audit and consultancy fees, lower results from the sale of securities, lower results from realized hedging
transactions and foreign currency loans, higher depreciation costs, and the fact that the prior-year results had
included the release of provisions.
Pan-European Gas
For financial reporting purposes, the Pan-European Gas market unit is divided into three business units:
Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects
the results of the supply, transmission system, storage and sales businesses, with the midstream operations
essentially including all of the supply and sales business other than exploration and production activities. The
Downstream Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes
consolidation effects.
Total sales of the Pan-European Gas market unit decreased by 0.9 percent to €22,745 million (including
€3,031 million in intersegment sales) in 2007, compared with a total of €22,947 million (including
€2,392 million in intersegment sales) in 2006. The negative impact of the trends in energy prices and severe
competition in the midstream business was not completely offset by the positive effect resulting from the firsttime full-year inclusion of the E.ON Földgaz companies.
The following table sets forth the sales of each business unit in the Pan-European Gas market unit in each of
the last two years:
SALES OF PAN-EUROPEAN GAS MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Up-/Midstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,738 18,889
-6.1
Downstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,625 4,773 +17.9
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(618)
(715) +13.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,745
22,947
-0.9
Sales in the Up-/Midstream business unit decreased in 2007 by €1,151 million or 6.1 percent from
€18,889 million to €17,738 million. Sales volumes were relatively unchanged, increasing from 710 billion kWh
to 713 billion kWh. The impact of the slight increase in volumes was more than offset by the fact that trends in
the various energy prices to which supply costs and sales prices are linked differed over the course of the year,
and lower sales prices due to the severe competition in the midstream business. In the upstream business, sales
decreased by €26 million, in particular as a result of lower sales prices at E.ON Ruhrgas North Sea and E.ON
Ruhrgas UK.
59
In the Downstream Shareholdings business unit, sales increased by €852 million or 17.9 percent to
€5,625 million in 2007 compared with €4,773 million in 2006. The main reason for the change was an increase in
sales in ERI’s downstream operations, particularly the impact of the first-time inclusion of a full year of results
from E.ON Földgaz Trade and E.ON Földgaz Storage following their consolidation as of April 2006. These
positive effects were partially offset by a decrease in sales of €238 million at the other ERI companies mainly
attributable to warmer weather and a €28 million decrease at Thüga’s downstream operations. The decline in
Thüga’s sales primarily derived from lower volumes of gas and electricity sold, mainly due to the warm weather.
Rising gas and electricity prices and the positive impact of changes in the basis of consolidation at Thüga Italia
could not offset this negative impact.
The total volume of gas sold by E.ON Ruhrgas’ midstream operations increased by 0.4 percent to 712.8
billion kWh in 2007 from 709.7 billion kWh in 2006. Sales to domestic distributors decreased by 8.2 percent
from 318.7 billion kWh to 292.5 billion kWh. Sales to domestic municipal utilities increased by 4.1 percent from
163.1 billion kWh to 169.8 billion kWh. E.ON Ruhrgas sold 70.1 billion kWh of gas to domestic industrial
customers, an increase of 3.7 percent from 67.6 billion kWh in 2006. Exports reached 180.4 billion kWh in 2007,
a 12.5 percent increase from 160.3 billion kWh in 2006. The higher sales volumes were mainly attributable to an
approximately 19 percent increase in the UK; in addition sales volumes in Denmark increased strongly in 2007
due to a new contract signed at the beginning of the year. E.ON Ruhrgas purchased approximately 81.8 percent
of its gas supplies from outside Germany and approximately 18.2 percent from German producers in 2007,
compared with 84.4 percent and 15.6 percent, respectively, in 2006. In the Downstream Shareholdings business
unit, total gas sales volumes rose by 11.9 percent from 175.1 billion kWh in 2006 to 197.5 billion kWh in 2007.
ERI increased its sales volumes by 16.8 percent to 177.6 billion kWh from 152.0 billion kWh, primarily due to
the first time full-year inclusion of the E.ON Földgaz companies. Sales volumes at Thüga decreased by 13.8
percent to 19.9 billion kWh from 23.1 billion kWh in 2006, largely due to unfavorable weather conditions.
Adjusted EBIT of the Pan-European Gas market unit increased by 9.8 percent to €2,576 million in 2007
from €2,347 million in 2006. The rise in adjusted EBIT reflected very positive results in the Downstream
Shareholdings business unit, which were only partly offset by lower results in the Up-/Midstream business unit,
as described in more detail below.
The following table sets forth the adjusted EBIT of each business unit in the Pan-European Gas market unit
in each of the last two years:
ADJUSTED EBIT OF PAN-EUROPEAN GAS MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Up-/Midstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,581 1,905
-17.0
Downstream Shareholdings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
987
453 +117.9
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8
(11)
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,576
2,347
+9.8
Adjusted EBIT in the Up-/Midstream business unit decreased by €324 million or 17.0 percent from
€1,905 million in 2006 to €1,581 million in 2007. The €89 million decrease in adjusted EBIT at the upstream
activities primarily reflected lower sales prices at E.ON Ruhrgas UK and E.ON Ruhrgas North Sea, an increase
in impairments relating to exploration activities in the German and the British North Sea and higher operating
and depreciation costs due to the start of production at new fields. Adjusted EBIT in the midstream activities
decreased by €235 million, primarily as a consequence of a decline in gross margin. The decline in gross margin
was related to short-term, asset-based trading activities; proprietary trading transactions; a decline in earnings
attributable to the storage valuation (for which the development of gas prices is the underlying driver); and other
price effects as a consequence of strong competition. The impact of these factors on gross margin was mitigated
60
by the fact that the time lag effect resulting from the fact that procurement prices are adjusted more rapidly than
sales prices had a greater negative impact on adjusted EBIT in 2006. These negative effects were partially offset
by higher income from minority shareholdings, especially that in Gazprom.
In the Downstream Shareholdings business unit, adjusted EBIT increased by €534 million, more than
doubling to €987 million in 2007 from €453 million in 2006. The increase in adjusted EBIT was primarily
attributable to higher earnings at the E.ON Földgaz companies, which were included for the entire year for the
first time and which benefited from a tariff adjustment designed to compensate for lower realized earnings in
prior years, as well as to the fact that prior year results had included €188 million in partial impairments of
certain minority Thüga shareholdings resulting from the introduction of new regulation of network charges in
Germany. Furthermore, book gains on the sale of shareholdings at Thüga Germany and the reduction of the rate
applicable to deferred taxes as a consequence of the German corporate tax reform also served to increase
adjusted EBIT.
U.K.
Total sales of the U.K. market unit in 2007 increased by 0.5 percent to €12,584 million (including
€129 million in intersegment sales) from €12,518 million (including €163 million in intersegment sales) in 2006,
primarily as a result of increased sales in the Non-regulated Business, as explained in more detail below.
The following table sets forth the sales of each business unit in the U.K. market unit in each of the last two
years:
SALES OF U.K. MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,126 12,031
+0.8
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
888
858
+3.5
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(430)
(371) -15.9
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,584
12,518
+0.5
Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and
trading), retail and the energy services businesses in the U.K., increased by €95 million from €12,031 million in
2006 to €12,126 million in 2007. This 0.8 percent increase was primarily attributable to higher average (retail)
prices and higher sales volumes in the energy wholesale business in 2007, which were largely offset by lower
sales volumes in the retail business due to warmer weather, consumer behavior and lower customer numbers.
Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, increased
to €888 million in 2007 from €858 million in 2006. The sales increase of €30 million, or 3.5 percent, was
principally attributable to tariff changes.
Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of
intrasegment sales and had a negative impact on sales of €430 million in 2007, as compared to a negative impact
of €371 million in 2006.
The volume of electricity sold by the U.K. market unit increased by 4.1 billion kWh or 5.6 percent to 77.8
billion kWh, as compared with 73.7 billion kWh in 2006. Market sales associated with trading operations
increased by 7.8 billion kWh or 44.6 percent to 25.3 billion kWh, while mass market sales decreased by 3.7
billion kWh or 9.8 percent to 34.2 billion kWh due to lower customer numbers and warmer weather. Sales to
industrial and commercial customers remained stable at 18.4 billion kWh. The increase in sales was reflected in
61
the volume of own production and power purchased from power stations in which E.ON UK has an interest of 50
percent or less. Own production increased by 5.3 billion kWh or 15.0 percent from 35.9 billion kWh in 2006 to
41.2 billion kWh in 2007, primarily due to improved plant availability and a reduction in wholesales gas prices
which made generation more economically attractive than buying power. Power purchased from power stations
in which E.ON UK has an interest of 50 percent or less increased by 0.5 billion kWh or 69.5 percent to 1.2
billion kWh from 0.7 billion kWh. The volume of power purchased from other suppliers decreased by 2.6 billion
kWh or 6.9 percent, reflecting the significant increase in own production. Gas sales increased by 12.4 billion
kWh or 6.4 percent from 194.0 billion kWh in 2006 to 206.4 billion kWh in 2007, with the increase reflecting
higher market sales (15.4 billion kWh) and an increase in gas used for the market unit’s own generation (10.7
billion kWh), offset in part by lower sales to retail mass market customers (8.4 billion kWh) and lower sales to
industrial and commercial customers (5.3 billion kWh). E.ON UK satisfied its increased need for gas through an
increase of 16.1 billion kWh or 10.7 percent in market purchases, while the volume of gas being sourced under
long-term gas supply contracts decreased by 3.7 billion kWh or 8.7 percent from 42.9 billion kWh in 2006 to
39.2 billion kWh in 2007.
Adjusted EBIT at the U.K. market unit decreased by €103 million or 8.3 percent from €1,239 million in
2006 to €1,136 million in 2007, reflecting a decrease at each of the Non-regulated Business and Other/
Consolidation, partially offset by higher results at the Regulated Business, as described in more detail below.
The following table sets forth the adjusted EBIT of each business unit in the U.K. market unit in each of the
last two years:
ADJUSTED EBIT OF U.K. MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
762
509
(135)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,136
851 -10.5
488
+4.3
(100) -35.0
1,239
-8.3
The Non-regulated Business contributed adjusted EBIT of €762 million in 2007. This €89 million or 10.5
percent decrease from €851 million in 2006 mainly resulted from the combination of lower retail sales volumes
due to warmer weather and lower customer numbers, as well as lower retail margins (mainly due to the price
reductions in February 2007 combined with higher energy transportation and distribution costs). These negative
factors were partially offset by the fact that the 2006 results had included high gas input costs during the first
quarter of 2006 caused by gas supply issues and cold weather, and that 2007 was marked by increased margins
from the gas power stations and improved station availability.
The Regulated Business increased its adjusted EBIT from €488 million in 2006 to €509 million in 2007.
The 4.3 percent or €21 million increase was mainly attributable to tariff changes.
The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative
due to the combination of intercompany eliminations and costs of the E.ON UK corporate center, was negative
€135 million in 2007, as compared with negative €100 million in 2006. The change was primarily attributable to
higher administrative costs, in part due to the transfer of certain activities to the corporate center from the
business units.
62
Nordic
Total sales of the Nordic market unit increased by €512 million or 18.1 percent from €2,827 million
(including €87 million in intersegment sales) to €3,339 million (including €123 million in intersegment sales) in
2007. Sales increased in both the Non-regulated Business and Regulated Business units, but were partially offset
by a greater negative effect in Other/Consolidation, as described in more detail below.
The following table sets forth the sales of each business unit in the Nordic market unit in each of the last
two years, in each case excluding electricity and natural gas taxes:
SALES OF NORDIC MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,895 2,298 +26.0
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
729
725
+0.6
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (285) (196) -45.4
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,339
2,827
+18.1
Sales in the Non-regulated Business unit, which includes power generation, retail, trading, heat and waste
and services operations, increased by €597 million or 26.0 percent from €2,298 million to €2,895 million, driven
by higher electricity volumes sold to Nord Pool and higher realized wholesale prices achieved on the hedged
portfolio. These positive effects were partially offset by a decrease in retail sales, volumes and prices, reflecting
continuing strong competition in the Nordic market.
Sales in the Regulated Business unit, which includes electricity distribution, as well as gas transmission,
distribution and storage, increased from €725 million to €729 million. This €4 million or 0.6 percent increase was
mainly attributable to higher tariffs for electricity distribution.
Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of
intrasegment sales and had a negative impact on sales of €285 million in 2007, as compared to a negative impact
of €196 million in 2006.
Total power supplied by E.ON Nordic (excluding physically settled trading activities) increased by 7.0
percent to 43.4 billion kWh in 2007, compared with 40.6 billion kWh in 2006. The increase of 2.8 billion kWh
reflected an increase in the volume of power sold to sales partners/Nord Pool by 19.7 percent from 21.1 billion
kWh in 2006 to 25.3 billion kWh in 2007, primarily reflecting higher hydroelectric production due to the better
than average hydrological balance. Sales to residential customers decreased by 0.5 billion kWh or 7.6 percent
from 6.6 billion kWh in 2006 to 6.1 billion kWh in 2007. Sales to commercial customers decreased by 6.4
percent to 12.0 billion kWh in 2007 compared with 12.8 billion kWh in 2006. These effects primarily resulted
from unseasonably warm weather in the first half of 2007. E.ON Nordic’s own production increased by 8.1
percent from 27.9 billion kWh in 2006 to 30.2 billion kWh in 2007, mainly as a result of higher hydroelectric
generation (2.9 billion kWh) due to higher water reservoir inflow in the beginning of 2007, which was partly
offset by lower nuclear generation (0.3 billion kWh). E.ON Nordic purchased 0.8 billion kWh more power from
outside sources, mainly from E.ON Sales & Trading. Purchases from jointly owned power stations decreased by
0.3 billion kWh due to lower volumes procured from Ringhals. The total volume of gas sold to third parties
decreased in 2007 to 6.9 billion kWh from 7.6 billion kWh in 2006, reflecting lower sales to business customers
due to the milder weather in the beginning of 2007.
63
Adjusted EBIT at the Nordic market unit increased by €158 million or 30.9 percent, from €512 million to
€670 million, primarily reflecting market developments at the Non-regulated Business unit, while the adjusted
EBIT at the Regulated Business unit showed a slightly positive development, as described in more detail below.
The following table sets forth the adjusted EBIT of each business unit in the Nordic market unit in each of
the last two years:
ADJUSTED EBIT OF NORDIC MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
488
220
(38)
342
200
(30)
+42.7
+10.0
-26.7
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
670
512
+30.9
Adjusted EBIT in the Non-regulated Business unit increased by €146 million from €342 million in 2006 to
€488 million in 2007. This 42.7 percent increase primarily reflected the successful hedging of the production
portfolio and the favorable hydrological balance, which led to an increase in hydroelectric production with the
business benefitting from both higher wholesale prices and an increase in volumes. These positive effects were
partly offset by an increase in the estimated costs of nuclear decommissioning in 2007.
In the Regulated Business, adjusted EBIT increased by €20 million from €200 million in 2006 to
€220 million in 2007. This 10.0 percent increase mainly resulted from the positive developments within
electricity distribution, where the Nordic market unit was able to introduce higher network tariffs mainly
reflecting the higher costs for procuring electricity to cover power losses. Despite the unseasonably warm
weather, the results of the gas distribution business remained rather stable.
U.S. Midwest
Total sales of the U.S. Midwest market unit amounted to €1,819 million in 2007, a decrease of 5.8 percent
from €1,930 million in 2006. The decrease was primarily attributable to translation effects reflecting the increase
in the value of the euro over the course of the year. In US dollars (U.S. Midwest’s operating currency), the
market unit’s sales were slightly higher, with the impact of higher retail sales volumes partially offset by that of
lower gas prices.
The following table sets forth the sales of each business unit in the U.S. Midwest market unit in each of the
last two years:
SALES OF U.S. MIDWEST MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,766 1,869
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
61
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,819
1,930
-5.5
-13.1
-5.8
Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, decreased
by €103 million to €1,766 million in 2007, from €1,869 million in 2006. The 5.5 percent decrease was
attributable to the increase in the value of the euro over the course of the year. In US dollars, sales of the
Regulated Business increased as a result of the impact of higher power retail sales volumes partially offset by
that of lower gas prices.
64
The decrease in sales at the Non-regulated Business was also primarily attributable to the strong euro, as
sales in US dollars were relatively flat.
Adjusted EBIT at the U.S. Midwest market unit decreased by 8.9 percent from €426 million in 2006 to
€388 million in 2007.
The following table sets forth the adjusted EBIT of each business unit in the U.S. Midwest market unit in
each of the last two years:
ADJUSTED EBIT OF U.S. MIDWEST MARKET UNIT
IFRS
2007
IFRS
2006
Percent
Change
(€ in millions)
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
393
-5
431
-5
-8.8
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
388
426
-8.9
Adjusted EBIT at the Regulated Business decreased by €38 million or 8.8 percent from €431 million in
2006 to €393 million in 2007. The decrease was primarily attributable to translation effects caused by the
stronger euro, although the business unit’s adjusted EBIT result in US dollars was also slightly lower than that in
the previous year. In US dollar terms, the negative impact of lower off-system electric sales volumes and lower
gas margins as a result of the timing of gas cost recoveries from customers was largely offset by higher retail
electric volumes and higher environmental cost recoveries.
Adjusted EBIT at E.ON U.S.’s Non-regulated Business was essentially flat compared to the prior year.
Corporate Center
The Corporate Center reduced Group sales by €3,785 million in 2007, compared with reducing sales by
€3,328 million in 2006. The 2007 figure also reflected €252 million in sales of newly acquired companies
(primarily OGK-4 and Airtricity). The reduction in adjusted EBIT attributable to the segment was €232 million
in 2007, compared with €403 million in 2006. The contribution of the Corporate Center to both sales and
adjusted EBIT is structurally negative due to the elimination of intersegment results and administrative costs that
are not matched by revenues.
Discontinued Operations
E.ON U.S.’s wholly-owned subsidiary, WKE operates the generating facilities of Big Rivers Electric
Corporation (“BREC”), a power generation cooperative in western Kentucky, and a coal-fired facility owned by
the city of Henderson, Kentucky, under a 25-year lease which commenced in July 1998. In March 2007, E.ON
U.S. entered into an agreement with BREC regarding an anticipated transaction to terminate the lease and
operational agreements among the parties and other related matters. During 2007, the parties entered into a
number of definitive amendments and ancillary documents regarding the termination transaction. The closing of
the lease termination transaction remains subject to a number of conditions, including review and approval of
various regulatory agencies and acquisition of certain consents by other interested parties. Subject to such
contingencies, the parties are working on completing the proposed termination transaction in the first half of
2008. WKE was classified as discontinued operations at the end of December 2005. “Income (Loss) from
discontinued operations, net” in E.ON’s Consolidated Statements of Income included a loss of €81 million for
2007, and income of €64 million for 2006 related to WKE.
In addition to the loss recorded with respect to WKE, there were gains from discontinued operations
recognized in 2007, primarily €418 million in respect of book gains on the sale of tranches of Degussa shares to
65
RAG in previous years. Although Degussa had not been considered a discontinued operation under U.S. GAAP,
it did qualify as a discontinued operation under IFRS 5, “Non-current Assets Held for Sale and Discontinued
Operations” (“IFRS 5”). The gains on these sales of Degussa shares, which were attributable to E.ON’s former
39.2 percent interest in RAG, crystallized as a result of the transfer to the “RAG-Stiftung Foundation” on
November 30, 2007 of E.ON’s shareholding in RAG and were therefore recorded” in 2007. The 2007 results
from discontinued operations also reflected €6 million in gains from the discontinued operations of the
Company’s former Viterra real estate segment, as well as a loss of €13 million from the sale of the former Veba
Oel oil segment.
Our IFRS results from discontinued operations in 2006 were also significantly affected by the classification
of Degussa as a discontinued operation, as the 2006 result reflected both €37 million in income earned by
Degussa prior to its disposal in the first quarter of 2006 (during which period we accounted for our interest in
Degussa under the equity method) and €596 million in book gains on the sale of Degussa shares to RAG in 2006.
The 2006 results also reflected €53 million in gains from the discontinued operations of Viterra and €20 million
in gains from the discontinued operations of E.ON Finland (including €9 million in income earned by E.ON
Finland prior to its disposal in June 2006).
For more information on the discontinued operations, including certain selected financial information, see
Note 4 of the Notes to Consolidated Financial Statements.
Year Ended December 31, 2006 Compared With Year Ended December 31, 2005
As noted above, the comparison of E.ON’s segment results for 2006 and 2005 presented below has been
prepared in accordance with U.S. GAAP, as previously reported in E.ON’s Annual Report on Form 20-F for the
fiscal year ended December 31, 2006 and the Notes to Consolidated Financial Statements included therein.
The following table sets forth sales and adjusted EBIT, which are presented in accordance with U.S. GAAP,
for each of E.ON’s business segments for 2006 and 2005 (in each case excluding the results of discontinued
operations):
E.ON BUSINESS SEGMENT SALES AND ADJUSTED EBIT
U.S. GAAP
2006
U.S. GAAP
2005
Adjusted
Adjusted
Sales
EBIT
Sales
(€ in millions)
Central Europe(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,380 4,168
Pan-European Gas(2)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,987 2,106
U.K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,569 1,229
619
Nordic(2)(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,204
391
U.S. Midwest(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,947
Corporate Center(2)(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,328) (416)
Core Energy Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67,759
—
Other Activities(2)(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
67,759
EBIT
24,295 3,930
17,914 1,536
10,176
963
3,213
766
2,045
365
(1,502) (399)
8,097
53
56,141
—
7,161
132
8,150
56,141
7,293
(1) Sales include energy taxes of €1,124 million in 2006 and €1,049 million in 2005.
(2) Excludes the sales and adjusted EBIT of certain activities now accounted for as discontinued operations. For
more details, see “— Discontinued Operations” for this period below and Note 4 of the Notes to
Consolidated Financial Statements.
(3) Sales include natural gas and electricity taxes of €2,060 million in 2006 and €3,110 million in 2005.
(4) Sales include electricity and natural gas taxes of €377 million in 2006 and €381 million in 2005.
66
(5) Includes primarily the parent company and effects from consolidation (including the elimination of
intersegment sales), as well as the results of its remaining telecommunications interests, as explained above.
Sales between companies in the same market unit are eliminated in calculating sales on the market unit
level.
(6) Includes adjusted EBIT of Degussa.
For a reconciliation of adjusted EBIT to net income, see the discussion under “— E.ON Group” below.
E.ON Group
E.ON’s sales in 2006 increased 24.4 percent to €64,197 million from €51,616 million in 2005 (in each case
net of electricity and natural gas taxes). As noted above, the increase was primarily attributable to higher
electricity and gas sales at the Pan-European Gas and Central Europe market units. As illustrated in the table on
the previous page, the overall increase in the Group’s sales also reflected an increase in sales at the Central
Europe, Pan-European Gas and U.K. market units, which more than offset decreases at the Nordic and U.S.
Midwest market units and the Corporate Center.
Sales of the Central Europe market unit increased 16.8 percent in 2006 to €28,380 million (including
€1,124 million of electricity taxes) from €24,295 million (including €1,049 million of electricity taxes) in 2005.
Pan-European Gas’ sales increased by 39.5 percent to €24,987 million (including €2,060 million of natural gas
and electricity taxes) in 2006 from €17,914 million (including €3,110 million of natural gas and electricity taxes)
in 2005. Sales of the U.K. market unit increased by 23.5 percent, amounting to €12,569 million in 2006 as
compared to €10,176 million in 2005. Nordic’s sales decreased by 0.3 percent to €3,204 million (including
€377 million of electricity and natural gas taxes) from €3,213 million (including €381 million of electricity and
natural gas taxes) in 2005. Sales of the U.S. Midwest market unit decreased by 4.8 percent in 2006 to
€1,947 million compared with €2,045 million in 2005. The elimination of intersegment sales at the Corporate
Center resulted in the segment reporting negative sales of €1,502 million in 2005 and negative sales of
€3,328 million in 2006. The sales of each of these segments are discussed in more detail below.
Total cost of goods sold and services provided in 2006 increased 28.8 percent or €11,701 million to
€52,304 million compared with €40,603 million in 2005, with increases at the Pan-European Gas market unit,
primarily reflecting the effect of higher gas prices, and at the Central Europe market unit. Purchases of electricity
from third parties and the purchase of significantly higher volumes of electricity generated from renewable
resources, as well as price-related increased procurement costs for gas increased costs of goods sold at the
Central Europe market unit while consolidation effects and higher costs at the U.K. market unit also contributed
to the overall increase. These effects were partially offset by lower cost of goods sold and services provided at
the Corporate Center, reflecting consolidation effects recorded at the Corporate Center level mainly as a result of
higher intergroup sales from the Pan-European Gas market unit to the U.K. market unit. Cost of goods sold as a
percentage of revenues (net of electricity and natural gas taxes) increased to 81.5 percent in 2006 from 78.7
percent in 2005, as the rate of increase of cost of goods sold and services provided was greater than that of sales.
Gross profit nonetheless increased, rising by 8.0 percent to €11,893 million in 2006 from €11,013 million in
2005.
Selling expenses increased 12.9 percent or €496 million to €4,341 million in 2006, compared with
€3,845 million in 2005. The increase reflected an overall increase of €299 million in selling expenses at the U.K.
market unit as a result of the expansion of the sales force and impairments of intangible assets due to the
rebranding of Powergen, at the Central Europe market unit, primarily attributable to the consolidation effects
involving Arena One GmbH (“Arena One”), E.ON Moldova and the Bulgarian companies Varna and Gorna and
IT-related expenses, as well as at the Pan-European market unit, primarily resulting from the first-time full-year
consolidation of E.ON Gaz România.
General and administrative expenses increased by €258 million, amounting to €1,774 million in 2006
compared with €1,516 million in 2005. The 17.0 percent increase reflected increases at the U.K. market unit,
67
primarily due to higher headcount, at the Central Europe market unit mainly resulting from consolidation effects
and an increase in purchased services from third parties, and at the Pan-European Gas market unit, also reflecting
the first full year consolidation of several new shareholdings. These effects were partially offset by lower general
and administrative expenses at the Corporate Center, reflecting consolidation effects.
Other operating income (expenses), net equaled expenses of €848 million in 2006 as compared to income of
€1,674 million in 2005. The significant change in this line item was primarily attributable to net gains/losses on
derivative instruments, which generated expenses of €2,748 million in 2006, compared to income of €931 million
in 2005, in part reflecting a decrease in the market value of derivatives at E.ON UK. In addition, net income
arising from exchange rate differences of €44 million in 2006 was lower than the corresponding net income of
€138 million in 2005. These negative effects were partially offset by higher net book gains on the disposal of
investments and increased miscellaneous other net operating income. Net book gains on the disposal of
investments increased by €545 million year on year, amounting to €579 million in 2006, compared with
€34 million in 2005. The 2006 figure primarily included the gain from the forward sale of the stake in Degussa.
Miscellaneous other operating income (expenses), net rose by €733 million, amounting to net income of
€1,297 million in 2006, as compared with net income of €564 million in 2005. For 2006, this line item also
reflects gains from the derecognition of institutional securities funds as part of the transfer to the Contractual
Trust Arrangement (“CTA”) in the amount of €159 million. In 2006, a Staff Accounting Bulletin No. 51,
Accounting for Sales of Stock of a Subsidiary, gain of €7 million related to the sale of shares of E.ON Avacon,
compared with €31 million in 2005.
Financial earnings increased by €377 million, resulting in a gain of €203 million in 2006 compared with a
loss of €174 million in 2005. The increase was primarily attributable to higher income from companies
accounted for under the equity method of €403 million and lower interest expenses of €49 million, which were
partly offset by higher depreciation on securities and share investments. For additional information, see Note 9 of
the Notes to Consolidated Financial Statements.
As a result of the factors described above, income (loss) from continuing operations before income taxes
and minority interests decreased by 28.2 percent or €2,019 million to €5,133 million in 2006, as compared with
€7,152 million in 2005.
In 2006, E.ON recorded an income tax benefit of €323 million, as compared to a tax expense of
€2,261 million in 2005. This change was primarily attributable to the change in the German corporate income tax
act with regard to corporate tax credits arising from the former corporate imputation system which led to a tax
credit of approximately €1.3 billion. In addition, deferred tax income in the amount of approximately €1.2 billion
resulted primarily from losses in the market valuation of energy derivatives. For additional information, see Note
10 of the Notes to Consolidated Financial Statements.
Income attributable to minority interests, and therefore deducted in the calculation of net income, was
€526 million in 2006, as compared to €536 million in 2005.
Results from discontinued operations increased net income by €127 million in 2006, as compared to a
contribution to net income of €3,059 million in 2005. The significant decrease reflected the very significant gains
on the disposal of Viterra and Ruhrgas Industries recorded in 2005. For details, see Note 4 of the Notes to
Consolidated Financial Statements. The Group’s net income decreased 31.7 percent, totaling €5,057 million in
2006, compared with €7,407 million in 2005. Excluding the results of discontinued operations, E.ON would have
recorded net income of €4,930 million in 2006, as compared to net income of €4,355 million in 2005.
Reconciliation of Adjusted EBIT. As noted above, E.ON uses adjusted EBIT as its segment reporting
measure in accordance with SFAS 131. On a consolidated Group basis, adjusted EBIT is considered a
68
non-GAAP measure that must be reconciled to the most directly comparable GAAP measure. A reconciliation of
Group adjusted EBIT to net income for each of 2006 and 2005 appears in the table below. The following
paragraphs discuss changes in the principal components of each of the reconciling items to income (loss) from
continuing operations before income taxes and minority interests. For additional details, see Note 33 of the Notes
to Consolidated Financial Statements.
U.S. GAAP
2006
U.S. GAAP
2005
(€ in millions)
Adjusted EBIT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted interest income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net book gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost-management and restructuring expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-operating results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,150
(1,081)
1,205
—
(3,141)
7,293
(1,027)
491
(29)
424
Income/(loss) from continuing operations before income taxes and
minority interests
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,133
323
(526)
7,152
(2,261)
(536)
Income/(loss) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cumulative effect of change in accounting principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,930
127
—
4,355
3,059
(7)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,057
7,407
On a consolidated Group basis, adjusted EBIT increased by 12.0 percent to €8,150 million in 2006, as
compared with €7,293 million in 2005.
As detailed in the table below, adjusted interest income, net, amounted to an expense of €1,081 million in
2006 as compared to an expense of €1,027 million in 2005. The interest portion of long-term provisions deducted
in the calculation was €389 million, as compared to €252 million in 2005, reflecting higher interest expenses for
nuclear waste management that were partially offset by lower interest expenses for pensions at the Central
Europe and Pan-European Gas market units, as well as the Corporate Center. Non-operating interest income, net,
amounted to income of €5 million in 2006 as compared with income of €39 million in 2005. In 2006,
non-operating interest income primarily reflected higher interest charges related to derivatives in the U.K. market
unit that were partially offset by higher interest income at the Central Europe market unit and the Corporate
Center. In 2005, non-operating interest income primarily reflected the termination of an interest provision.
U.S. GAAP
2006
U.S. GAAP
2005
(€ in millions)
Interest income and similar expenses (net) as shown in Note 9 of the Notes to
Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(+) Non-operating interest income, net(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(–) Interest portion of long-term provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(687)
(5)
389
(736)
(39)
252
Adjusted interest income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,081)
(1,027)
(1) This net figure is calculated by adding in non-operating interest expense and subtracting non-operating
interest income.
Net book gains as used in the reconciliation of adjusted EBIT more than doubled in 2006, increasing by
€714 million from €491 million in 2005 to €1,205 million. In 2006, net book gains primarily resulted from the
sale of funds invested in securities held by the Central Europe market unit and the Degussa transaction. In 2005,
net book gains primarily resulted from the sale of other securities held by the Central Europe market unit. In
addition, the Central Europe market unit realized a gain on disposal of €90 million from the transfer of shares in
TEAG. These book gains are calculated on a more inclusive basis than those discussed above in the analysis of
69
other operating income (expenses), net. These gains generally include all gains and losses from the disposal of
financial assets and results of deconsolidation, both net of expenses directly linked with the relevant disposal.
They also include book gains and losses realized by equity investees, which are included in the income statement
as a component of financial earnings.
Cost-management and restructuring expenses did not occur in 2006, compared with €29 million in 2005. In
2005, the principal expenses contributing to this item were restructuring costs of €18 million at the U.K. market
unit, mainly attributable to the integration of Midlands Electricity, and restructuring costs of €11 million at the
Central Europe market unit, primarily due to the merger of GVT and TEAG into ETE.
The amount reported as other non-operating results amounted to an expense of €3,141 million in 2006, as
compared to income of €424 million in 2005. The total of 2006 primarily reflected the fulfilment of derivative
gas procurement contracts and the marking to market of derivatives, particularly at the U.K. market unit. The
2006 result also reflected a total of €548 million in impairment charges. Following the BNetzA’s reduction of
allowable network charges, E.ON conducted impairment tests on E.ON’s network assets and shareholdings in
municipal distribution network operators. As a result, E.ON recorded impairment charges totaling €374 million
in its gas distribution businesses. Of this total, €266 million relate to the Central Europe market unit, with
€227 million relating to its own gas distribution networks and the remaining €39 million to minority
shareholdings. The remaining impairment loss of €108 million was recorded on other shareholdings at the
Pan-European Gas market unit. Impairment tests on E.ON Energie’s electricity transmission and distribution
networks did not lead to any impairment losses. Further impairments relate to CHP generation assets at the U.K.
market unit, as well as intangible and tangible assets at the Pan-European Gas, U.K. and Nordic market units.
The impact of these impairments was partially offset by effects from the first-time consolidation of VKE at the
Central Europe market unit, which add up to €83 million. In 2005, other non-operating earnings positively
reflected unrealized gains from the required marking to market of derivatives under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, primarily at the U.K. market unit. This positive effect on this
item was partially offset by the impact of an impairment charge that Degussa took as of December 31, 2005.
Degussa recorded an impairment charge of €836 million (before taxes) in its Fine Chemicals business unit due to
significant changes in market conditions. As a result of this impairment, E.ON recorded a loss of €347 million
attributable to its direct 42.9 percent shareholding in Degussa. Additional offsetting effects on other
non-operating earnings were storm-related costs for rebuilding of the distribution grid and compensating
customers of €142 million at the Nordic market unit, impairments recorded at cogeneration facilities in the U.K.
market unit, and an adjustment of deferred taxes made at an equity holding of the Corporate Center.
Central Europe
For financial reporting purposes, the Central Europe market unit comprises four business units: Central
Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central
Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear
and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the
retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power
also includes the results of E.ON Benelux, which operates power generation, district heating and gas and
electricity retail businesses in the Netherlands. The Central Europe West Gas business unit reflects the results of
the regional distribution of gas and the gas retail business in Germany. The Central Europe East business unit
primarily includes the results of the regional distribution companies in Bulgaria, the Czech Republic, Hungary,
Romania and Slovakia (with the Slovak activities being valued under the equity method given E.ON Energie’s
minority interest). Other/Consolidation primarily includes the results of E.ON Energie’s business in Italy, other
national and international shareholdings, service companies and E.ON Energie AG, as well as intrasegment
consolidation effects.
Total sales of the Central Europe market unit increased by 16.8 percent to €28,380 million (including
€1,124 million of energy taxes and €686 million in intersegment sales) in 2006, compared with a total of
70
€24,295 million (including €1,049 million of energy taxes and €248 million in intersegment sales) in 2005. The
overall increase of €4,085 million reflected higher sales at each of Central Europe’s business units, as described
in more detail below.
The following table sets forth the sales of each business unit in the Central Europe market unit in each of the
last two years, in each case excluding energy taxes:
SALES OF CENTRAL EUROPE MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Central Europe West Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central Europe West Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central Europe East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,885
4,371
3,469
531
16,945
3,463
2,618
220
+11.4
+26.2
+32.5
+141.4
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27,256
23,246
+17.3
Sales of the Central Europe West Power business unit increased by €1,940 million or 11.4 percent from
€16,945 million in 2005 to €18,885 million in 2006. The rise was primarily attributable to higher electricity
prices resulting from the global rise in raw material and energy prices as well as to an increase in the sale of
electricity produced from renewable resources, as the volume of such energy, which E.ON Energie is required to
purchase under regulatory requirements, increased in 2006. An increase in the volume of electricity sold also
contributed to the increase in sales. These positive impacts were offset in part by the negative effect of the new
regulations applicable to network charges in Germany.
Sales of the Central Europe West Gas business unit rose by 26.2 percent from €3,463 million in 2005 to
€4,371 million in 2006, with the increase of €908 million primarily reflecting higher gas prices as well as the
first-time full-year consolidation of GVT. These positive factors were offset in part by the negative effect of the
new regulation applicable to network charges in Germany.
Sales of the Central Europe East business unit increased by 32.5 percent or €851 million, from
€2,618 million in 2005 to €3,469 million in 2006, with the increase primarily due to the first-time inclusion of
full-year results from Hungarian gas companies which were consolidated as of April 2005, the Bulgarian
companies Varna and Gorna Oryahovitza (consolidated as of March 2005), and the Romanian company
E.ON Moldova (consolidated as of September 2005), as well as the first-time inclusion of two companies in the
Czech Republic and one Hungarian company in 2006. The remainder mainly resulted from higher electricity
prices in Hungary and the Czech Republic.
Sales of the Other/Consolidation business unit more than doubled, increasing by €311 million to
€531 million in 2006, with the increase being primarily attributable to the consolidation effects involving
E.ON IS UK (an IT services company), Arena One and Dalmine.
Total power procured by the Central Europe market unit (excluding physically-settled trading activities)
rose 3.6 percent to 281.2 billion kWh in 2006, compared with 271.3 billion kWh in 2005. The increase was
primarily attributable to an increase in power procured from third parties and the own production of power. E.ON
Energie’s own production of power increased by 1.7 percent from 129.1 billion kWh in 2005 to 131.3 billion
kWh in 2006. E.ON Energie produced approximately 47 percent of its power requirements in 2006, compared
with approximately 48 percent in 2005. Compared with 2005, electricity purchased from jointly operated power
stations increased by 2.2 percent from 12.0 billion kWh to 12.3 billion kWh. Purchases of electricity from third
71
parties increased by 5.7 percent, from 130.2 billion kWh in 2005 to 137.6 billion kWh in 2006, largely due to the
first-time inclusion of a full year of results from the electricity distribution companies in Bulgaria and Romania
(approximately 3.6 TWh), as well as the purchase of significantly higher volumes of electricity generated from
renewable resources pursuant to Germany’s Renewable Energy Law (approximately 3.4 TWh).
In 2006, the Central Europe market unit contributed adjusted EBIT of €4,168 million, a 6.1 percent increase
from a total of €3,930 million in 2005. The following table sets forth the adjusted EBIT of each business unit in
the Central Europe market unit in each of the last two years:
ADJUSTED EBIT OF CENTRAL EUROPE MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Central Europe West Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central Europe West Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Central Europe East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,550
272
269
77
3,389
307
237
(3)
+4.8
-11.4
+13.5
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,168
3,930
+6.1
Adjusted EBIT at the Central Europe West Power business unit increased by €161 million from
€3,389 million in 2005 to €3,550 million in 2006. This 4.8 percent increase was primarily attributable to higher
wholesale electricity prices which could be passed on to customers, higher earnings from sale of shareholdings
and lower expenses for nuclear fuel management, primarily due to the absence of expenditures for nuclear
operations taken in the prior year. The positive effects of these factors on the business unit’s adjusted EBIT were
partly offset by negative effects from the new regulation of network charges in Germany. Higher fuel costs,
primarily reflecting significantly higher prices for hard coal and higher procurement costs also reduced overall
adjusted EBIT. Adjusted EBIT was also negatively affected by increased charges relating to earlier periods.
Adjusted EBIT of the Central Europe West Gas business unit decreased by 11.4 percent to €272 million in
2006, compared with €307 million in 2005. The lower result was a consequence of the impact of new regulation
of network charges in Germany. The negative impact of the regulation could only partially be offset by the effect
of the first-time inclusion of a full year of results from GVT.
The Central Europe East business unit contributed adjusted EBIT of €269 million in 2006, a 13.5 percent
increase from €237 million in 2005, largely reflecting the inclusion of a full year of earnings from the regional
distributors in Bulgaria, Hungary, and Romania acquired in 2005, as well as a positive contribution from the two
newly acquired companies in the Czech Republic. Higher procurement costs and weather related lower sales
volumes in the Hungarian gas business had a negative effect on adjusted EBIT.
Central Europe’s Other/Consolidation business unit recorded an adjusted EBIT of €77 million in 2006
compared with an adjusted EBIT of negative €3 million in 2005. This positive change primarily resulted from
higher income from realized hedging transactions and increased earnings from shareholdings, while intrasegment
consolidation effects, re-evaluation of stock options owing to an increase in E.ON’s stock price, reduction of the
interest rate for pensions and changes in the basis of consolidation had a negative effect.
Pan-European Gas
For financial reporting purposes, the Pan-European Gas market unit is divided into three business units:
Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects
the results of the supply, transmission system, storage and sales businesses, with the midstream operations
72
essentially including all of the supply and sales business other than exploration and production activities. The
Downstream Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes
consolidation effects.
The results of the Downstream Shareholdings business unit have included the results of E.ON Gaz România
since July 1, 2005 and the results of MOL’s gas trading and storage units (now E.ON Földgaz Trade and E.ON
Földgaz Storage) since April 1, 2006. The results of the Up-/Midstream business unit include those of Caledonia
(now E.ON Ruhrgas North Sea), which has been consolidated since November 1, 2005.
Total sales of the Pan-European Gas market unit increased by 39.5 percent to €24,987 million (including
€2,060 million of natural gas and electricity taxes and €2,393 million in intersegment sales) in 2006, compared
with a total of €17,914 million (including €3,110 million of natural gas and electricity taxes and €1,079 million
in intersegment sales) in 2005. The increase was mainly attributable to higher average sales prices, higher sales
volumes outside of Germany and consolidation effects. The decline in natural gas and electricity taxes is related
to the new German energy taxation law which came into effect in August 2006 and provides that the tax is paid
by distributors of gas rather than the importer.
The following table sets forth the sales of each business unit in the Pan-European Gas market unit
(excluding natural gas and electricity taxes) in each of the last two years:
SALES OF PAN-EUROPEAN GAS MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Up-/Midstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Downstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,868
4,773
(715)
13,380
1,848
(424)
+41.0
+158.3
-68.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22,926
14,804
+54.9
Sales in the Up-/Midstream business unit increased in 2006 by €5,488 million or 41.0 percent from
€13,380 million to €18,868 million, with the increase being primarily attributable to the increase in average sales
prices and higher sales volumes (from 690.2 billion kWh to 709.7 billion kWh) in the midstream activities. In the
upstream business, sales increased in particular as a result of the first time full year inclusion of E.ON Ruhrgas
North Sea, which was acquired in November 2005, and the increase of sales prices at E.ON Ruhrgas Norge and
E.ON Ruhrgas UK.
In the Downstream Shareholdings business unit, sales more than doubled, increasing by €2,925 million to
€4,773 million in 2006 compared with €1,848 million in 2005. The main reason for the change was an increase in
sales in ERI’s downstream operations, particularly the impact of the first-time consolidation of E.ON Földgaz
Trade and E.ON Földgaz Storage following their consolidation in April and the first time inclusion of a full year
of results from E.ON Gaz România. The overall figure also reflected an increase in sales of €125 million at
Thüga’s downstream operations, mainly reflecting a rise in gas sales as a consequence of higher average gas
prices, the impact of which was partially offset by the impact of regulatory changes in Italy and Germany.
The total volume of gas sold by E.ON Ruhrgas’ midstream operations increased by 2.8 percent to
709.7 billion kWh in 2006 from 690.2 billion kWh in 2005. Sales to domestic distributors decreased by 1.5
percent from 323.7 billion kWh to 318.7 billion kWh. Sales to domestic municipal utilities increased by 1.4
percent from 160.9 billion kWh to 163.1 billion kWh. E.ON Ruhrgas sold 67.6 billion kWh of gas to domestic
industrial customers, a decrease of 4.0 percent from 70.4 billion kWh in 2005. Exports reached 160.3 billion
kWh in 2006, a 18.6 percent increase from 135.2 billion kWh in 2005, primarily resulting from increased trading
activities in the U.K. E.ON Ruhrgas purchased approximately 84.4 percent of its gas supplies from outside
73
Germany and approximately 15.6 percent from German producers in 2006, compared with 84.5 percent and 15.5
percent, respectively, in 2005. In the Downstream Shareholdings business unit, total gas sales volumes more than
doubled, rising from 69.0 billion kWh in 2005 to 175.1 billion kWh in 2006. Thüga increased its sales volumes
by 2.7 percent to 23.1 billion kWh from 22.5 billion kWh. Sales volumes at ERI more than tripled to
152.0 billion kWh from 46.5 billion kWh in 2005, largely due to the first time inclusion of a full year of results
from E.ON Gaz România and the inclusion of E.ON Földgaz since April 2006.
Adjusted EBIT of the Pan-European Gas market unit increased by 37.1 percent to €2,106 million in 2006
from €1,536 million in 2005. The rise in adjusted EBIT reflected positive results in the Up-/Midstream business
unit, which were only partly offset by lower results in the Downstream Shareholdings business unit, as described
in more detail below.
The following table sets forth the adjusted EBIT of each business unit in the Pan-European Gas market unit
in each of the last two years:
ADJUSTED EBIT OF PAN-EUROPEAN GAS MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Up-/Midstream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Downstream Shareholdings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,684
431
(9)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,106
988
551
(3)
1,536
+70.4
-21.8
-200.0
+37.1
Adjusted EBIT in the Up-/Midstream business unit increased by €696 million or 70.4 percent from
€988 million in 2005 to €1,684 million in 2006. The €25 million increase in adjusted EBIT at the upstream
activities primarily reflected continued high oil and natural gas prices. These higher oil and gas prices led to
improvements in adjusted EBIT of E.ON Ruhrgas UK and E.ON Ruhrgas Norge, whereas the positive effect of
the first time inclusion of a full year of results from E.ON Ruhrgas North Sea was more than offset by the impact
of reductions in expected production from certain gas fields. Adjusted EBIT in the midstream activities increased
by €671 million, primarily due to the positive impact of the time lag effect in adjusting purchase prices, which
had a negative impact last year. The settlement of proprietary trading transactions at maturity also contributed to
the increase. The positive impact of these factors on the adjusted EBIT of the midstream activities was partially
offset by a lower contribution from commodity derivatives as well as the combination of higher transportation
fees and the fact that the 2005 result had benefited from the recalculation of fees for the usage of gas pipes.
In the Downstream Shareholdings business unit, adjusted EBIT decreased by €120 million or 21.8 percent to
€431 million in 2006 from €551 million in 2005. The decrease in adjusted EBIT was primarily attributable to the
new regulation of network charges in Germany which led to impairments of certain Thüga shareholdings totaling
€188 million, as well as to the establishment of provisions for the obligation to refund to network customers the
difference between network charges originally assessed and those finally approved. Furthermore, E.ON Földgaz
Trade, which operates in Hungary’s regulated gas market, negatively impacted the Downstream Shareholding’s
adjusted EBIT due to a delay in the approval of tariffs allowing it to recoup higher procurement costs. These
negative effects were partially offset by higher net earnings at other equity investments, the inclusion of the
results of E.ON Gaz România for the entire year of 2006 as compared to only six months in 2005 and the firsttime inclusion of the results of E.ON Földgaz Storage.
U.K.
From the beginning of 2006, E.ON UK re-allocated costs relating to the business services unit (facilities, IT
and other shared services), which had been recorded under Other/Consolidation, to the Non-regulated Business to
74
reflect this unit’s use of such services. The Regulated Business already incurred a charge for these services. The
2005 results included below have been recalculated on the same basis to facilitate a comparison. In addition, the
Energy Services business, most of which was included in the Regulated Business in prior years, has been
included in the Non-regulated Business since the beginning of 2006, reflecting the unit’s revised strategic
objectives.
Total sales of the U.K. market unit in 2006 increased by 23.5 percent to €12,569 million (including
€163 million in intersegment sales) from €10,176 million (including €74 million in intersegment sales) in 2005,
primarily as a result of increased sales in the Non-regulated Business, as explained in more detail below.
The following table sets forth the sales of each business unit in the U.K. market unit in each of the last two
years:
SALES OF U.K. MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,081
856
(368)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,569
9,553
813
(190)
10,176
+26.5
+5.3
-93.7
+23.5
Sales in the Non-regulated Business, which is primarily comprised of the energy wholesale (generation and
trading), retail and the energy services businesses in the U.K., increased by €2,528 million from €9,553 million
in 2005 to €12,081 million in 2006. This 26.5 percent increase was primarily attributable to higher retail prices
driven by higher energy prices, the effects of which were partially offset by lower volumes resulting from
warmer weather and changes in consumer behavior and higher sales in the wholesale market reflecting both
higher energy prices and increased market sales volumes.
Sales in the Regulated Business, which is primarily comprised of the U.K. distribution operations, increased
to €856 million in 2006 from €813 million in 2005. The sales increase of €43 million, or 5.3 percent, was
principally attributable to tariff changes.
Sales attributed to the Other/Consolidation business unit consist almost entirely of the elimination of
intrasegment sales and had a negative impact on sales of €368 million in 2006, as compared to a negative impact
of €190 million in 2005.
The volume of electricity sold by the U.K. market unit decreased by 1.2 billion kWh or 1.6 percent to
73.8 billion kWh, as compared with 75.0 billion kWh in 2005. Market sales associated with trading operations
increased by 2.1 billion kWh or 13.8 percent to 17.5 billion kWh and mass market sales increased by 0.6 billion
kWh or 1.6 percent to 37.9 billion kWh, while those to industrial and commercial customers decreased by
3.9 billion kWh or 17.6 percent to 18.4 billion kWh, reflecting the market unit’s focus in this segment on
securing margins rather than volume. The decrease in sales was reflected in the volume of own production and
power purchased from outside sources. Own production decreased by 1.4 billion kWh or 3.7 percent from
37.3 billion kWh in 2005 to 35.9 billion kWh in 2006, primarily due to the unplanned outage at Ratcliffe power
station. Power purchased from other suppliers decreased by 1.1 billion kWh or 2.8 percent to 38.1 billion kWh
from 39.2 billion kWh, reflecting lower sales to industrial and commercial customers. The volume of power
purchased from power stations in which E.ON UK has an interest of 50 percent or less increased by 0.1 billion
kWh or 16.6 percent. Gas sales increased by 11.5 billion kWh or 6.3 percent from 182.5 billion kWh in 2005 to
194.0 billion kWh in 2006, with the increase reflecting higher market sales (20.9 billion kWh), offset in part by
lower sales to industrial and commercial customers (3.9 billion kWh), lower sales to retail mass market
customers (3.8 billion kWh), as well as a decrease in gas used for the market unit’s own generation
75
(1.7 billion kWh). E.ON UK satisfied its increased need for gas through an increase of 17.0 billion kWh or
12.7 percent in market purchases, while the volume of gas being sourced under long-term gas supply contracts
decreased by 5.5 billion kWh or 11.4 percent from 48.4 billion kWh in 2005 to 42.9 billion kWh in 2006.
Adjusted EBIT at the U.K. market unit increased by €266 million or 27.6 percent from €963 million in 2005
to €1,229 million in 2006, reflecting an increase at each of the Non-regulated Business and the Regulated
Business, partially offset by lower results at Other/Consolidation, as described in more detail below.
The following table sets forth the adjusted EBIT of each business unit in the U.K. market unit in each of the
last two years:
ADJUSTED EBIT OF U.K. MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
869
488
(128)
1,229
540
452
(29)
+60.9
+8.0
-341.4
963
+27.6
The Non-regulated Business contributed adjusted EBIT of €869 million in 2006. This €329 million or 60.9
percent increase from €540 million in 2005 mainly resulted from the combination of higher margins at the coal
fired power stations, higher retail prices and profit and cost saving initiatives implemented after the disappointing
results of the first quarter, which were partially offset by higher commodity costs in 2006 as well as the fact that
the 2005 results reflected a benefit relating to the integration of previously outsourced customer service activities.
The Regulated Business increased its adjusted EBIT from €452 million in 2005 to €488 million in 2006.
The 8.0 percent or €36 million increase was almost entirely attributable to tariff changes and cost improvements.
The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative
due to the combination of intercompany eliminations and costs of the E.ON UK corporate center, was negative
€128 million in 2006, as compared with negative €29 million in 2005. The change was primarily attributable to
foreign exchange hedging impacts, higher pension costs and central costs to support a growing business.
Nordic
Total sales of the Nordic market unit remained essentially stable in 2006, amounting to €3,204 million
(including €377 million of electricity and natural gas taxes and €86 million in intersegment sales) compared to
€3,213 million (including €381 million of electricity and natural gas taxes and €102 million in intersegment
sales) in 2005. Sales decreased in both the Non-regulated Business and the Regulated Business units. This was
offset by a positive development in Other/Consolidation, as described in more detail below.
As noted above, the Nordic market unit adopted a new business unit structure following the disposition of
E.ON Finland, with its operating units split between the Non-regulated Business and the Regulated Business. In
addition, the gas business has been undergoing structural changes since 2005. Following the deregulation of the
Swedish gas market, the gas trading and retail businesses were moved from the distribution company to the
respective trading and retail companies in the E.ON Sverige group. Since January 2006, the trading and retail
businesses are included in the business unit “Non-regulated Business”, whereas the gas distribution business
remains in the business unit “Regulated.” This re-allocation affects the year-on-year comparison of sales and
adjusted EBIT for both the Regulated Business unit and the Non-regulated Business unit.
76
The following table sets forth the sales of each business unit in the Nordic market unit in each of the last
two years, in each case excluding electricity and natural gas taxes:
SALES OF NORDIC MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,119
725
(17)
2,247
850
(266)
-5.7
-14.7
+93.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,827
2,831
—
Sales in the Non-regulated Business unit, which includes power generation, retail, trading, heat and services
operations decreased by €128 million or 5.7 percent from €2,247 million to €2,119 million, driven by lower
volumes in hydro and nuclear power generation following significantly lower hydro reservoir inflow in the first
three quarters of 2006 and the temporary shutdown of several nuclear plants.
Sales in the Regulated Business unit, which includes electricity distribution, as well as gas transmission,
distribution and storage, decreased from €850 million to €725 million. This €125 million or 14.7 percent
decrease was mainly attributable to the reorganization of gas trading activities from the Regulated Business unit
to the Non-regulated Business unit in 2006 noted above.
Sales attributed to the Other/Consolidation business unit consists almost entirely of the elimination of
intrasegment sales and had a negative impact on sales of €17 million in 2006, as compared to a negative impact
of €266 million in 2005. The significant decrease of intersegment sales in 2006 compared to 2005 primarily
reflects the impact of the re-allocation of the gas trading and retail businesses to the Non-regulated Business and
the fact that the 2005 results had included a higher volume of maintenance services provided to the
Non-regulated Business following the severe storm in January 2005. Notably, the hydroelectric assets sold to
Statkraft in October 2005 were included in the Other/Consolidation business unit and contributed to the results
until their disposal. This partly offset the negative impact on sales coming from the Other/Consolidation business
unit in 2005.
Total power supplied by E.ON Nordic (excluding physically settled trading activities) decreased by
11.5 percent to 40.6 billion kWh in 2006, compared with 45.9 billion kWh in 2005. The decrease of 5.3 billion
kWh reflected a reduction in the volume of power sold to sales partners/Nord Pool by 19.6 percent from
26.2 billion kWh in 2005 to 21.1 billion kWh in 2006, primarily reflecting lower hydroelectric production due to
the prevailing hydroelectric situation, the sale of hydroelectric assets to Statkraft in late 2005, and the unplanned
outages of nuclear reactors. Sales to residential customers decreased by 0.4 billion kWh or 5.7 percent from
7.0 billion kWh in 2005 to 6.6 billion kWh in 2006, as a result of unseasonably warm weather in the fourth
quarter 2006. Sales to commercial customers increased by 1.6 percent to 12.7 billion kWh in 2006 compared
with 12.6 billion kWh in 2005, reflecting the impact of new customers. E.ON Nordic’s own production decreased
by 16.2 percent from 33.3 billion kWh in 2005 to 27.9 billion kWh in 2006, mainly resulting from lower
hydroelectric generation (5.1 billion kWh) and lower nuclear generation (0.8 billion kWh). As a result of lower
production volumes from its own sources, E.ON Nordic purchased slightly more power from outside sources
(0.5 billion kWh). Purchases from jointly owned power stations remained stable with 10.2 billion kWh. The total
volume of gas sold to third parties decreased in 2006 to 5.8 billion kWh from 6.9 billion kWh in 2005, mainly
resulting from lower sales to industrial and distribution customers (1.7 billion kWh).
Adjusted EBIT at the Nordic market unit decreased by €147 million or 19.2 percent, from €766 million to
€619 million, primarily reflecting lower generation volumes, the disposition of hydroelectric assets to Statkraft,
and increased taxation on hydroelectric assets and nuclear generation, as described in more detail below.
77
The following table sets forth the adjusted EBIT of each business unit in the Nordic market unit in each of
the last two years:
ADJUSTED EBIT OF NORDIC MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other/Consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
448
200
(29)
541
244
(19)
-17.2
-18.0
-52.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
619
766
-19.2
Adjusted EBIT in the Non-regulated Business unit decreased by €93 million from €541 million in 2005 to
€448 million in 2006. This 17.2 percent decrease primarily reflected increased taxation on hydroelectric assets
and nuclear generation, and lower hydro and nuclear generation volumes resulting from the strained hydrological
situation during summer and autumn and the unplanned nuclear outages. These effects were partially offset by a
positive effect from rising spot electricity prices and successful hedging activities, which enabled Nordic to
secure higher average sales prices for its production portfolio.
In the Regulated Business, adjusted EBIT decreased by €44 million from €244 million in 2005 to
€200 million in 2006. This 18.0 percent decrease mainly resulted from the re-allocation of gas trading activities
from the Regulated Business unit to the Non-regulated Business unit, and increased costs for power losses in the
transmission and distribution grid driven by higher electricity prices during 2006.
The contribution of the Other/Consolidation business unit to adjusted EBIT, which is structurally negative
due to the combination of intercompany eliminations and costs of the E.ON Nordic corporate center, was
negative €19 million in 2005 and negative €29 million in 2006. The change primarily reflects the loss of the
contribution from hydroelectric assets sold to Statkraft in 2005.
U.S. Midwest
Total sales of the U.S. Midwest market unit amounted to €1,947 million in 2006, a decrease of 4.8 percent
from €2,045 million in 2005. The decrease was primarily due to lower off-system sales volumes and milder
weather in 2006, the impact of which was partially offset by higher recoveries of coal price increases from retail
customers and recoveries of environmental capital spending.
The following table sets forth the sales of each business unit in the U.S. Midwest market unit in each of the
last two years:
SALES OF U.S. MIDWEST MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,887
60
1,965
80
-4.0
-25.0
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,947
2,045
-4.8
Sales of the Regulated Business, which is comprised of the utility operations of LG&E and KU, decreased by
€78 million to €1,887 million in 2006, from €1,965 million in 2005. The 4.0 percent decrease was primarily
attributable to lower revenues from off-system electric sales, as well as lower retail electric and gas volumes resulting
from milder weather (and associated lower passed-through costs of gas supply), and lower off-system gas sales
volumes. These negative effects were partially offset by the higher recovery from customers of passed-through costs
for fuel (primarily coal) used for generation, and higher recoveries on environmental capital spending.
78
Sales of the Non-regulated Business, which primarily consists of ECC and its subsidiaries, decreased by
€20 million or 25.0 percent from €80 million in 2005 to €60 million in 2006, with the decrease being primarily
attributable to new regulations that allowed Argentine industrial customers to purchase gas directly from
producers.
Adjusted EBIT at the U.S. Midwest market unit increased by 7.1 percent from €365 million in 2005 to
€391 million in 2006.
The following table sets forth the adjusted EBIT of each business unit in the U.S. Midwest market unit in
each of the last two years:
ADJUSTED EBIT OF U.S. MIDWEST MARKET UNIT
U.S. GAAP
2006
U.S. GAAP
2005
Percent
Change
(€ in millions)
Regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-regulated Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
387
4
351
14
+10.3
-71.4
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
391
365
+7.1
Adjusted EBIT at the Regulated Business increased by €36 million or 10.3 percent from €351 million in
2005 to €387 million in 2006. The increase was primarily attributable to net cost savings resulting from the exit
from MISO in the third quarter of 2006 and lower amortization expenses reflecting the completion of certain
restructuring activities, as well as recoveries on environmental capital spending and higher prices realized on
off-system electric sales. The impact of these positive effects was partially offset by lower retail electric and gas
volumes due to significantly milder weather in 2006 and higher labor costs.
Adjusted EBIT at E.ON U.S.’s Non-regulated Business decreased from €14 million in 2005 to €4 million in
2006. This 71.4 percent or €10 million decrease primarily reflected the loss of earnings from LPI following its
sale in 2006, partially offset by the improved performance of the Argentine operations.
Corporate Center
The Corporate Center reduced Group sales by €3,328 million in 2006, compared with reducing sales by
€1,502 million in 2005. The reduction in adjusted EBIT attributable to the segment was €416 million in 2006,
compared with €399 million in 2005. The contribution of the Corporate Center to both sales and adjusted EBIT is
structurally negative due to the elimination of intersegment results and administrative costs that are not matched
by revenues.
Discontinued Operations
In 2001, the Company discontinued the operations of its former aluminum segment. This former segment
was accounted for as discontinued operations in accordance with U.S. GAAP. In 2005, E.ON discontinued and
either disposed of certain operations or classified certain businesses as held for sale in the Pan-European Gas and
U.S. Midwest market units, as well as Viterra in the Other Activities business segment. E.ON therefore also
considers these businesses to be discontinued operations. Finally, in 2006, the Nordic market unit disposed of its
entire stake in E.ON Finland. Under U.S. GAAP, results of all such discontinued operations must be shown
separately, net of taxes and minority interests, under “Income (Loss) from discontinued operations, net” in
E.ON’s Consolidated Statements of Income. For details, see Note 4 of the Notes to Consolidated Financial
Statements.
In March 2002, E.ON sold VAW (then one of Europe’s major aluminum companies) to the Norwegian
company Norsk Hydro ASA for the aggregate price of €3.1 billion, including financial liabilities and pension
provisions totaling €1.2 billion. E.ON realized a gain on disposal of €893 million, which does not include the
79
reversal of VAW’s negative goodwill of €191 million, as this amount was required to be recognized as income
due to a change in accounting principles upon adoption of SFAS No. 142, Goodwill and Other Intangible Assets,
on January 1, 2002. In 2005, E.ON recognized a gain of €10 million before income taxes resulting from the
release of a related provision. This effect was recorded under “Income (Loss) from discontinued operations, net”
in the Consolidated Statements of Income.
In May 2005, E.ON sold Viterra to Deutsche Annington GmbH. The total consideration received for 100.0
percent of Viterra’s equity was €4 billion. The company was classified as a discontinued operation in May 2005
and deconsolidated as of July 31, 2005. E.ON recorded a gain of just over €2.4 billion on the sale, which closed
in August. The portion of Viterra’s 2005 and 2004 results included in “Income (Loss) from discontinued
operations, net” in E.ON’s Consolidated Statements of Income amounted to €2,558 million and €294 million,
respectively. In 2005, Viterra had revenues of €453 million. In 2006, E.ON recognized gains of €52 million
resulting from adjustments of the purchase price and the partial release of a related provision.
In June 2005, E.ON Ruhrgas signed an agreement for the sale of Ruhrgas Industries to CVC Capital
Partners, a European private equity firm. The purchase price for 100.0 percent of Ruhrgas Industries was €1.2
billion, with the purchasers’ assumption of Ruhrgas Industries’ debt and provisions bringing the total value of the
transaction to €1.5 billion. The transaction received antitrust approvals in July and September and was closed on
September 12, 2005. The company was classified as a discontinued operation in June 2005, and deconsolidated
as of August 31, 2005. The portion of Ruhrgas Industries’ 2005 and 2004 results included in “Income (Loss)
from discontinued operations, net” in E.ON’s Consolidated Statements of Income amounted to €628 million and
€29 million, respectively. In 2005, Ruhrgas Industries had revenues of €847 million. E.ON recorded a gain on the
disposal of €0.6 billion.
In February 2006, E.ON Nordic and Fortum signed an agreement providing for Fortum’s acquisition of
E.ON Nordic’s entire 65.6 percent stake in E.ON Finland for a total consideration of €393 million. The
transaction closed in June 2006, and E.ON Nordic recorded a gain of €11 million on the sale. E.ON Finland was
accounted for as discontinued operations from January 16, 2006 (the date on which a legal impediment to E.ON
Nordic’s sale of the stake was removed) through the date of its disposal. The portion of E.ON Finland’s 2006 and
2005 results included in “Income (Loss) from discontinued operations, net” in E.ON’s Consolidated Statements
of Income amounted to €11 million and €24 million, respectively. In 2006, E.ON Finland had revenues of €131
million.
The U.S. GAAP consolidated financial statements and related notes thereto for the years ending
December 31, 2006, 2005 and 2004, were reclassified to reflect the discontinued operations treatment outlined
above. Operating results for discontinued operations through the disposal date, as well as the gains or losses from
ultimate sale, are reported in “Income (Loss) from discontinued operations, net” in the Consolidated Statements
of Income. The assets and liabilities of the business units which were classified as held for sale as of
December 31, 2006 and 2005, but which were not yet sold as of the respective balance sheet date, are reported as
“Assets of disposal groups” and “Liabilities of disposal groups,” respectively, in the respective Consolidated
Balance Sheets. Cash flows from discontinued operations have been presented separately from the Consolidated
Statements of Cash Flows for all periods presented.
Other Activities
For the period between Degussa’s deconsolidation and E.ON’s disposal of its interest in July 2006, E.ON’s
proportionate share of Degussa’s after-tax earnings continued to be presented outside of the core energy business
as part of E.ON’s “Other Activities,” which is reported as a separate segment. Degussa contributed €53 million to
adjusted EBIT in 2006, compared with €132 million in 2005. For information regarding the disposal of E.ON’s
remaining interest in Degussa, see “Business — Overview.”
Liquidity And Capital Resources
The major source of liquidity for E.ON in 2007 was again cash provided by operating activities. Cash
provided by operating activities amounted to €8,726 million in 2007 and €7,161 million in 2006. The 21.9
80
percent increase in cash provided by operating activities in 2007 was primarily attributable to improvements at
the Pan-European Gas, U.K. and Nordic market units. A key factor at the Pan-European Gas market unit was the
inclusion of a full year of results from the E.ON Földgaz companies, which were not consolidated until April
2006, and negatively impacted cash provided by operating activities in 2006. In addition, there were positive cash
effects arising from the usage of stored volumes in 2007. The improvement at the U.K. market unit was mainly
due to improved operational performance from the retail business, and an improvement in the management of
accounts receivable, as well as strong profits from the fourth quarter of 2006 collected as cash in 2007. At the
Nordic market unit, positive effects from higher power sales volumes, higher average price levels achieved
through hedging activities, and improvements in working capital were offset by cash-effective payments for the
January storm and higher income tax payments. Improvements at these market units were partially offset by
lower levels of cash from operations at the Corporate Center, primarily due to lower external tax refunds, and at
the U.S. Midwest market unit, mainly due to increased pension contributions made in 2007 and the strong
performance of the euro.
Proceeds from divestments, which are reported in the Consolidated Statements of Cash Flows as the sum of
payments received on the disposition of equity investments and intangible and fixed assets, amounted to
€1,431 million in 2007 and €3,877 million in 2006. In 2007, divestment proceeds were primarily attributable to
the sale of E.ON’s interest in ONE (€569 million), the sale of various interests in Saxony held by the
Pan-European Gas market unit to EnBW (€181 million) and an additional payment relating to the sale of equity
interests in EWE Aktiengesellschaft (€100 million) at the Central Europe market unit.
E.ON’s major liquidity requirement in recent years has been capital expenditures for purchases of financial
assets (including equity investments) and other fixed assets. Capital expenditures in 2007 and 2006 amounted to
€11,306 million and €5,037 million, respectively, and are reported in the Consolidated Statements of Cash Flows
as the sum of purchases of equity investments, and intangible and fixed assets. In both 2007 and 2006,
investments in fixed and intangible assets exceeded purchases of equity investments. For additional information
on these acquisitions, see “— Acquisitions and Dispositions” above and Note 4 of the Notes to Consolidated
Financial Statements. As described in more detail in the segment analysis below, the most significant capital
expenditures in 2007 were for the acquisition of E2-I, Airtricity and OGK-4 at the Corporate Center, and interests
in the Skarv and Idun natural gas fields at the Pan-European Gas market unit. Funds used for the abovementioned acquisitions were the primary reasons for the change in E.ON’s cash flow used for investing activities,
which totaled €4,457 million cash used in 2006 and €8,789 million cash used in 2007.
Cash provided by financing activities totaled €1,808 million, as compared to €5,860 million in cash used by
such activities in 2006, primarily reflecting an increase in borrowing, partially offset by cash used for the
purchase of own shares as part of the share buy-back program. For further information, see Note 19 of the Notes
to Consolidated Financial Statements.
As of December 31, 2007, the Group had cash and cash equivalents from continuing operations of
€2,887 million, as compared with €1,154 million at December 31, 2006.
81
The following table shows the cash provided by operating activities and used for capital expenditures for
each of the Group’s segments in 2007 and 2006 (in each case excluding the cash flows of discontinued
operations, see “ — Results of Operations” above).
E.ON BUSINESS SEGMENT CASH FLOW AND CAPITAL EXPENDITURES(1)(2)
2007
Cash from
Operations
2006
Capital
Expenditures
Cash from
Operations
Capital
Expenditures
(€ in millions)
Central Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pan-European Gas(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nordic(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Midwest(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate Center(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,811
3,041
1,615
914
216
(871)
2,581
2,424
1,364
914
690
3,333
3,802
604
724
715
381
935
2,279
882
863
642
398
(27)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,726
11,306
7,161
5,037
(1) For a detailed description of capital expenditures by purchases of financial assets and purchases of other
fixed assets, see Note 29 of the Notes to Consolidated Financial Statements.
(2) Excludes investments in other financial assets.
(3) Excludes the cash from operations and capital expenditures of certain activities accounted for as
discontinued operations. For more details, see “— Results of Operations — Discontinued Operations” for
each period and Note 4 of the Notes to Consolidated Financial Statements.
Capital Expenditures
The Central Europe market unit continued to account for the largest portion of the Group’s capital
expenditures over the most recent two-year period, primarily as a result of additions to property, plant and
equipment and intangible assets, as well as acquisitions of equity interests in energy companies and other share
investments. In 2007, capital expenditures at the Central Europe market unit rose by 13.3 percent to
€2,581 million, compared to €2,279 million in the prior year. Investments in property, plant and equipment and
intangible assets totaled €2,390 million, compared with €1,883 million in the prior year. The additional
investments went towards power generation projects currently under way in Germany and Italy, as well as
offshore investments in Germany. Share investments of €191 million were €205 million below the prior-year
level. In 2006, investments in property, plant and equipment and intangible assets amounted to €1,883 million,
mainly consisting of assets used in conventional and renewable power generation, waste incineration and the
distribution of energy. The Central Europe market unit invested €396 million in share investments, of which
€100 million were due to the acquisitions of JCP and Teplárna Otrokovice in the Czech Republic and Dalmine in
Italy. Furthermore, investments in companies which are engaged in conventional generation and waste
incineration plants amounted to €134 million.
The Pan-European Gas market unit’s level of capital expenditures almost tripled, increasing from
€882 million in 2006 to €2,424 million in 2007. In 2007, the Pan-European Gas market unit invested
€1,381 million in property, plant, and equipment and intangible assets with the largest single items being the
acquisition of interests in Skarv and Idun gas fields in the northern Norwegian Sea (€641 million) and the
construction of the new gas pipelines Lauterbach-Scheidt and Rothenstadt-Schwandorf (€160 million). Share
investments of €1,043 million primarily reflected the acquisition of Contigas Deutsche Energie-AG from the
Central Europe market unit. A corresponding offsetting item was recorded in the Corporate Center reporting
segment. Furthermore, an increase in the stake held in Rohöl-Aufsuchungs AG led to an expenditure of €86
million. In 2006, the Pan-European Gas market unit invested €505 million in share investments, with the largest
single investment being the €400 million spent acquiring the MOL activities. Investments in property, plant and
equipment and intangible assets, mainly in the transmission system and the upstream activities, amounted to
€377 million.
82
Investments in the U.K. market unit increased by 58.1 percent to €1,364 million in 2007, compared with
€863 million in 2006. In 2007, the U.K. market unit spent €1,364 million on property, plant and equipment
primarily for the development of new generation capacity, power station overhauls, gas storage and our
distribution network, while there were no share investments during the year. In 2006, the U.K. market unit
invested €860 million in property, plant and equipment and intangible assets, primarily for generation assets,
including the development of new renewables capacity at Lockerbie, Scotland, and in existing conventional
power plants, as well as investments in the regulated distribution business. Investments in share investments
amounted to €3 million.
In 2007, investments at the Nordic market unit amounted to €914 million, an increase of 42.4 percent
compared with 2006. E.ON Nordic invested €892 million in property, plant, and equipment and intangible assets,
primarily to maintain and expand existing production plants and to upgrade and extend the distribution network.
Share investments amounted to €22 million with the largest single investment being the acquisition of a further
interest in Elverket Vallentuna AB. The Nordic market unit invested €642 million in 2006 with €592 million
dedicated to property, plant and equipment and intangible assets, mainly to maintain existing production plants,
particularly nuclear power plants, and to upgrade and extend E.ON Nordic’s distribution network. Share
investments amounted to €50 million.
Capital expenditures in the U.S. Midwest market unit increased by 73.4 percent from €398 million in 2006
to €690 million in 2007 primarily due to investments for SO2 emissions equipment and the construction of a new
750 MW baseload unit at the Trimble County plant.
The Corporate Center segment’s capital expenditures in 2007 amounted to €3,333 million, with
€3,134 million in share investments, primarily for the acquisition of E2-I, Airtricity and OGK-4 and €199 million
in property, plant and equipment and intangible assets. In the Corporate Center, capital expenditures amounted to
negative €27 million in 2006, with investments of negative €13 million in share investments and negative
€14 million in property, plant and equipment and intangible assets.
Financial Liabilities and Financing Policy. The financial liabilities of E.ON increased to €21,464 million at
year-end 2007 from €13,472 million at year-end 2006. The increase of €7,992 million or 59.3 percent primarily
resulted from increases in bonds outstanding (€5,467 million), commercial paper outstanding (€1,618 million),
the outstanding amount of bank loans (€775 million) and other financial liabilities (€61 million). Bank loans
increased from €1,237 million at year-end 2006 to €2,012 million at year-end 2007. (Of the amounts payable
under bank loans at year-end 2007, €1,045 million (52.0 percent) are due in 2008, €93 million (4.6 percent) due
in 2009, €381 million (18.9 percent) due in 2010, €182 million (9.0 percent) due in 2011, €100 million (5.0
percent) due in 2012 and €211 million (10.5 percent) due after 2012.)
E.ON’s investment program and its share buyback program are financed by liquid funds, operating cash
flows and additional indebtedness. E.ON follows a financing policy that ensures access to various sources of
financing at all times. As a general rule, external financings will be undertaken at the E.ON AG level or via the
Dutch financing subsidiary E.ON International Finance B.V. (under guarantee of E.ON AG)) E.ON pursues a
financing policy that is based on the following principles. Firstly, E.ON pursues a wide diversification of
investors by accessing a variety of markets and using different instruments. Secondly, bonds are issued with a
view to achieve a balanced portfolio of maturities. Thirdly, benchmark issues with a high volume are being
combined with smaller opportunistic issues.
To support E.ON’s financing policy, E.ON AG has a Commercial Paper program and a Debt Issuance
program with aggregate authorized amounts of €10 billion and €30 billion, respectively. E.ON also has a
Syndicated Multi-Currency Revolving Credit Facility that permits borrowings in various currencies in an
aggregate amount of up to €15 billion. For additional information on these programs, including amounts
outstanding and available as of year end 2007, see Note 26 of the Notes to Consolidated Financial Statements.
83
For more detailed information on interest rates, maturities and other details of the Group’s financial
liabilities, including the syndicated credit facility and Commercial Paper and Debt Issuance programs, see Note
26 of the Notes to Consolidated Financial Statements.
At year-end 2007, Standard & Poor’s Ratings Group (“S&P”) and Moody’s Investors Service (“Moody’s”)
rated E.ON’s Commercial Paper program with a short-term rating of “A-1” and “Prime-1,” respectively.
Following the announcement of E.ON’s new investment plan in May 2007, Moody’s confirmed its long-term
rating for E.ON at “A2” with a stable outlook. Previously, Moody’s had reduced its long-term rating for E.ON
from “Aa3” to “A2” following E.ON’s announcement that it had signed an agreement with Enel and Acciona to
acquire certain assets following their purchase of Endesa. Moody’s short-term “P-1” rating remained unchanged.
On June 12, 2007, S&P lowered its long-term rating for E.ON from “AA-” to “A” with a stable outlook
following the announcement of E.ON’s revised strategy on May 31, 2007. Both the long-term rating from
Moody’s and S&P factor in the higher investment plan and the resulting increase of indebtedness. Both agencies
expect that the relevant ratios will remain within the ranges of an A2 or A rating, respectively.
Expected Investment Activity. E.ON currently plans to invest a total of approximately €49.9 billion over the
three years from 2008 to 2010. A majority of these capital expenditures (approximately 73 percent or €36.3
billion) is planned for expanding the existing business and approximately 27 percent or €13.6 billion at
maintaining E.ON’s position in the electricity and gas markets. The investment plan is based on the actual group
structure as of December 31, 2007. Investments in new market units are shown as part of the Corporate Center.
The Central Europe market unit expects to make a total of approximately €14.3 billion in capital
expenditures between 2008 and 2010. Of this amount, approximately 64 percent is budgeted for maintenance and
replacement, and 36 percent are growth investments. Maintaining and increasing the unit’s generating capacity in
the convergent western European market is an important component in these investments. As described in more
detail in the description of the market unit’s activities in “Business,” the construction of new power stations at
Datteln and Irsching has already begun, while E.ON is committed to building a new coal-fired power station at
Staudinger if and when the necessary regulatory approvals are obtained. The market unit’s plans also include the
construction at Wilhelmshaven of the world’s first large coal-fired power plant capable of operating with a target
efficiency of more than 50 percent. Outside of Germany, E.ON has started to build a modern gas-fired power
station at Livorno Ferraris in Italy, and plans to build a coal-fired power station at Maasvlakte in the Netherlands
and at Antwerp in Belgium. New coal-fired and gas-fired power stations are planned at Malzenice in Slovakia
and Gönyu in Hungary, as well as elsewhere in Eastern Europe. A total of approximately €3.5 billion has been
budgeted for investments in power and gas networks in Central Europe, of which the single largest investment
(approximately €1.7 billion) is intended for connecting the offshore wind power facilities to the power network.
The Pan-European Gas market unit plans to invest approximately €6.0 billion during the three-year period,
of which approximately 90 percent is budgeted for growth investments. These investments are mainly targeted
towards developing natural gas fields. In addition, investments are planned to improve and expand the gas
transmission pipelines and storage facilities to secure the security and flexibility of gas supplies.
Investments at the U.K. market unit are expected to total approximately €5.7 billion between 2008 and 2010
and are predominantly focused on the replacement and maintenance of generation facilities and the distribution
network infrastructure. This includes the construction of a coal-fired power station, as well as two combined
cycle gas-fired plants. In addition, growth investment in power production from renewable sources, especially
wind power, is also expected to increase. Of the total of €5.7 billion, approximately €0.8 billion has been
budgeted for financial investments in companies operating wind power facilities.
The Nordic market unit is expected to invest approximately €3.0 billion over the three-year period. Nordic’s
investments are mainly earmarked for the improvement of the Swedish power distribution network and the
modernization, improvement in performance and expansion of existing generation facilities, such as the
completion of the CHP power station currently being built at Malmö. Of the total of €3.0 billion, approximately
€1.4 billion are maintenance and €1.6 billion are growth investments.
84
Capital expenditures totaling approximately €1.7 billion through 2010 are budgeted at the U.S. Midwest
market unit. All of these investments are earmarked for property, plant and equipment. The market unit’s most
important investment project is the completion of Trimble County 2, a 750 MW coal-fired power station, while
investments will also be made in environmental measures at existing power stations and the improvement of
power and gas networks.
The investment plan summarized above only contains projects that E.ON believes are sufficiently probable
from today’s perspective.
In addition to the investments expected in each individual market unit (together totaling approximately
€30.7 billion), other budgeted expenditures (totaling approximately €19.2 billion) over the period 2008 to 2010
include the planned takeover of activities in France, Italy and Spain as part of the agreement with Enel and
Acciona, as well as investments in new markets. Among these are follow-up investments in Russia and in
renewable energies.
The acquisition of Endesa assets in Europe and Viesgo are the material transactions expected to have a
significant impact on E.ON’s cash flows in 2008.
Upon approval of the Supervisory Board on August 10, 2005, E.ON Pension Trust e.V. and
Pensionsabwicklungstrust e.V. were formed, each with registered offices in Grünwald, Germany. The purpose of
these trusts is the fiduciary administration of funds to provide for future pension benefit payments to employees
of German group companies (the so-called “CTA model”). In 2006, E.ON made a contribution of €5.1 billion.
In January 2005, E.ON AG agreed to make a payment of GBP431 million (approximately €629 million) into
the pension schemes for existing employees of the U.K. market unit. The payment, which was made in April
2005, improved the funding level of the plans (which had a funding deficit of GBP728 million (€1.1 billion) at
the time of the last actuarial valuation in March 2004) and allowed for the merger of four previously autonomous
sections covering Powergen, East Midlands Electricity Distribution plc, Midlands Electricity and TXU into a
single pool.
E.ON expects that cash flow from operations will continue to be the primary source of funds for capital
expenditures in its ongoing business (i.e., excluding acquisitions) and working capital requirements in 2008.
E.ON believes that its cash flow and available liquid funds and credit lines will be sufficient to meet the
anticipated cash needs of its ongoing business operations. In addition, various means of raising share capital and
debt are available to E.ON.
Fair Value of Derivatives. E.ON has established risk management policies that allow the use of foreign
currency, interest rate, equity, and commodity derivative instruments and other instruments and agreements to
manage its exposure to market, currency, interest rate, commodity price, share price and counterparty risk. E.ON
uses derivatives for both trading and non-trading purposes. Proprietary trading is conducted with the goal of
improving operating results within defined limits in specified markets.
For information regarding E.ON’s trading activities, risk management and market factors impacting the fair
values of contracts, see the respective market unit descriptions in “— Quantitative and Qualitative Disclosures
about Market Risk” and Notes 30 and 31 of the Notes to Consolidated Financial Statements.
E.ON estimated the gross mark-to-market value of its commodity contracts as of December 31, 2007, which
amounted to negative €352.6 million (2006: negative €1,132.1 million), using quoted market values where
available and other valuation techniques where market data is not available. In such instances, E.ON uses
alternative pricing methodologies, including, but not limited to, fundamental data models, spot prices adjusted for
forward premiums/discounts and option pricing models. Fair value contemplates the effects of credit risk,
liquidity risk and the time value of money on gross mark-to-market positions.
85
The following table shows the sources of prices used to calculate the fair value of commodity contracts at
December 31, 2007. In many cases these prices are fed into option models that calculate a gross mark-to-market
value from which fair value is derived after considering reserves for liquidity, credit, time value and model
confidence.
SOURCE OF FAIR VALUE TABLE
Fair Value of Contracts at Period-End
Source of Fair Value
Fair Value
Nominal Value
(€ in millions)
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources or based on models and other
valuation methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(73.1)
10,480.7
(279.5)
46,723.0
The amounts disclosed above are not indicative of likely future cash flows, as these positions may be
changed by new transactions in the trading portfolio at any time in response to changing market conditions,
market liquidity and E.ON’s risk management portfolio needs and strategies.
Off-Balance Sheet Arrangements
E.ON uses certain off-balance sheet arrangements in the ordinary course of business, including guarantees,
lines of credit, indemnification agreements and other arrangements. E.ON’s arrangements in each of these
categories are described in more detail below. For additional information, see Note 27 of the Notes to
Consolidated Financial Statements.
Contingent liabilities. With regard to the aforementioned arrangements and other underlying matters
contingent liabilities have been arisen in the E.ON group. A contingent liability is a possible obligation that
arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one
or more uncertain future events not wholly within the control of E.ON or a present obligation that arises from
past events but is not recognized because it is not probable that an outflow or E.ON’s resources embodying
economic benefits will be required to settle E.ON’s obligation or the amount of the obligation cannot be
measured with sufficient reliability. Contingent liabilities are generally not recognized on E.ON’s balance sheet.
As of December 31, 2007, E.ON’s contingent liabilities amounted to €96 million (2006: €114 million). E.ON
currently does not have reimbursement rights relating to the contingent liabilities disclosed.
Guarantees. E.ON has issued various direct and indirect guarantees to third parties, which require the
guarantor to make contingent payments upon the occurrence of certain events or changes in an underlying
instrument that is related to an asset, a liability or the equity of the guaranteed party, on behalf of both related
parties and external entities. These consist primarily of financial guarantees and warranties.
The direct guarantees of E.ON also include items related to the operation of nuclear power plants. With the
entry into force on April 27, 2002, of the German Nuclear Power Regulations Act (Atomgesetz, or “Tag”), as
amended, and of the ordinance regulating the provision for coverage under the Atomgesetz (Atomrechtliche
Deckungsvorsorge-Verordnung, or “AtDeckV”), as amended, German nuclear power plant operators are required
to provide nuclear accident liability coverage of up to €2.5 billion per incident.
The coverage requirement is satisfied in part by a standardized insurance facility in the amount of €255.6
million. The institution Nuklear Haftpflicht Gesellschaft bürgerlichen Rechts (“Nuklear Haftpflicht GbR”) now
only covers costs between €0.5 million and €15 million for claims related to officially ordered evacuation
measures. Group companies have agreed to place their subsidiaries operating nuclear power plants in a position
to maintain a level of liquidity that will enable them at all times to meet their obligations as members of the
Nuklear Haftpflicht GbR, in proportion to their shareholdings in nuclear power plants.
86
To provide liability coverage for the additional €2,244.4 million per incident required by the abovementioned amendments, E.ON Energie AG and the other parent companies of German nuclear power plant
operators reached a Solidarity Agreement (Solidarvereinbarung) on July 11, July 27, August 21, and August 28,
2001. If an accident occurs, the Solidarity Agreement calls for the nuclear power plant operator liable for the
damages to receive — after the operator’s own resources and those of its parent company are exhausted —
financing sufficient for the operator to meet its financial obligations. Under the Solidarity Agreement, E.ON
Energie’s share of the liability coverage currently stands at 42.0 percent (2006: 42.0 percent), with an additional
5.0 percent charge for the administrative costs of processing damage claims.
In accordance with Swedish law, the Nordic market unit has issued guarantees to governmental authorities.
The guarantees were issued to cover possible additional costs related to the disposal of high-level radioactive
waste and to nuclear power plant decommissioning. These costs could arise if actual costs exceed accumulated
funds. In addition, Nordic is also responsible for any costs related to the disposal of low-level radioactive waste.
In Sweden, owners of nuclear facilities are liable for damages resulting from accidents occurring in those
nuclear facilities and for accidents involving any radioactive substances connected to the operation of those
facilities. The liability per incident as of December 31, 2007, was limited to SEK 3,063 million, or €324 million
(2006: SEK 3,102 million, or €343 million), which amount must be insured according to the Law Concerning
Nuclear Liability. The Nordic market unit has purchased the necessary insurance for its nuclear power plants.
The Swedish government is currently in the process of reviewing the regulatory framework underlying the
aforementioned liability limitation. The extent to which this review will result in changes to the Swedish
regulations on the limitation of nuclear liability is still unclear at present.
Other than in the Central Europe and Nordic market units, there are no nuclear power plants in operation.
Accordingly, there are no additional contingent liabilities comparable to those mentioned above.
Moreover, E.ON has commitments under which it assumes joint and several liability arising from its
interests in certain German civil-law companies (“GbR”), non-corporate commercial partnerships and consortia
in which it participates.
E.ON has recorded appropriate provisions for the direct and indirect guarantees according to the regulations
of IFRS.
Indemnification Agreements. A number of the agreements governing E.ON’s
subsidiaries and operations include indemnification clauses (Freistellungen) and other
which are required by applicable local law. These arrangements generally comprise
relating to the accuracy of representations and warranties, as well as indemnification
contingent future environmental and tax liabilities.
divestiture of former
guarantees, certain of
customary guarantees
provisions relating to
In some cases the buyer of such former subsidiaries and operations is required to either share costs or cover
a certain amount of costs before E.ON is required to make any payments. Certain of E.ON’s obligations under
these arrangements are also covered by insurance and/or provisions established at the relevant divested
companies.
Guarantees issued by companies that were later sold by E.ON AG (or VEBA AG and VIAG AG before their
merger) have generally been assumed by the buyers of the relevant businesses in the final sales contracts in the
form of indemnities, and are therefore no longer obligations of E.ON.
E.ON has recorded appropriate provisions with respect to all indemnities and other guarantees included in
the sales agreements according to the regulations of IFRS.
Special Purpose Entities. E.ON applies the rules of SIC Interpretation 12 “Consolidation — Special Purpose
Entities” for various companies identified as “Special Purpose Entities.” These Special Purpose Entities (SPE)
87
consolidated within the E.ON group as of December 31, 2007, which are not significant either individually or in
the aggregate, are two jointly managed electricity generation companies, one real estate leasing company, one
company operating in the gas storage business and one company managing investments.
As of December 31, 2007, these special purpose entities included in the E.ON group had total assets of
€937 million and recorded earnings of €77 million before consolidation compared to €1,034 million in total
assets and €43 million recorded earnings before consolidation at year-end 2006.
Contractual Obligations
The following table summarizes E.ON’s contractual obligations as of December 31, 2007 and the related
amounts falling due within one year and thereafter:
Payments Due by Period
Contractual Obligations
Total
Less than
1 Year
More than
1 Year
(€ in millions)
Financial Liabilities(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,271
Capital Lease Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
193
Operating Leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
883
Purchase Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267,695
Asset Retirement Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,034
9,725
Pension Payments(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Long-Term Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,673
5,510
39
148
32,572
734
867
1,918
15,761
154
735
235,123
14,300
8,858
1,755
Total Contractual Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318,474
41,788
276,686
(1) Excludes capital lease obligations.
(2) Estimated pension payments for 2008-2017.
As of December 31, 2007, the majority of the Company’s long-term contractual obligations arose under
long-term purchase contracts in its core energy business, primarily for natural gas and electricity. For additional
details on E.ON’s financial liabilities and lease obligations, see Notes 14, 26, 27 and 31 of the Notes to
Consolidated Financial Statements. For information on pension obligations, see Note 24 of the Notes to
Consolidated Financial Statements.
Purchase Obligations. E.ON’s long-term purchase obligations primarily relate to the procurement of gas
(€244 billion) and electricity (€8 billion). E.ON Ruhrgas purchases nearly all of its natural gas under long-term
supply contracts with international and German gas producers. For more detailed information, see “Operating
and Financial Review and Prospects — Acquisitions and Dispositions — Pan-European Gas.” As is standard in
the industry, the price E.ON Ruhrgas pays for gas under these contracts is calculated on the basis of complex
formulas incorporating variables based upon current market prices for fuel oil, gas oil, coal and/or other
competing fuels, with prices being automatically recalculated periodically. The contracts also generally provide
for formal revisions and adjustments of the price and other business terms to reflect changes in the market
environment (in many cases expressly including changes in the retail market for natural gas and competing
fuels), generally providing that such revisions may only be made once every few years unless the parties agree
otherwise. Claims for revision are subject to binding arbitration in the event the parties cannot agree on the
necessary adjustments. The contracts also require E.ON Ruhrgas to pay for specified minimum quantities of gas
even if it does not take delivery of such quantities, a standard gas industry practice known as “take or pay.”
Certain of the Company’s other energy businesses also procure gas under similar arrangements. E.ON calculates
the financial obligations arising from these contracts using the same principles that govern its internal budgeting
process, as well as taking into account the specific take-or-pay obligations in the individual contracts.
88
Contractual obligations for the purchase of electricity arise in particular in connection with E.ON Energie’s
interest in jointly operated power plants. The price E.ON pays for electricity generated by these jointly operated
power plants is determined on the basis of production cost plus a profit margin that is generally calculated on the
basis of an agreed return on capital.
E.ON Energie has also entered into long-term contractual obligations for the procurement of services in the
area of reprocessing and temporary storage of spent nuclear fuel elements delivered through June 30, 2005. For
additional details on these obligations, see “Business — Central Europe — Western Europe — Power
Generation.”
E.ON’s purchase obligations also include obligations for as yet outstanding investments in connection with
new power plant construction projects as well as modernizations of existing power plants, particularly at the
Central Europe, Nordic and U.K. market units and at the power plant operator OGK-4 acquired in Russia. These
commitments also include obligations concerning the construction of wind power plants.
Asset Retirement Obligations. In accordance with IFRS, E.ON’s asset retirement obligations are reported at
the fair value of both legal and contractual obligations. These obligations primarily relate to retirement costs for
decommissioning of nuclear power plants in Germany and Sweden, environmental remediation related to
non-nuclear power plants, including removal of electricity transmission and distribution equipment,
environmental remediation at gas storage and opencast mining facilities and the decommissioning of oil and gas
field infrastructure. For additional details on E.ON’s asset retirement obligations, see Note 25 of the Notes to
Consolidated Financial Statements.
Other Long-Term Obligations. E.ON’s Other Long-Term Obligations includes obligations arising out of
option agreements that would require the Company to purchase shares from third parties. As of December 31,
2007, E.ON is a party to put option agreements related to certain of its acquisitions that allow minority
shareholders in other companies controlled by E.ON Energie to sell these remaining stakes in these companies to
E.ON at a time fixed in the put option agreement. As of December 31, 2007, the total amount potentially payable
in connection with such obligations was €0.5 billion.
Additionally, E.ON has an obligation that arises from the network connection of offshore wind farms.
Other Long-Term Obligations in the table above do not include E.ON’s obligation toward the minority
shareholders of the Russian power plant operator OGK-4 to offer to acquire their shares in that company. For
more information on this, see Note 4 of the Notes to Consolidated Financial Statements.
For more information with regard to E.ON’s long-term contractual obligations, see Notes 27 of the Notes to
Consolidated Financial Statements.
Quantitative And Qualitative Disclosures About Market Risk
For information on the Company’s risk exposures and the risk management policies and procedures it
follows, please refer to the “Summary of Significant Accounting Policies” in Note 2 of the Notes to Consolidated
Financial Statements and Notes 30 and 31 of the Notes to Consolidated Financial Statements, which provides a
summarized comparison of nominal values and fair values of financial instruments used by the Company for risk
management purposes and other information relating to those instruments.
89
BUSINESS
Except as otherwise indicated, the information contained herein is current to December 31, 2007 and has
not been updated since that date. See “Summary — Recent Developments”.
History and Development of the Company
E.ON AG is a stock corporation organized under the laws of Germany. It is entered in the Commercial
Register (Handelsregister) of the local court of Düsseldorf, Germany, under HRB 22315. E.ON’s registered
office is located at E.ON-Platz 1, D-40479 Düsseldorf, Germany, telephone +49-211-45 79-0. E.ON’s agent in
the United States is E.ON North America, Inc., 405 Lexington Avenue, New York, NY 10174.
The State of Prussia established VEBA in 1929 when it consolidated state-owned coal mining and energy
interests (hence the original name VEBA, “Vereinigte Elektrizitäts- und Bergwerks-Aktiengesellschaft”).
Ownership of VEBA was transferred from the dissolved Prussian state to Germany. VEBA was partially
privatized in 1965, leaving the German government with a 40.2 percent share. After several subsequent offerings,
privatization was completed in 1987 when the German government offered its remaining 25.5 percent share to
the public. During and since the privatization process, VEBA AG evolved into a management holding company,
providing strategic leadership and resource allocation for the entire Group.
On June 16, 2000, VEBA AG merged with VIAG AG, one of the largest industrial groups in Germany.
VEBA AG was subsequently renamed E.ON AG.
The merger of VEBA and VIAG was legally implemented by merging VIAG AG into VEBA AG, with
VEBA AG continuing as the surviving entity. The newly-merged company then received the new name
E.ON AG. VIAG AG was dissolved and its assets and liabilities were transferred to VEBA AG. Simultaneously,
each VIAG shareholder, with the exception of VEBA AG, received two shares of the new company in exchange
for each five VIAG shares held. Pursuant to this exchange ratio, the former VIAG shareholders (with the
exception of VEBA AG) therefore held 33.1 percent of the company immediately after the merger, while the
former VEBA shareholders held 66.9 percent.
In 2002, E.ON acquired the London- and Coventry-based British utility Powergen. As agreed between E.ON
and Powergen, upon satisfaction of all conditions E.ON implemented the transaction under an alternative U.K.
legal procedure known as a “scheme of arrangement” instead of a tender offer. The scheme of arrangement
provided for the acquisition of all outstanding Powergen shares by virtue of an order of the English courts
following approval of the transaction at a meeting of Powergen shareholders convened by order of the court.
Following the receipt of the necessary regulatory approvals, E.ON completed its acquisition of the Powergen
Group, which is now wholly owned by E.ON, on July 1, 2002. In March 2003, E.ON transferred LG&E Energy
(Powergen’s former principal U.S. operating subsidiary; now named E.ON U.S.) and its direct parent holding
company to a direct subsidiary of E.ON AG. In July 2004, Powergen was renamed E.ON UK.
The total purchase price amounted to €7.6 billion (net of €0.2 billion cash acquired), and the assumption of
€7.4 billion of debt. Goodwill in the amount of €8.9 billion resulted from the purchase price allocation. A
significant deterioration in the market environment for the Powergen Group’s U.K. and U.S. operations triggered
an impairment analysis as of the acquisition date that resulted in an impairment charge of €2.4 billion, thus
reducing the amount of goodwill associated with the transaction to €6.5 billion.
For more information on E.ON UK and E.ON U.S., see “— Our Business — U.K.” and “— U.S. Midwest.”
E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas business
in Germany in terms of gas sales. Prior to its acquisition by E.ON, Ruhrgas was owned by a number of holding
companies, with indirect stakes dispersed among a number of major industrial and energy companies both within
and outside Germany. E.ON completed its acquisition of these stakes in 2003, following a prolonged procedure
marked by regulatory and legal challenges to E.ON’s acquisition of control over Ruhrgas. For more detailed
information on that process, see “— Our Business — Pan European Gas.” The total cost of the transaction to
90
E.ON, including settlement costs and excluding dividends received on Ruhrgas shares owned by E.ON prior to
its consolidation, amounted to €10.2 billion. Beginning as of February 1, 2003, E.ON fully consolidated Ruhrgas,
which was renamed E.ON Ruhrgas on July 1, 2004.
In February 2006, we announced our intent to make an offer to acquire all the outstanding ordinary shares
and ADSs of Endesa. The offer consisted of an offer to all holders of Endesa ordinary shares and a separate,
concurrent offer to all holders of Endesa ordinary shares who are resident in the United States and to all holders
of Endesa ADSs, wherever located. In April 2007 following competing bids by Acciona S.A. (“Acciona”) and
Enel SpA (“Enel”), we entered into an agreement with Enel/Acciona to acquire, following any acquisition of
Endesa by Enel/Acciona, a substantial package comprising the Enel subsidiary Enel Viesgo in Spain and power
plants and other shareholdings of Endesa in Spain, France and Italy. On August 6, 2007, the European
Commission approved the acquisition of Endesa Europe and Viesgo by us without any conditions.
On March 28, 2008, our Board of Management and Supervisory Board approved the acquisition from
Acciona S.A. and Enel S.p.A of: (1) Enel Viesgo Generación, S.L. and Electra de Viesgo Distribución, S.L.
(together, “Viesgo”) in Spain, a 1,600 megawatts (“MW”) generation capacity business and distribution business,
from Enel; (2) 1,400 MW of generating capacity in Spain to be transferred from Endesa; (3) new build projects in
Spain of 2,000 MW capacity by 2010; (4) Endesa’s stake in Endesa Italia, S.p.A., a 7,200 MW generation
capacity business (of which based on the current assumptions approximately 70 percent will be for us) and future
liquid natural gas regasification capacity; (5) Endesa’s stake in SNET in France with 2,500 MW capacity; and
(6) certain assets in Poland and Turkey. The valuation process of the assets, which was agreed on April 2, 2007
as a basis for determining the final enterprise value of the asset package, has now been completed on schedule.
The transaction value totals approximately €11.8 billion: €2 billion for Viesgo, €750 million for the additional
Spanish generation assets, and €9.1 billion for Endesa Europe. On the basis of a consolidated net debt of
approximately €2.9 billion, the equity purchased would amount to approximately €8.9 billion. The final net debt
figure still has to be determined according to the provisions of the agreement of April 2, 2007. The completion of
the transaction is likely to take place in the third quarter of 2008 once all permits are available.
Our Business
We are the largest industrial group in Germany, measured on the basis of market capitalization at
December 31, 2007. For the year ended December 31, 2007, we had sales of €68.7 billion with approximately
88,000 employees worldwide.
As of December 31, 2007, our core energy business was organized into the following five market units:
Central Europe, Pan-European Gas, U.K., Nordic and U.S. Midwest.
Central Europe. E.ON Energie AG, Munich, Germany (“E.ON Energie”) is the lead company of the Central
Europe market unit. E.ON Energie is one of the largest non-state-owned European power companies in terms of
electricity sales. E.ON Energie’s core business consists of the ownership and operation of power generation
facilities and the transmission, distribution and sale of electricity and, to a lesser extent, gas and heat, to
interregional, regional and municipal utilities, traders and industrial, commercial and residential customers.
Furthermore, E.ON Energie operates waste incineration facilities. The Central Europe market unit owns interests
in and operates power stations with a total installed capacity of approximately 37,200 MW, of which Central
Europe’s attributable share is approximately 28,500 MW (not including mothballed, shutdown and cold reserve
plants). In 2007, E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in
Germany. In 2007, the Central Europe market unit recorded revenues of €32.0 billion and an adjusted EBIT of
€4.7 billion. For a definition of adjusted EBIT, see “Summary — Summary Consolidated Financial Data.”
Pan European Gas. E.ON Ruhrgas AG, Essen, Germany (“E.ON Ruhrgas”) is the lead company of the
Pan-European Gas market unit and is responsible for all of E.ON’s non-retail gas activities in continental Europe.
E.ON Ruhrgas is one of the leading non-state-owned gas companies in Europe and the largest gas company in
91
Germany in terms of gas sales, with 712.8 billion kilowatt hours (“kWh”) of gas sold in 2007. E.ON Ruhrgas’
principal business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas purchases nearly all
of its natural gas from producers in six countries: Russia, Norway, the Netherlands, Germany, the United
Kingdom and Denmark. E.ON Ruhrgas sells this gas to supra-regional and regional distributors, municipal
utilities and industrial customers in Germany and increasingly also delivers gas to customers in other European
countries. In addition, E.ON Ruhrgas is active in gas transmission within Germany via a network of
approximately 11,611 kilometers (“km”) of gas pipelines and operates a number of underground storage facilities
in Germany. E.ON Ruhrgas also holds numerous stakes in German and other European gas transportation and
distribution companies, as well as a 6.4 percent shareholding in OAO Gazprom, Russia’s main natural gas
exploration, production, transportation and marketing company. In 2007, the Pan-European Gas market unit
recorded revenues of €22.7 billion and adjusted EBIT of €2.6 billion.
U.K. E.ON UK plc (formerly Powergen UK plc), Coventry, United Kingdom (“E.ON UK”) is the lead
company of the U.K. market unit and is one of the leading integrated electricity and gas companies in the United
Kingdom. E.ON UK and its associated companies are involved in electricity generation, distribution, retail and
trading. As of December 31, 2007, E.ON UK owned or through joint ventures had an attributable interest in
10,581 MW of generation capacity. E.ON UK served approximately 8.0 million electricity and gas customer
accounts at December 31, 2007 and its Central Networks business served 4.9 million customer connections. In
2007, the U.K. market unit recorded sales of €12.6 billion and an adjusted EBIT of €1.1 billion.
Nordic. E.ON Nordic AB, Malmö, Sweden (“E.ON Nordic”) is the lead company of the Nordic market unit.
E.ON Nordic’s principal business, carried out mainly through E.ON Sverige AB (“E.ON Sverige”), is the
generation, distribution, sale and trading of electricity, gas and heat and waste, mainly in Sweden. E.ON Sverige
is the second-largest Swedish utility (on the basis of electricity sales and production capacity). E.ON Nordic is
the largest shareholder in E.ON Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent
voting interest. Statkraft (“Statkraft” refers to Statkraft AS and its consolidated subsidiaries), the other
shareholder in E.ON Sverige and E.ON AG have on October 12, 2007 signed a letter of intent stating that E.ON
AG will take over Statkraft’s 44.6 percent interest in E.ON Sverige’s share capital in the second or third quarter
of 2008. As of December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power stations with
a total installed capacity of approximately 18,300 MW, of which its attributable share was approximately 7,400
MW (not including mothballed and shutdown power plants). In 2007, E.ON Nordic recorded sales of €3.3
billion, and adjusted EBIT of €670 million.
U.S. Midwest. E.ON U.S. LLC, Louisville, USA (“E.ON U.S.”) is the lead company of the U.S. Midwest
market unit. E.ON U.S. is a diversified energy services company with businesses in power generation, retail gas
and electric utility services, as well as asset-based energy marketing. E.ON U.S.’s power generation and retail
electricity and gas services are located principally in Kentucky, with a small customer base in Virginia and
Tennessee. As of December 31, 2007, E.ON U.S. owned or controlled aggregate generating capacity of
approximately 7,500 MW. In 2007, E.ON U.S. served more than one million customers. In 2007, the U.S.
Midwest market unit recorded sales of €1.8 billion, and adjusted EBIT of €388 million.
Corporate Center. The Corporate Center consists of E.ON AG itself, those interests owned directly and
indirectly by E.ON AG that have not been allocated to any of the other segments, including its remaining
telecommunications interests (until their disposal), and for 2007 the newly acquired companies Airtricity Inc. and
Airtricity Holdings (Canada) Ltd. (collectively “Airtricity”), ENERGI E2 Renovables Ibéricas S.L.U. (“E2-I”)
and OAO OGK-4 (“OGK-4”). The Corporate Center’s results also reflect consolidation effects at the Group
level, including the elimination of intersegment sales.
New Market Units
Since January 1, 2008, E.ON has been organized into nine different market units having added the Energy
Trading, Italy, Russia and Climate & Renewables market units. If the pending acquisition of Viesgo and
additional generation capacity in Spain from Endesa is successful, these operations are expected to be organized
92
in a new tenth market unit. For information about the planned acquisition, see “Business — History and
Development of the Company.” Until the end of 2008, the results of each of the new market units other than
Energy Trading will be reported as part of the Corporate Center segment; Energy Trading’s results will be
reported separately. The detailed discussion of each of the five existing market units that follows is based on their
operations as of year-end 2007, and thus does not fully reflect intra-Group transfers of assets or operations to the
new market units.
Energy Trading. E.ON Energy Trading AG, Germany (“EET”) is the lead company of the Energy Trading
market unit. EET began operations in January 2008, and combines all our European trading activities, including
those relating to electricity, gas, coal, oil and CO2 emission allowances. We have created EET with the goal of
taking advantage of the opportunities created by the increasing integration of Europe’s power and gas markets
and those present in global commodity markets.
Russia. E.ON Russia Power, Russia (“E.ON Russia”) is the lead company of the E.ON Russia market unit.
E.ON Russia oversees our power business in Russia. In October 2007, we acquired a majority stake in the
Russian power generation company OGK-4. E.ON now holds 76.1 percent of OGK-4’s capital stock. OGK-4
operates five conventional power stations at different locations with a total installed capacity of 8.6 gigawatts
(“GW”). For additional details on the OGK-4 acquisition, see “History and Development of the Company.”
Italy. E.ON Italia S.p.A., Italy (“E.ON Italia”) is the lead company of the Italy market unit. E.ON Italia
manages our power and gas business in Italy, and is active in Italy’s wholesale power and gas markets and in
natural gas sales. The expected acquisition of the activities of Endesa in Italy will give us a total of about 5,000
MW of generating capacity in Italy. For information about the planned acquisition, see “History and
Development of the Company.”
Climate & Renewables. E.ON Climate & Renewables GmbH, Germany (“C&R”) is the lead company of
the Climate & Renewables market unit. C&R is responsible for managing and expanding our global renewables
business and for coordinating climate-protection projects. C&R has about 760 MW of generating capacity in
Europe and approximately 250 MW in North America.
The following table sets forth the sales of E.ON’s market units (as well as the Corporate Center) for 2007
and 2006:
2007
(€ in millions)
Central Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pan-European Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nordic(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Midwest(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate Center(1)(2)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32,029
22,745
12,584
3,339
1,819
(3,785)
Total Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68,731
2006
%
46.6
33.1
18.3
4.9
2.6
(5.5)
100.0
(€ in millions)
27,197
22,947
12,518
2,827
1,930
(3,328)
64,091
%
42.5
35.8
19.5
4.4
3.0
(5.2)
100.0
(1) Excludes the sales of certain activities now accounted for as discontinued operations. For more details, see
“Operating and Financial Review and Prospects — Results of Operations — Discontinued Operations” for
each period and Note 4 of the Notes to Consolidated Financial Statements.
(2) Includes primarily the parent company and effects from consolidation, as well as the results of certain other
interests, as noted above.
(3) Excludes intercompany sales.
Most of E.ON’s operations are in Germany. German operations produced 59.1 percent of E.ON’s revenues
(measured by location of operation) in 2007 (2006: 60.8 percent). E.ON also has a significant presence outside
Germany representing 40.9 percent of revenues by location of operation for 2007 (2006: 39.2 percent). In 2007,
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53.7 percent (2006: 54.5 percent) of E.ON’s revenues were derived from customers in Germany and 46.3 percent
(2006: 45.5 percent) from customers outside Germany. For more details about the segmentation of E.ON’s
revenues by location of operation and customers for the years 2007 and 2006, see Note 33 of the Notes to
Consolidated Financial Statements. At December 31, 2007, E.ON had 87,815 employees, approximately 39.4
percent of whom were employed in Germany.
Central Europe
Overview
The Central Europe market unit is led by E.ON Energie. E.ON Energie, which is wholly owned by E.ON, is
one of the largest non-state-owned European power companies in terms of electricity sales. E.ON Energie had
revenues of €32.0 billion, €24.9 billion of which was generated from German customers and adjusted EBIT of
€4.7 billion in 2007. E.ON Energie, together with E.ON Ruhrgas and E.ON Nordic, is responsible for all of
E.ON’s energy activities in Germany and continental Europe and is one of the four interregional electric utilities
in Germany that are interconnected in the western European power grid.
E.ON Energie is embarking on a significant program to build new generating capacity in many of the
countries in which it operates:
•
Construction is underway on new facilities at Irsching, Germany (a 530 MW advanced natural gas plant
to be built in cooperation with Siemens AG, scheduled to begin operations in 2011 and a new 800 MW
combined cycle gas fired plant, which is scheduled to begin operations in 2009), Datteln, Germany (a
1,100 MW hard coal plant, scheduled to begin operations in 2011) and Livorno Ferraris, Italy (an 800
MW natural gas plant, scheduled to begin operations in 2008 and expected to form part of the new
market unit Italy).
•
In addition, E.ON Energie plans to build new plants at the location of Staudinger, Germany (a
1,100 MW hard coal plant), Maasvlakte, the Netherlands (a 1,100 MW hard coal plant) and in the
harbor of Antwerp, Belgium (a 1,100 MW hard coal plant), if all requirements are met. E.ON also plans
to build the world’s first large coal fired power plant with a target efficiency of more than 50 percent
and a capacity of about 550 MW in Wilhelmshaven, Germany.
•
E.ON Energie also intends to erect two 400 MW gas fired combined cycle power plants in Gönyü,
Hungary, and Malzenice, Slovakia, both of which are expected to start operations in 2010, and may
build other power plants in Eastern Europe.
For more information, see “Operating and Financial Review and Prospects — Liquidity and Capital
Resources — Expected Investment Activity.”
E.ON Energie’s company structure reflects its operations in western and eastern Europe and, in addition,
reflects the individual segments of its electricity business: generation, transmission, distribution, sales and
trading. The following chart shows the major subsidiaries of the Central Europe market unit as of December 31,
2007, their respective fields of operation and the percentage of each held by E.ON Energie as of that date.
Central Europe Market Unit
Holding Company
E.ON Energie AG
•
Leading entity for the management and coordination of the group activities.
•
Centralized strategic, controlling and service functions.
94
Western Europe
Conventional Power Plants
E.ON Kraftwerke GmbH (100%)
•
Power generation by conventional power plants.
•
Renewables.
•
District heating.
•
Industrial power plants.
Nuclear Power Plants
E.ON Kernkraft GmbH (100%)
•
Power generation by nuclear power plants.
Hydroelectric Power Plants
E.ON Wasserkraft GmbH (100%)
•
Power generation by hydroelectric power plants.
Waste Incineration
BKB AG (100%)
•
Energy generation from waste incineration.
E.ON Benelux Holding B.V. (100%)
•
Power generation by conventional power plants in the Netherlands.
•
District heating in the Netherlands.
•
Sales of power and gas in the Netherlands.
Transmission
E.ON Netz GmbH (100%)
•
Operation of high voltage grids (380 kilovolt-110 kilovolt).
•
System operation, including provision of regulating and balancing power.
Distribution of Electricity and Gas
Seven regional grid companies across Germany (shareholding percentages range from 62.8 to 100.0 percent)
•
Distribution of electricity and gas to retail customers.
Sales and Trading of Electricity, Gas and Heat
E.ON Sales & Trading GmbH (100%)(1)
•
Supply of electricity and energy services to large industrial customers, as well as to regional and
municipal distributors.
•
Centralized wholesale functions.
•
Optimization of energy procurement costs.
(1) Since December 20, 2007, E.ON Energy Trading AG
95
•
Physical energy trading and trading of energy-based financial instruments and related risk management.
•
Optimization of the value of the power plants’ assets in the market place.
•
Emissions trading
Seven regional energy companies across Germany (shareholding percentages range from 62.8 to
100.0 percent)
•
Sales of electricity, gas, heat and water to retail customers.
•
Ownership and operation of regional grid companies in compliance with the Energy Law of 2005.
•
Energy support services.
•
Waste incineration.
E WIE EINFACH Strom & Gas GmbH (100%)
•
Sales of electricity and gas to residential customers and small and medium enterprises across Germany.
Ruhr Energie GmbH (100%)
•
Customer service and electricity and heat supply to utilities and industrial customers in the Ruhr region.
Eastern Europe
E.ON Hungária Energetikai ZRt. (100%)
•
Generation, distribution and sales of electricity and gas in Hungary through its group companies.
E.ON Czech Holding AG (100%)
•
Generation, distribution and sales of electricity and gas in the Czech Republic through its group
companies.
E.ON Energie România S.A. (90.2%)
•
Distribution and sales of electricity in Romania through its group companies.
E.ON Bulgaria EAD (100%)
•
Distribution and sales of electricity in Bulgaria through its group companies.
Západoslovenská energetika a.s. (49.0% held at equity)
•
Distribution and sales of electricity in Slovakia through its group companies.
Consulting and Support Services
E.ON Engineering GmbH (57.0%)(2)
•
Provision of consulting and planning services in the energy sector to companies within the Group and
third parties.
•
Marketing of expertise in the area of conventional and renewable power generation and cogeneration, as
well as a pipeline business.
(2) The remaining 43.0 percent is held by E.ON Ruhrgas.
96
•
E.ON IS GmbH (30.0%)(3)
•
Provision of information technology services to companies within the Group and third parties.
E.ON Facility Management GmbH (100%)
•
Infrastructure services.
For financial reporting purposes, the Central Europe market unit comprises four business units: Central
Europe West Power, Central Europe West Gas, Central Europe East and Other/Consolidation. The Central
Europe West Power business unit reflects the results of the conventional (including waste incineration), nuclear
and hydroelectric generation businesses, transmission of electricity, the regional distribution of power and the
retail electricity business in Germany, as well as its trading business. In addition, Central Europe West Power
also includes the results of E.ON Benelux Holding B.V. (“E.ON Benelux”), which operates power generation,
district heating and gas and electricity retail businesses in the Netherlands. The Central Europe West Gas
business unit reflects the results of the regional distribution of gas and the gas retail business in Germany. The
Central Europe East business unit primarily includes the results of the regional distribution companies in
Bulgaria, the Czech Republic, Hungary, Romania and Slovakia (with the Slovak activities being valued under the
equity method given E.ON Energie’s minority interest). Other/Consolidation primarily includes the results of
E.ON Energie’s retail business in Italy, other national and international shareholdings, service companies and
E.ON Energie AG, as well as intrasegment consolidation effects.
Operations
Electricity generated at power stations is delivered to customers through an integrated transmission and
distribution system. The principal segments of the electricity industry in the countries in which E.ON Energie
operates are:
Generation:
the production of electricity at power stations;
Transmission:
the bulk transfer of electricity across an interregional power grid, which consists
mainly of overhead transmission lines, substations and some underground cables
(at this level there is a market for bulk trading of electricity, through which sales
and purchases of electricity are made between generators, regional distributors,
and other suppliers of electricity);
Distribution:
the transfer of electricity from the interregional power grid and its delivery,
across local distribution systems, to customers;
Sales:
the sale of electricity to customers; and
Trading:
the buying and selling of electricity and related products for purposes of
portfolio optimization, arbitrage and risk management.
E.ON Energie and its associated companies are actively involved in all segments of the electricity industry.
Its core business consists of the ownership and operation of power generation facilities and the transmission,
distribution and sale of electricity and, to a lesser extent, gas and heat, to interregional, regional and municipal
utilities, traders and industrial, commercial and residential customers. Furthermore, E.ON Energie operates waste
incineration facilities.
(3) The remaining 70.0 percent is held by E.ON AG.
97
The following table sets forth the sources of E.ON Energie’s electric power in kWh in 2007 and 2006:
Sources of Power
2007
million kWh
2006
million kWh
%
Change
Own production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
from power stations in which E.ON Energie has an interest of 50 percent or
less . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
from other suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total power procured(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power used for operating purposes, network losses and pump storage . . . . . . .
134,531
192,635
131,304
149,867
+2.5
+28.5
8,301
184,334
327,166
(13,469)
12,287
137,580
281,171
(12,951)
-32.4
+34.0
+16.4
+4.0
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
313,697
268,220
+17.0
(1) Excluding physically-settled electricity trading activities at E.ON Sales & Trading GmbH (“EST”). EST’s
physically-settled electricity trading activities amounted to 141,797 million kWh and 161,892 million kWh
in 2007 and 2006, respectively.
In 2007, E.ON Energie procured a total of 327.2 billion kWh of electricity, including 13.5 billion kWh used
for operating purposes, network losses and pumped storage. E.ON Energie purchased a total of 8.3 billion kWh
of power from power stations in which it has an interest of 50 percent or less. In addition, E.ON Energie
purchased 184.3 billion kWh of electricity from other utilities, 14.8 billion kWh of which were from Vattenfall
Europe, the eastern German interregional utility, for redistribution by eastern German regional distributors. In
addition, E.ON Energie purchased power from local generators in Hungary, the Czech Republic, Bulgaria and
Romania totaling 36.5 billion kWh. The increase in purchased power compared to 2006 primarily reflects the
purchase of significantly higher volumes due to an increase in trading activities (approximately 28 TWh), the
purchase of higher volumes of electricity from renewable resources, which is regulated under Germany’s
Renewable Energy Law (as defined in “— Regulatory Environment”) (approximately 15 TWh) and the
contribution of Dalmine Energie S.p.A. (“Dalmine”) in Italy, first consolidated in December 2006
(approximately 4 TWh).
E.ON Energie supplied approximately 17 percent of the electricity consumed by end users in Germany in
2007. Electricity accounted for 80.0 percent of E.ON Energie’s 2007 sales (2006: 75.3 percent), gas revenues
represented 13.8 percent (2006: 17.6 percent), district heating 2.0 percent (2006: 2.2 percent) and other activities
4.2 percent (2006: 4.9 percent).
The following table sets forth data on the sales of E.ON Energie’s electric power in 2007 and 2006:
Total 2007
million kWh
Total 2006
million kWh
%
Change in
Total
Non-consolidated interregional, regional and municipal utilities . . . . . . . . . .
Industrial and commercial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential and small commercial customers . . . . . . . . . . . . . . . . . . . . . . . . .
185,934
83,687
44,076
145,688
77,238
45,294
+27.6
+8.3
-2.7
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
313,697
268,220
+17.0
Sale of
Power(1)
to
(1) Excluding physically-settled electricity trading activities at EST. EST’s physically-settled electricity trading
activities amounted to 141,797 million kWh and 161,892 million kWh in 2007 and 2006, respectively.
The increase in the total sale of power is mainly attributable to higher volumes sold to sales and trading
partners and to higher deliveries to the network of electricity generated from renewable resources pursuant to
Germany’s Renewable Energy Law. Furthermore the sales volumes include those of Italy’s Dalmine, which
became a consolidated E.ON Energie company in December 2006. For further information, see “Operating and
Financial Review and Prospects — Results of Operations.
98
The following table sets forth data on the gas sales of E.ON Energie in 2007 and 2006:
Total 2007
million kWh
Sale of Gas to
Total 2006
million kWh
%
Change in
Total
Non-consolidated interregional, regional and municipal utilities . . . . . . . . . .
Industrial and commercial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential and small commercial customers . . . . . . . . . . . . . . . . . . . . . . . . .
27,544
59,474
39,179
30,631
53,208
44,629
-10.1
+11.8
-12.2
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
126,197
128,468
-1.8
The decline in gas sales volumes was primarily attributable to the unseasonably warm weather across many
parts of Europe during the first four months of 2007. Although the inclusion of newly consolidated companies,
mainly Jihoceska plynárenská a.s. (“JCP”) of the Czech Republic (since September 2006) and Dalmine in Italy
(since December 2006), had a positive effect, overall gas sales volumes declined by 1.8 percent.
Western Europe
Power Generation
General. In Germany, E.ON Energie owns interests in and operates electric power generation facilities with
a total installed capacity of approximately 34,800 MW, its attributable share of which is approximately 26,300
MW (not including mothballed, shutdown or reduced power plants). The German power generation business is
subdivided into four units according to fuels used: E.ON Kraftwerke GmbH owns and operates the power
stations using fossil fuel energy sources, as well as renewable generation facilities, E.ON Kernkraft owns and
operates the nuclear power stations, E.ON Wasserkraft GmbH owns and operates the hydroelectric power plants
and BKB AG owns and operates the waste incineration plants.
In the Netherlands, E.ON Energie operates, through its subsidiary E.ON Benelux, hard coal and natural gas
power plants for the supply of electricity and heat to bulk customers and utilities. In 2007, it had a total installed
generation capacity of approximately 1,900 MW.
Based on the consolidation principles under IFRS, E.ON Energie reports 100 percent of revenues and
expenses from majority-owned power plants in its consolidated accounts without any deduction for minority
interests. Conversely, 50 percent and minority-owned power plants (at least 20 percent) are accounted for by the
equity method. Power generation capacity in jointly owned plants is generally reported based on E.ON’s
ownership percentage.
Germany. E.ON Energie’s German plants generate electricity primarily with nuclear power, bituminous coal
(commonly referred to as “hard coal”), lignite, gas, fuel oil and water. The existing nuclear and hydroelectric
power plants are E.ON Energie’s source of power with the lowest variable costs and, together with lignite-based
power plants, are used mainly to cover the base load. Hard coal is utilized mainly for middle load, while the other
energy sources are used primarily for peak load.
Nuclear Power. E.ON Energie operates its German nuclear power plants through E.ON Kernkraft. These
nuclear power plants are required to meet applicable German safety standards, which are among the most
stringent standards in the world (see “— Environmental Matters — Germany”).
Operators of nuclear power plants are required under German nuclear law to establish sufficient financial
provisions for obligations that arise from the use of nuclear power. In accordance with IAS 37, “Provisions,
Contingent Liabilities and Contingent Assets” (“IAS 37”) and IFRIC 1, these provisions include: (1) provisions
for management of non-contractual obligations based on experts’ opinions and estimates, and (2) provisions for
contractual obligations based on concluded contracts. All nuclear provisions include expenses for management of
spent nuclear fuel rods, disposal of contaminated operating waste and the decommissioning of nuclear plants. At
year-end 2007, E.ON Energie had provisions in its consolidated accounts for these purposes equal to €8.9 billion
99
for management of non-contractual obligations and €3.3 billion for contractual obligations. In addition to
obligations relating to the German nuclear law, E.ON Energie had to establish provisions for the disposal and
dismantling of non-nuclear plant components according to general applicable law.
E.ON Kernkraft purchases uranium and fuel elements for its nuclear power plants from domestic and
international suppliers, primarily under long-term contracts. E.ON Energie considers the supply of uranium and
fuel elements on the world market to be generally adequate.
In May 1995, PreussenElektra, which formed part of E.ON Energie in 2000, decided to shut down its
nuclear power plant at Würgassen for economic reasons and, in October 1995, it applied for and received
permission from the German authorities to decommission and dismantle the Würgassen plant in accordance with
German nuclear energy legislation. E.ON Energie expects the decommissioning of Würgassen, which began in
October 1995, to last until approximately 2015. In 2000, E.ON Energie also decided to shut down the nuclear
power plant Stade. In July 2001, E.ON Kernkraft filed an application with the Lower Saxonian Ministry of
Environment to decommission and dismantle Stade and received the relevant approval in September 2005. Stade
was shut down in November 2003, and E.ON Energie expects its decommissioning to last until approximately
2015. E.ON Energie has established a provision for non-contractual obligations of €1.1 billion for the
decommissioning of Würgassen and Stade, including the management of spent nuclear fuel rods and the
dismantling of the plants. E.ON Energie has also established a provision of €0.3 billion for contractual
obligations.
The current German Nuclear Power Regulations Act (Atomgesetz, or “AtG”) took effect in April 2002.
Among other things, it provides as follows:
•
Nuclear Phase-out: The operators of the nuclear plants have agreed to a specified number of operating
kWh for each nuclear plant. This number has been calculated on the basis of 32 years of plant operation
using a high load factor. The operators may trade allocated kWh among themselves. This means that if
one nuclear plant closes before it has produced the allocated amount of kWh, the remaining kWh may
be transferred to another nuclear power plant.
•
Termination of Fuel Reprocessing: The transport of spent fuel elements for reprocessing was allowed
until June 30, 2005. Following this deadline, the operators must store spent fuel in interim facilities on
the premises of the nuclear plants. Such storage requires the approval and construction of interim
storage facilities. E.ON has constructed five interim on-site storage facilities. Two of these,
Grafenrheinfeld and Grohnde, went into operation in the first quarter of 2006, while the remaining three
interim on-site storage facilities in Brokdorf, Isar and Unterweser went into operation in the first half of
2007.
As part of the agreement, the German federal government has agreed not to institute any future changes in
German tax law which discriminate against nuclear power operations or other measures creating economic
disadvantages in comparison with other forms of power generation.
The Company considers its provisions with respect to nuclear power operations to be adequate with respect
to the costs of implementing the agreement. E.ON Energie has no plans to construct any new nuclear power
plants in Germany.
Hard Coal. In 2007, approximately 30 percent of the hard coal used by E.ON Energie’s German operations
was mined in Germany. Traditionally, hard coal is mined in Germany under much more difficult conditions than
in other countries. Therefore, German coal production costs are substantially above world market levels, and
E.ON Energie strongly believes they will continue to remain high. Although electricity producers were in the
past required to purchase German coal, they are now free to purchase coal from any source. To encourage the
purchase of German coal, the German federal government has been paying direct subsidies to German producers
enabling them to offer domestic coal at world market prices, although it is now in the process of reducing such
subsidies. Due to high production costs and the reduction in subsidies, the volume of German coal production has
100
shown a relatively steady decline in the past and is expected to continue to decline further. However, E.ON
Energie expects that adequate supplies of imported coal for its operations will be available on the world coal
market at acceptable prices. Hard coal is generally available from multiple sources, though prices are determined
on international commodities markets and are therefore subject to fluctuations. E.ON Benelux also uses imported
hard coal in its power plants.
Lignite. German lignite, also known as brown coal, has approximately one-third of the heating value of hard
coal. E.ON Energie participates in lignite-based energy generation in western Germany through BKB
Aktiengesellschaft (“BKB”) and in eastern Germany through Kraftwerk Schkopau GbR and a portion of one unit
of Kraftwerk Lippendorf. Lignite is a readily available domestic fuel source that E.ON Energie obtains from its
own reserves or under long-term contracts with German producers. The price of lignite is not generally volatile
and is generally determined by reference to published indices in Germany. However, the price can fluctuate
based on the underlying price of hard coal in global commodities markets.
Gas and Oil. In Germany, the price of natural gas is linked to the price of oil and other competing fuels.
This mechanism has been enforced in order to reduce the influence of, and dependence on, gas-producing
countries. Only about 16 percent of gas demand in Germany is satisfied by German deposits, while about 84
percent is satisfied through imports from foreign producers, primarily from Russia, Norway and the Netherlands.
For its gas-fired power plants, E.ON Energie purchases gas from E.ON Ruhrgas and other international suppliers,
mainly under short-term contracts. Fuel oil power plants are only used for peak load operations. E.ON Energie
purchases its fuel oil from traders or directly from a number of oil companies. As with natural gas, the price of
fuel oil depends on the price of crude oil. E.ON Benelux purchases predominantly Dutch gas under one-year
contracts for its gas-fired power plants.
Water. This domestic source of energy is primarily available in southern Germany due to the presence of
mountains and rivers. The variable costs of production are extremely low in the case of run-of-river plants and
consequently, these plants are used to cover base load requirements. Storage and pump storage facilities are used
to meet peak demand and for back-up power purposes.
Waste Incineration. E.ON Energie also has a waste incineration business, led by BKB and E.ON Westfalen
Weser. In 2007, incinerated waste volumes totaled approximately 2.5 million tons. The waste incineration plants
have a total power generation capacity of 250 MW of electricity, of which 164 MW is attributable to E.ON
Energie.
Demand for power tends to be seasonal, rising in the winter months and typically resulting in additional
electricity sales by E.ON Energie in the first and fourth quarters. E.ON Energie believes it has adequate sources
of power to meet foreseeable increases in demand, whether seasonal or otherwise. In order to benefit from
economies of scale associated with large stations, E.ON Energie has built large capacity power station units in
conjunction with other utilities where it does not require all of the electricity produced by such plants. In these
cases, the purchase price of electricity is determined by the production cost plus a negotiated fee.
Although E.ON’s power plants are maintained on a regular basis, there is a certain risk of failure for power
plants of every fuel type. Depending on the associated generation capacity, the length of the outage and the cost
of the required repair measures, the economic damage due to such failure can vary significantly. In order to meet
contractual commitments, electricity which cannot be generated at these plants has to be bought from other
generators or has to be generated from more expensive plants. Thus, power plant outages can negatively affect
the market unit’s financial and operating results.
Transmission
The German power transmission grid of E.ON Energie, which operates with voltages of 380, 220 and 110
kilovolts, has a coverage area of nearly 200,000 km2. The 380 and 220 kilovolts extra high voltage lines have a
system length of close to 11,000 km, whereas the high voltage lines have a system length of over 30,000 km. The
grid is interconnected domestically, and with the western European power grid with links to the Netherlands,
101
Austria, Denmark and Eastern Europe and with other power grids in Germany. The system is mainly operated by
E.ON Netz. The network of E.ON Netz allows long-distance power transport (380 and 220 kilovolts) at low
transmission losses and covers about 40 percent of the surface area of Germany. This system is operated from
two main system control centers, one in Lehrte near Hanover and one in Dachau near Munich, and from several
regional control and service units at decentralized locations within the E.ON Netz grid area.
A new challenge to network operators are the ambitious construction plans for offshore windfarms.
Transmission system operators are legally bound to connect those offshore windfarms, the construction of which
is expected to have been started by 2011, to the existing transmission system onshore through new powerlines.
E.ON Netz will have to build powerlines primarily in the area of the North Sea, starting the construction
concurrently with the building of the wind farms. Costs for investments will initially have to be born by E.ON
Netz, but are expected to be distributed among all four transmission system operators and finally be included in
network charges.
Access to E.ON Energie’s power transmission grid is open to all potential users. The Company believes its
usage fees and conditions comply with existing German regulations governing grid access. For further
information about the impact of recent regulatory developments on E.ON Energie’s transmission business and
results, see “— Regulatory Environment” and “Operating and Financial Review and Prospects — Results of
Operations — Year Ended December 31, 2006 Compared with Year Ended December 31, 2005 — Central
Europe.”
The Baltic Cable links the transmission grid of E.ON Energie to Scandinavia. For details, see “— Nordic —
Regulated Business — Electricity Distribution.”
Distribution
Electricity. The German utilities historically established defined supply areas which were coextensive with
their distribution grids. The following map shows E.ON Energie’s current distribution area in Germany through
its majority shareholdings in regional energy distribution companies as of December 31, 2007:
E.ON Hanse
E.ON edis/E.ON Hanse
(73.8 %)
E.ON edis (70.0 %)
E.ON Avacon (65.0 %)
E.ON Westfalen Weser
(62.8 %)
E.ON Thüringer
Energie (77.0 %)
E.ON Mitte
(73.3 %)
E.ON Bayern (100.0 %)
Majority shareholdings
102
To meet the requirements of legal regulations and increased competition, E.ON Energie and its seven
regional energy companies have started the structural project “regi.on”. With the target of increasing enterprise
values and maintaining a sustainable basis for competitiveness, the goals of the project include for example the
standardization and harmonization of processes as well as the bundling of overall functions in separate
organizations.
In order to realize the targets of the “regi.on” project the network operating companies which have already
been spun off (“small DSO”) are planned to be re-integrated into the respective regional energy company. Within
these companies an explicit and non-overlapping organizational separation of the DSO, grid operation and
technical grid service (TNS) is planned. To meet legal requirements, the sales units will be spun off in separate
organizations. For more information, see “— Sales” below.
Access to E.ON Energie’s power distribution grid is open to all potential users. The Company believes its
usage fees and conditions comply with existing German regulations governing grid access. For further
information about the impact of recent regulatory developments on E.ON Energie’s distribution business and
results, see “— Regulatory Environment” and “Operating and Financial Review and Prospects — Results of
Operations — Year Ended December 31, 2006 Compared with Year Ended December 31, 2005 — Central
Europe.”
In January 2007, a severe storm damaged the power grid of E.ON Energie in some areas of Germany. For
more information, see “Risk Factors.”
Gas. E.ON Energie’s distribution subsidiaries supply natural gas to households, small businesses and
industrial customers in many parts of Germany. Similar to “Electricity” above, E.ON Energie’s regional
distribution companies had to submit their calculated gas network charges to Germany’s energy regulator by the
end of January 2006. The energy regulator approved reduced charges for each of E.ON Energie’s network
operators between September and November 2006. For the next regulatory period beginning in April 2008, the
network operators submitted applications for charges in September 2007. For more information, see
“— Regulatory Environment — Germany: Gas — Gas Network Charges.”
Sales
In Germany, E.ON Energie supplies electricity, gas and heat, mainly through the regional energy companies
in which it holds majority interests. As described below, E.ON Energie’s wholly-owned subsidiary EST supplies
electricity to these regional energy companies as well as to large municipal distributors and very large national
and international industrial customers.
E.ON Energie’s customers are interregional, regional and municipal utilities, traders, industrial and
commercial customers and, through regional distributors, residential and small commercial customers
predominantly in those parts of Germany highlighted on the map shown in “Distribution” above. E.ON Energie
supplied approximately 17 percent of the electricity consumed by end users in Germany in 2007. Due to
competitive environment E.ON Energie lost approximately 300,000 private customers in its power and gas
business with its regional distributors. In February 2007, E.ON Energie launched the new company E WIE
EINFACH Strom & Gas GmbH (“EWI”), which attracted more than 450,000 residential and small business
power and gas customers in the mass market throughout Germany in 2007. The introduction of EWI allowed us
to increase our overall number of residential customers in a highly competitive market.
103
Electricity. The following table sets forth the sale of electric power by E.ON Energie’s German companies
(excluding that used in physically settled trading activities), primarily in Germany, in 2007 and 2006:
2007
million kWh
2006
million kWh
%
Change in
Total
Non-consolidated interregional, regional and municipal utilities . . . . . . . . . .
Industrial and commercial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential and small commercial customers . . . . . . . . . . . . . . . . . . . . . . . . .
171,375
55,071
28,722
135,112
53,896
29,736
+26.8
+2.2
-3.4
Total(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
255,168
218,744
+16.7
Sale of Power to
(1) The increase in the total sale of power mainly reflects higher deliveries of renewable electricity regulated by
Germany´s Renewable Energy Law, as well as higher volumes sold to sales and trading partners.
(2) Total sales of power includes sales of EST in European countries other than Germany.
The supply contracts under which E.ON Energie’s regional energy companies (all are majority-owned)
regularly order their required load for upcoming years have historically had relatively long terms. Typical supply
contracts now last for one to three years. Potential alternative sources of electricity include the purchase of
electricity from other utilities and auto-generation by municipalities, regional distributors or industrial customers.
The regional distributors’ contracts with municipal utilities contain varying terms and conditions.
In the context of the “regi.on” project (see “Distribution” above), E.ON Energie intends to bundle the tasks
of the regional energy companies concerning sales administration relating to marketing, product development
and procurement in a company managing all sales activities: E.ON Vertrieb Deutschland GmbH ( “EVD”).
Additionally EVD is also expected to direct the national wholesale sales activities of E.ON Energy Sales GmbH
(“EES”). EES will take over the former sales activities of E.ON Sales & Trading GmbH (“EST”); EST’s trading
activities are being transferred to EET, with retroactive effect as of January 1, 2008. However, responsibility for
the long-term portion of contracts (i.e., those with obligations beyond three years) will stay with E.ON Energie
and the other market units. For this purpose, the regional energy companies will transfer the relevant parts of
their natural gas and power sales business (including the customer contracts) to an affiliated subsidiary
(Vertriebsgesellschaft, “VG”) in which they have a 100 percent interest. Each regional energy company will have
its own VG. The sales activities of the VGs will be directed by EVD and the regional energy companies will own
stakes in EVD to ensure the consideration of regional interests, as well as their involvement in substantial
decisions. Furthermore, it is also planned to bundle the shared service divisions of the regional energy companies
into two companies (Shared Service Gesellschaften; “SSGs”). The SSGs predominantly provide customer related
services (e.g. metering services, billing, customer care and receivables management) associated with the sales
business of the VG´s and the distribution service business of regional energy companies. Details of the new
structure still must be agreed by all relevant parties, including the decision-making bodies of the regional energy
companies.
Gas. E.ON Energie’s gas sales volume in Germany amounted to 93.2 billion kWh in 2007 compared to
106.2 billion kWh in 2006. The decrease of consumption was mainly due to the warm winter at the beginning of
2007.
Heat. E.ON Energie is one of the leading suppliers of district heating in Germany. It operates its own district
heating networks and supplies several additional networks owned by other companies. E.ON Energie’s regional
energy companies are also involved in district heat and steam delivery. E.ON Energie’s total district heat
deliveries in Western Europe decreased from 16.2 billion kWh in 2006 to 15.2 billion kWh in 2007, of which
10.5 billion kWh were supplied in Germany. The decrease primarily reflected the warm winter in 2007.
Water. E.ON’s regional water business is conducted through certain of its distribution companies,
particularly E.ON Hanse, E.ON Avacon AG (“E.ON Avacon”) and E.ON Westfalen Weser.
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Customers. Through its subsidiaries and companies in which it has shareholdings, E.ON Energie serves
approximately 9.5 million electricity customers in Germany. E.ON Energie’s German operations also supply
approximately 1.9 million customers with gas and more than 0.5 million customers with water.
The Netherlands. In the Netherlands, E.ON Benelux acquired the Dutch power and gas company NRE
Energie b.v. (“NRE”) in 2005. In 2007, the company supplied approximately 1.2 TWh of electricity and
approximately 3.5 TWh of gas to approximately 0.25 million electricity and gas customers in the Netherlands.
Italy. Sales activities in Italy are conducted through E.ON Italia (electricity) and Dalmine (electricity and
gas). Both focus on industrial customers and local utilities. Both companies were handed over to the new market
unit Italy on January 1, 2008. In 2007, E.ON Italia supplied 3.9 TWh of electricity and Dalmine supplied
approximately 4.2 TWh of electricity and approximately 13.0 TWh of gas.
Trading
Until the end of 2007, EST, the integrated wholesale and trading organization of E.ON Energie AG, was
responsible for E.ON’s power and emission trading in the Central European market unit. In early 2008, E.ON
started to integrate all of its European trading activities in a single entity, EET, which was formed out of EST.
For information about EET, see “— New Market Units — Energy Trading” above.
EST traded electricity on the spot and forward markets and offered customized and standard products that
were traded on a bilateral basis, as well as trading in standard exchange-traded instruments. EST’s trading
focused on Germany and continental Europe, including important European power exchanges such as the
European Energy Exchange in Leipzig, the Amsterdam Power Exchange in the Netherlands, Powernext in France
and the Energy Exchange Austria. EST also supplied cross border trading and risk management processes for
optimizing international power procurement to E.ON Energie’s operations in Eastern Europe and was the
procurer for E.ON Energie’s operations in Italy. As the central trading desk of the E.ON Energie group, EST was
also responsible for CO2 emissions trading. For further information on CO2 emissions trading, see
“— Regulatory Environment — EU/Germany: General Aspects (Electricity and Gas).” The volume of CO2
emission certificates traded by EST decreased from 15.1 million tons in 2006 to 10.6 million tons in 2007,
reflecting reduced liquidity in the market in the final months of the EU scheme’s initial period.
The volume of EST’s energy trading activities decreased in 2007, reflecting lower market price volatility,
especially during the second and third quarters of the year. The following table sets forth the total volume of
EST’s traded electric power in 2007 and 2006.
Trading of Power
Power sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power purchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
million kWh
2006
million kWh
%
Change
in Total
153,689
210,331
364,020
201,543
222,843
424,386
-23.7
-5.6
-14.2
Other
Consulting and Support Services. E.ON Engineering GmbH offers internal and external consulting, planning
and construction services in the energy sector in fields such as chemical analytics and electrical, mechanical and
civil engineering, with a focus on conventional and renewable power generation, cogeneration, use of biomass,
pipeline construction, development of energy strategies and CO2-emissions reduction. Building on their
shareholdings in municipal and regional utilities, E.ON Energie and the regional distributors also establish
partnerships and cooperative relationships with local authorities. E.ON Energie and the regional distributors
operate their own electricity and gas supply systems, and provide the local authorities with consulting, technical
105
and managerial support to promote the efficient use of electricity and gas. E.ON Facility Management GmbH
provides technical, commercial and infrastructural facility management services, mainly for E.ON Energie group
companies. E.ON IS GmbH (“E.ON IS”) is the provider for all information technology services needed in the
E.ON Group. The company also offers information technology services for third parties. E.ON IS is whollyowned by the E.ON Group.
Other Minority Shareholdings. In the Alpine region, E.ON Energie owns a 21.0 percent equity interest and
20.0 percent voting interest in BKW FMB Energie AG, an integrated Swiss utility that owns important
hydroelectric assets, as well as a single nuclear power station and interests in other nuclear power stations.
Eastern Europe
E.ON Energie has significant shareholdings in Hungary, the Czech Republic, Bulgaria, Romania and Slovakia.
In Eastern Europe, E.ON Energie’s power generation facilities have a total installed capacity of approximately 540
MW, E.ON Energie’s attributable share of which is approximately 350 MW. National holding companies such as
E.ON Hungária Energetikai ZRt. (“E.ON Hungária”), E.ON Czech Holding AG, E.ON Bulgaria EAD and E.ON
Energie România S.A. (“E.ON Energie România”) coordinate E.ON Energie’s activities in the region.
The following table summarizes the most significant shareholdings in each of the specific countries:
Hungary
E.ON Hungária Energetikai ZRt.
Debreceni Kombinált Ciklusú Erömü Kft.
Nyíregyházi Kombinált Ciklusú Erömü Kft
E.ON Energiatermelö Kft.
E.ON Dél-dunántúli Áramszolgáltató ZRt.
E.ON Észak-dunántúli Áramszolgáltató ZRt.
E.ON Tiszántúli Áramszolgáltató ZRt.
E.ON Középdunántúli Gázszolgáltató ZRt.
E.ON Dél-dunántúli Gázszolgáltató ZRt.
E.ON Energiakereskedő Kft.
E.ON Energiaszolgáltató Kft.
E.ON Hálózati Szolgáltató Kft.
E.ON Ügyfélszolgálati Kft.
E.ON Gazdasági SzolgáltatóKft.
Czech Republic
E.ON Czech Holding AG
Teplárna Otrokovice a.s.
E.ON Distribuce, a.s.
Jihoceská plynárenská Distribuce, s.r.o.
E.ON Energie, a.s.
E.ON Ceská republika, s.r.o.
Bulgaria
E.ON Bulgaria EAD
E.ON Bulgaria Grid AD
E.ON Bulgaria Sales AD
Romania
E.ON Energie România S.A.
E.ON Moldova Distributie S.A.
E.ON Moldova Furnizare S.A.
Slovakia
Západoslovenská energetika a.s. (ZSE)
Business
Shareholding(1)
Holding
Power and heat generation
Power and heat generation
Diverse small power generation units
Power distribution
Power distribution
Power distribution
Gas distribution and sales
Gas distribution and sales
Sales of power and gas for customers
open to competition
Sales of power and gas for quasiregulated customers (USP-segment)
Network services
Customer services
Business services
100%
100%
100%
100%
100% (except for a “golden share”)
100% (except for a “golden share”)
100% (except for a “golden share”)
99.6%
99.9%
100%
100%
100%
100%
Holding
Power and heat generation
Power distribution
Gas distribution
Sales of power and gas
Services
100%
66.0%
100%
100%
100%
100%
Holding & Services
Power distribution
Sales of power
100%
67.0%
67.0%
Holding
Power distribution
Sales of power
90.2%
51.0%
51.0%
Distribution and sales of power
49.0%
100%
(1) The minority shareholdings listed are those in which E.ON Energie has a direct interest.
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In Hungary, E.ON Hungária provided 2.5 million customers with approximately 16.1 TWh of electricity in
2007. In the gas sector, E.ON Középdunántúli Gázszolgáltató ZRt. (“KÖGÁZ”) and E.ON Dél-dunántúli
Gázszolgáltató ZRt. (“DDGÁZ”) provided approximately 0.6 million customers with approximately 12.7 TWh of
gas. As of February 1, 2007, E.ON Hungária completed a reorganization to fulfill legal unbundling requirements.
Business administration services are now in the newly-founded company E.ON Gazdasági Szolgáltató Kft., while
the newly-founded companies E.ON Ügyfélszolgálati Kft. and E.ON Hálózati Szolgáltató Kft. handle customer
services and network services, respectively. Until August 2007, all sales activities were carried out by E.ON
Energiakereskedö Kft. Due to a requirement of the new Hungarian energy legislation, as of September 1, 2007
E.ON Hungária put into operation the newly founded E.ON Energiaszolgáltató Kft. to take care of the universal
service provided customers (“USP”, a quasi-regulated segment) in the electricity as well as gas segment. As of
September 1, 2007, E.ON Hungária’s five electricity and gas distributors transferred their retail customers to
E.ON Energiaszolgáltató Kft.
In the Czech Republic, E.ON Energie controls significant participations in the energy sector. As of
January 1, 2005, E.ON Energie fulfilled legal unbundling requirements by creating three wholly-owned
subsidiaries, E.ON Ceská republika, s.r.o., E.ON Distribuce, a.s. and E.ON Energie, a.s. On a combined basis,
these companies provided approximately 1.4 million customers with approximately 11.4 TWh of electricity in
2007. In January 2007, E.ON Energie received the remaining 1.0 percent interest of JCP from a squeeze-out. In
July 2007, JCP was integrated into the structure of E.ON Energie a.s.
As of January 1, 2007, the legal unbundling requirements in Bulgaria were fulfilled through the foundation
of E.ON Bulgaria Sales AD, which is now the sales company for the entire territory of northeastern Bulgaria, and
E.ON Bulgaria Grid AD, which is now the distribution company for the entire territory of northeastern Bulgaria.
The sales and distribution businesses of each of the former companies of Elektrorazpredelenie Varna AD
(“Varna”) and Elektrorazpredelenie Gorna Oryahovitza AD (“Gorna Oryahovitza”) were integrated into these
companies. In 2007, the E.ON Bulgaria Group effected annual sales for about 5.0 TWh and provided electricity
to approximately 1.1 million customers.
In September 2005, E.ON Energie acquired a 24.6 percent stake in the Romanian electricity distribution
company Electrica Moldova S.A. (“Electrica Moldova”) — renamed E.ON Moldova S.A. (“E.ON Moldova”) —
and simultaneously increased its stake in the company to 51.0 percent by subscribing to a capital increase. In
March, 2007, E.ON Energie România — at that time a fully owned subsidiary of E.ON Energie Group — and
E.ON Energie AG agreed to transfer the shares held by E.ON Energie AG in E.ON Moldova S.A. to E.ON
Energie România. E.ON Energie România is the new holding company for the activities of the E.ON Energie
Group in Romania. According to the EU Directive, which imposes the legal unbundling of power distribution
and supply, the electricity supply activity of E.ON Moldova S.A. has been legally transferred to the newly
established E.ON Moldova Furnizare S.A. in April, 2007. As a result of these restructuring activities, E.ON
Energie România holds 51.0 percent of E.ON Moldova Furnizare S.A. and 51.0 percent of E.ON Moldova
Distributie S.A. (the former E.ON Moldova S.A., renamed after spin-off of the sales activities). In October, 2007
E.ON Energie AG sold a stake of 9.8 percent of E.ON Energie România to the European Bank for
Reconstruction and Development (EBRD). In Romania, E.ON Moldova Furnizare S.A. and E.ON Moldova
Distributie S.A. sold approximately 3.1 TWh of electricity to approximately 1.4 million customers in 2007.
In Slovakia, Západoslovenská energetika a.s. (“ZSE”) provided approximately 0.9 million customers with
approximately 8.1 TWh of distributed electricity and 8.0 TWh of supplied electricity in 2007. As of July 2007,
ZSE fulfilled legal unbundling requirements by creating two wholly-owned subsidiaries: ZSE Distribucia a.s. for
power distribution and ZSE Energia a.s. for power retail.
Competitive Environment
Since 1998, liberalization of the electricity markets in the EU has greatly altered competition in the German
electricity market, which was formerly characterized by numerous strong competitors. Following liberalization,
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significant consolidation has taken place in the German market, resulting in three mergers of major interregional
utilities in recent years: VEBA and VIAG forming E.ON, RWE and Vereinigte Elektrizitätswerke AG forming
RWE (both in 2000) and Hamburgische Electricitäts-Werke AG/Bewag Berliner Kraft und Licht
Aktiengesellschaft/VEAG Vereinigte Energiewerke Aktiengesellschaft/Lausitzer Braunkohle Aktiengesellschaft
forming Vattenfall Europe in 2002. In 2007, E.ON, RWE, Vattenfall Europe and the other remaining major
interregional utility, EnBW, supplied approximately 70 percent of the total electricity production in Germany.
The interregional utilities own the high-voltage transmission lines in their traditional supply areas and are
active in all phases of the electricity business. In addition to the interregional utilities, there are about 900 electric
utilities in Germany at the state, regional and municipal level, many of which are partly or wholly owned by state
or municipal governments. These utilities may be involved in various combinations of the generation,
transmission, distribution and supply and trading functions. The liberalization of the electricity market in
Germany has also led to new market structures with new market participants. The market for electricity has
become more liquid and more competitive, and currently has the highest number of participants in continental
Europe. Approximately 200 new market participants have entered the German market since 1998, with more than
half of them engaged in electricity trading. The volume of electricity trading rose in 2007 (1,273 TWh at the
European Energy Exchange’s Spot and Futures Market compared with 1,133 TWh in 2006; a 12 percent
increase). The European Energy Exchange has also become a benchmark for electricity prices in central Europe.
Liberalization of the electricity market in Germany caused wholesale and consequently end customer
electricity prices to decrease in 1998, with significant declines in some market segments. These declines were
largely due to aggressive price setting by new competitors and suppliers, as well as other factors such as
significant power plant overcapacity in Germany and Europe and relatively high and increasing price
transparency. The rate of price declines began to slow in the second half of 2000, and prices have increased since
2001 but have developed differently in each of the customer segments. According to the German Energy
Association, BDEW, in 2007 prices paid by household customers were about 21 percent higher than in the
liberalization year 1998, while prices (including electricity tax) paid by industrial customers were about 22
percent higher than in 1998. However, when all applicable taxes are excluded from the comparison, 2007 prices
were approximately 5 percent lower than those in 1998 for household customers and approximately 1 percent
lower for industrial customers. In 2007, wholesale electricity prices in Germany stayed at a high level. Some
industrial customers were affected by the high wholesale prices, but others had already locked in lower prices in
earlier years. For this reason, the wholesale price increases did not affect the industrial customer segment to the
same degree as household customers, who generally paid higher prices in 2007.
In addition to the effect of higher wholesale market prices, a significant factor in the overall price recovery
are new or increased costs faced by electricity companies since the beginning of liberalization. Among these new
or increased costs are the electricity tax (introduced in 1998 and subject to annual increases through 2003), duties
and additional costs attributable to compliance with new legislation, including the Renewable Energy Source Act
and Combined Heat and Power Act, as well as higher costs incurred in procuring balancing power to cover
fluctuations in the availability of electricity from renewable resources such as wind. Most distributors have tried
to pass these increases through to their customers. Taxes and duties accounted for approximately 41 percent of
German electricity prices for household customers in 2007, compared with about 25 percent before deregulation
in 1998. Similarly, electricity taxes and duties increased from 2 percent of German electricity prices for industrial
customers in 1998 to almost 21 percent in 2007. E.ON Energie’s German regional utilities, as well as other
competitors, announced in October 2007 further price increases for end customers to be effective in 2008.
However, these price changes for end customers depend on the wholesale market prices for electricity. The most
significant effects in this regard derive from the strong increase in procurement costs owing to the global rise in
demand for energy. Subsidies for renewables-based energy are also having an impact on electricity prices,
resulting in substantial additional burdens. For information about court proceedings on price increases affecting
some of E.ON Energie’s majority-owned regional distribution companies, see “Risk Factors.”
High environmental and nuclear safety standards, as well as high investments in new power plants, taxes on
electricity, the requirements of the Co-Generation Protection Law and the Renewable Energy Law’s requirement
108
that regional utilities purchase electricity generated from renewable resources impose a considerable burden on
German electricity prices for end customers. E.ON Energie still believes that it will be able to compete
effectively in Germany. In addition, E.ON Energie believes that the liberalization of the gas and electricity
markets may open new business opportunities. However, E.ON Energie may be unable to compete as effectively
as other electricity companies due to the factors described above, as well as due to regulatory changes described
in “— Regulatory Environment.” Any of these or other factors could materially and adversely affect E.ON’s
financial condition and results of operations. See also “Risk Factors.”
Outside Germany, the energy markets in which E.ON Energie operates are also subject to strong
competition. In the countries of Eastern Europe where E.ON Energie has operations, full liberalization of the
electricity and gas sales markets should have been formally realized by July 1, 2007 under the Directive
2003/54/EC Concerning Common Rules for the Internal Market in Electricity (“Second Electricity Directive”)
and Directive 2003/55/EC Concerning Common Rules for the Internal Market in Natural Gas and Repealing
Directive 98/30/EC (“Second Gas Directive”). This may alter competition in these electricity and gas markets,
which could lead to decreasing end customer prices or to a loss of market shares. E.ON Energie cannot guarantee
it will be able to compete successfully in electricity and gas markets where it already is present or in new
electricity and gas markets it may enter.
Pan-European Gas
Overview
E.ON Ruhrgas is the lead company of the Pan-European Gas market unit and is responsible for all of
E.ON’s non-retail gas activities in continental Europe. In terms of sales, E.ON Ruhrgas is one of the leading
non-state-owned gas companies in Europe and the largest gas company in Germany. E.ON Ruhrgas’ principal
business is the supply, transmission, storage and sale of natural gas. E.ON Ruhrgas also holds numerous stakes in
German and other European gas transportation and distribution companies, as well as a small shareholding in
Gazprom, Russia’s main natural gas exploration, production, transportation and marketing company. In 2007, the
Pan-European Gas market unit recorded revenues of €22.7 billion and adjusted EBIT of €2.6 billion. €13.7
billion of the Pan-European Gas market unit’s 2007 revenues were generated in Germany and €9.0 billion was
generated abroad (measured by location of customer).
In 2001, E.ON concluded contracts for the purchase of significant shareholdings in Ruhrgas with BP p.l.c.
(“BP”) and Vodafone Group Plc (“Vodafone”). E.ON also reached an agreement in principle with RAG
Aktiengesellschaft (“RAG”) to acquire its Ruhrgas stake. In January and February 2002, the German Federal
Cartel Office blocked the consummation of the transactions with the aforementioned parties on the grounds that
the proposed purchase would have a negative effect on competition in the German gas and electricity markets.
E.ON appealed the decision to the German Federal Ministry for Economics and Labor (now renamed the Federal
Ministry for Economics and Technology) (Bundesministerium für Wirtschaft und Technologie), which has the
power to overrule the Cartel Office if it determines a transaction would result in an overriding general benefit to
the German economy.
Between May and July 2002, E.ON reached agreements with ThyssenKrupp AG, Esso Deutschland GmbH,
Deutsche Shell GmbH and TUI AG with respect to E.ON’s acquisition of each company’s respective stake in
Ruhrgas. E.ON also reached a definitive agreement with RAG to acquire RAG’s more than 18 percent interest in
Ruhrgas and to sell E.ON’s majority interest in Degussa to RAG in a two-step transaction. The successful
completion of each of these arrangements would make E.ON the sole owner of Ruhrgas.
In July 2002, E.ON was granted the ministerial approval it had requested for the acquisition of a majority
shareholding in Ruhrgas. The ministerial approval was linked with stringent requirements designed to promote
competition in the gas sector. Ruhrgas was required to auction a specified volume of natural gas to its
109
competitors and to legally unbundle its transmission system from its other operations. In addition, E.ON and
Ruhrgas were required to divest several shareholdings. E.ON immediately completed the acquisition of 38.5
percent of Ruhrgas from BP, Vodafone and ThyssenKrupp AG.
A number of companies with alleged interests in the German energy industry filed complaints against the
ministerial approval with the State Superior Court (Oberlandesgericht) in Düsseldorf and petitioned the court to
issue a temporary injunction blocking the transaction. The court subsequently issued a series of orders in July,
August and September 2002 that temporarily enjoined the Company’s acquisition of a majority stake in Ruhrgas
and prohibited the Company from exercising its shareholders’ rights with respect to the Ruhrgas stake it had
already acquired.
In September 2002, Germany’s Federal Minister of Economics confirmed the essential aspects of the July 5
ministerial approval for E.ON’s acquisition of Ruhrgas. However, the ministry linked its decision to a tightening
of the requirements. Ruhrgas was also required to sell its stakes in two regional gas companies, and each of the
companies required to be disposed of was granted a special right to terminate its existing purchase agreements
with E.ON and Ruhrgas on a staggered basis. In addition, customers purchasing a majority of their gas
requirements from Ruhrgas were granted the right to unilaterally reduce the contracted volumes, and Ruhrgas
was required to auction 200 billion kWh of natural gas to its competitors, with the minimum bid in such auctions
being lower than the average border-crossing price. The approval also provided that the ministry has the right to
take further action in the event of any sale by E.ON of a controlling interest in E.ON Ruhrgas or a change in
control over E.ON. On this basis, the ministry asked the State Superior Court to lift its temporary injunction.
E.ON and E.ON Ruhrgas have complied with all of the conditions imposed by the ministerial approval.
In December 2002, the State Superior Court decided not to lift the temporary injunction, and formal
proceedings (Hauptverfahren) regarding the injunction began in January 2003. On January 31, 2003, E.ON
reached settlement agreements with all plaintiffs who had contested the validity of the ministerial approval. In
accordance with these agreements, E.ON exchanged shareholdings with certain plaintiffs and agreed to enter into
gas and/or electricity supply contracts, make certain infrastructure improvements (particularly with regard to gas
distribution), and provide specified access to the gas and electricity supply grids, with others, as well as agreeing
to make other financial payments to the plaintiffs. In addition, Ruhrgas reconfirmed to all the parties its
commitment to open and fair competition in the gas market.
In March 2003, E.ON acquired the remaining shares of Ruhrgas. The total cost of the transaction to E.ON,
including settlement costs and excluding dividends received on Ruhrgas shares owned by E.ON prior to its
consolidation, amounted to €10.2 billion. Beginning as of February 1, 2003, E.ON fully consolidated Ruhrgas,
which was renamed E.ON Ruhrgas on July 1, 2004.
Upon termination of the court proceedings, the Company completed the first step of the RAG/Degussa
transaction, i.e., the Company acquired RAG’s Ruhrgas stake for total consideration of €2.0 billion, and E.ON
tendered 37.2 million of its shares in Degussa to RAG at the price of €38 per share, receiving total proceeds of
€1.4 billion. Following this transaction and the completion of the subsequent mandatory tender offer to the other
Degussa shareholders, RAG and E.ON each held a 46.5 percent interest in Degussa, with the remainder being
held by the public. In the second step of the transaction, E.ON sold a further 3.6 percent of Degussa’s stock to
RAG with effect from June 1, 2004, giving RAG a 50.1 percent interest in Degussa. Total proceeds from the sale
of this 3.6 percent stake amounted to €283 million. In December 2005, E.ON and RAG signed a framework
agreement on the sale of E.ON’s remaining 42.9 percent stake in Degussa to RAG. As part of the implementation
of that framework agreement, E.ON transferred its stake in Degussa to RAG Projektgesellschaft mbH (“RAG
Projektgesellschaft”) in March 2006 and agreed on the forward sale of that entity to RAG for a purchase price of
€2.8 billion (equal to €31.50 per Degussa share). The transaction closed in July 2006. As a result, E.ON no
longer holds any equity interest in Degussa.
110
In 2007, E.ON Ruhrgas entered into the following significant transactions:
•
In June 2007, E.ON Ruhrgas AG participated in the creation of a joint venture to plan a new European
gas pipeline in Scandinavia. This Skanled pipeline is to transport Norwegian gas to Norway, Sweden
and Denmark. With a 15 percent stake, E.ON Ruhrgas is one of the largest partners in the joint venture,
in which a total of 10 companies from Norway, Sweden, Denmark and Poland are involved. The total
investment for the pipeline is currently estimated at €1.3 billion on the basis of an updated design
incorporating developments in the materiel procurement and construction markets. A final decision on
construction of the pipeline is to be taken by the end of 2009. If constructed, the pipeline is then
expected to come into operation by 2012 at the latest.
•
In August 2007, E.ON Ruhrgas acquired (through its subsidiary E.ON Ruhrgas Norge AS) an
approximately 28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from Shell, with
retroactive effect to January 1, 2007. E.ON Ruhrgas Norge AS’ share of the investments for developing
these fields is expected to be around $1.4 billion (around €1.0 billion). Skarv and Idun are both located
in the northern Norwegian Sea, just below the Arctic Circle. Skarv-Idun is thought to be among the most
attractive undeveloped gas fields in Norway as the area has significant potential for reserves growth
through further exploration. Gas production is expected to start in 2011.
Operations
Through E.ON Ruhrgas AG and its subsidiaries, E.ON Ruhrgas is primarily engaged in the following
segments of the gas industry:
Supply:
The purchase of natural gas under long-term contracts with foreign and
domestic producers, including the Russian gas company Gazprom, the world’s
largest gas producer in terms of volume, in which E.ON Ruhrgas holds a small
shareholding. E.ON Ruhrgas also engages in gas exploration and production
activities and, to supplement its supply as well as its sales business and until
they will be taken over by EET, in a limited amount of trading activities;
Transmission:
The transmission of gas within Germany via a network of approximately
11,611 km of pipelines in which E.ON Ruhrgas holds an interest;
Storage:
The storage of gas in a number of large underground natural gas storage
facilities; and
Sales:
The sale of gas within Germany to supraregional and regional distributors,
municipal utilities and industrial customers, as well as sales to a number of
customers in other European countries.
In addition to its natural gas supply, transmission, storage and sales businesses, E.ON Ruhrgas owns
numerous shareholdings in integrated gas companies, gas distribution companies and municipal utilities through
its subsidiaries E.ON Ruhrgas International AG (“ERI”) and Thüga Aktiengesellschaft (“Thüga”). ERI holds
both majority and minority shareholdings in German and European energy companies, while Thüga holds
primarily minority shareholdings in 93 regional and municipal electricity and gas utilities in Germany, as well as
majority and minority shareholdings in a number of Italian gas distribution and sales companies.
For financial reporting purposes, the Pan-European Gas market unit is divided into three business units:
Up-/Midstream, Downstream Shareholdings and Other/Consolidation. The Up-/Midstream business unit reflects
the results of the supply, transmission, storage and sales businesses, with the midstream operations essentially
including all of the supply and sales businesses other than exploration and production activities. The Downstream
Shareholdings business unit reflects the results of ERI and Thüga. Other/Consolidation includes consolidation
effects.
111
Up-/Midstream
The following table provides information about purchases and sales of natural gas and coke oven gas by
E.ON Ruhrgas’ midstream operations for the years 2007 and 2006. The difference between gas supplies and gas
sales in any given period is due to storage and metering differences and occurs routinely.
Purchases
Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
German sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales
Domestic distributors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Domestic municipal utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Domestic industrial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales abroad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total 2007
billion kWh
%
Total 2006
billion kWh
%
570.8
127.0
697.8
81.8
18.2
100.0
609.9
113.3
723.2
84.4
15.6
100.0
292.5
169.8
70.1
180.4
712.8
41.1
23.8
9.8
25.3
100.0
318.7
163.1
67.6
160.3
709.7
44.9
23.0
9.5
22.6
100.0
In the table above, as well as in the descriptions of E.ON Ruhrgas’ supply and sales businesses, purchase
and sales volumes are presented for all periods excluding relatively small amounts of gas that E.ON Ruhrgas
does not consider part of its primary business, including volumes handled for third parties. In addition, these gas
volumes do not include gas volumes attributable to ERI or Thüga, which are part of the Downstream
Shareholdings business unit.
The increase in total sales volume in 2007 was primarily attributable to an increase in sales abroad,
especially to customers in the Netherlands, Denmark and the United Kingdom. For more information on E.ON
Ruhrgas’ gas supply contract with E.ON Sverige, see “— Nordic — Operations.”
Supply
E.ON Ruhrgas purchases nearly all of its natural gas from producers in six countries: Russia, Norway, the
Netherlands, Germany, the United Kingdom and Denmark. In 2007, E.ON Ruhrgas purchased a total of 690.5
billion kWh of gas, of which approximately 81.8 percent was imported and approximately 18.2 percent was
purchased from German producers. E.ON Ruhrgas was the largest gas purchaser in Germany in 2007, acquiring
more than half of the total volume of gas purchased for the German market. Of the 697.8 billion kWh of gas
purchased in 2007, E.ON Ruhrgas bought approximately 25.5 percent from Russia and approximately 25.0
percent from Norway, its two largest suppliers. The following table provides information on the amount of gas
purchased from each country and its percentage of the total volume of gas purchased by the midstream
operations in the years 2007 and 2006:
Sources of Gas
Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Norway . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The Netherlands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Denmark . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Others(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1) Italy, France, Austria, Hungary and Slovakia.
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Total 2007
billion kWh
%
Total 2006
billion kWh
%
127.1
178.0
174.7
120.3
68.2
20.8
8.7
697.8
18.2
25.5
25.0
17.2
9.8
3.0
1.3
100.0
113.3
178.4
196.5
137.5
67.2
22.9
7.4
723.2
15.6
24.7
27.2
19.0
9.3
3.2
1.0
100.0
In the table above, purchase volumes are presented for all periods excluding relatively small amounts of gas
that E.ON Ruhrgas does not consider part of its primary supply business, including volumes handled for third
parties. In addition, these gas volumes do not include gas volumes attributable to ERI or Thüga.
As is typical in the gas industry, these purchases were primarily made under long-term supply contracts that
E.ON Ruhrgas has with one or more gas producers in each country. Purchases under such contracts provided for
nearly all of the gas bought by E.ON Ruhrgas in 2007; the remaining amounts were purchased on international
spot markets or pursuant to short-term contracts. E.ON Ruhrgas’ current long-term contracts with fixed terms
(so-called “supply”-type contracts) have termination dates ranging from 2008 to 2036 (subject in certain cases to
automatic extensions unless either party gives notice of termination), while so-called “depletion”-type contracts
terminate upon the exhaustion of economic production from the relevant gas field. E.ON Ruhrgas believes that
its existing contracts secure the supply of a total volume of approximately 12.5 trillion kWh of natural gas over
the period to 2036. As is standard in the gas industry, the price E.ON Ruhrgas pays for gas under these contracts
is calculated on the basis of complex formulas incorporating variables based upon current market prices for fuel
oil, gas oil, coal and/or other competing fuels, with prices being automatically re-calculated periodically, usually
monthly or quarterly. The contracts also generally provide for formal revisions and adjustments of the price or
business terms to reflect changes in the market (in many cases expressly including changes in the retail market
for natural gas and competing fuels), generally providing that such revisions may only be made once every few
years unless the parties agree otherwise. Claims for revision are subject to binding arbitration in the event the
parties cannot agree on the necessary adjustments. Certain contracts also provide E.ON Ruhrgas with the
possibility of buying specified quantities of gas at prices linked to those on international spot markets. The
contracts also require E.ON Ruhrgas to pay for specified minimum quantities of gas even if it does not take
delivery of such quantities, a standard gas industry practice known as “take or pay.” Take-or-pay quantities are
generally set at approximately 80 percent of the firm contract quantities. To date, E.ON Ruhrgas has been able to
avoid the application of these take-or-pay clauses in nearly all cases. The contracts also include quality and
availability provisions (together with related discounts for non-compliance), force majeure provisions and other
industry standard terms. E.ON Ruhrgas also has short-term arrangements with some of its suppliers, which
provided less than 3 percent of E.ON Ruhrgas’ gas supply in 2007. E.ON Ruhrgas generally takes delivery of the
gas it imports at the point at which the relevant pipeline crosses the German border. For additional information
on these contractual obligations, see “Operating and Financial Review and Prospects — Contractual
Obligations.”
In the medium and long term, rising demand for gas in Europe, combined with falling indigenous
production in European countries, particularly in the United Kingdom, will lead to a greater reliance on imports
by European gas wholesalers. Accordingly, in the near future, gas producers will have to invest, in some cases
quite considerably, in expanding their production capacities. In addition, the natural decline in output from older
fields will need to be made up by the development of new fields. E.ON Ruhrgas believes that long-term gas
purchase contracts will remain crucial to European gas supplies, ensuring a fair balance of risks between
producers and importers. E.ON Ruhrgas believes the price adjustment provisions in such contracts ensure
sufficient supplies of gas at competitive prices, while the take or pay provisions give producers the necessary
long-term security for investing. For information about risks relating to long-term gas supply contracts, see “Risk
Factors.”
E.ON Ruhrgas’ supply sources are discussed below on a country-by-country basis.
Russia. In 2007, E.ON Ruhrgas purchased 178.0 billion kWh of gas, or 25.5 percent of its total gas
purchased, from Russia. Russia is the largest supplier of natural gas to E.ON Ruhrgas, while E.ON Ruhrgas is the
second-largest purchaser of gas from Russia. As with most of its gas imports, E.ON Ruhrgas takes ownership of
its Russian gas when it reaches the German border.
All of E.ON Ruhrgas’ purchases of Russian natural gas are made pursuant to long-term supply contracts
with OOO Gazexport (now Gazprom export), the subsidiary of Gazprom responsible for exports. E.ON Ruhrgas
holds a 3.5 percent direct interest in Gazprom; an additional stake of 2.9 percent in Gazprom is attributable to
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E.ON Ruhrgas on the basis of contractual arrangements relating to its minority interest in a Russian entity that
holds these shares. E.ON Ruhrgas considers its shareholding in Gazprom to be an important element supporting
its long-term supply relationship with Gazprom, which is the world’s largest gas producer, having produced
approximately 550 billion cubic meters (“m3”) of gas in 2007. E.ON Ruhrgas expects the importance of Russian
gas exports for Europe to increase as the indigenous production of important European supply countries
decreases. Gazprom has indicated it will flexibly cover about one third of E.ON Ruhrgas’ gas requirements for
the German market until 2030. In July 2004, E.ON and Gazprom signed a Memorandum of Understanding for a
deepened strategic cooperation between the parties, pursuant to which E.ON, Gazprom and BASF AG signed a
basic agreement on the construction of the Nord Stream pipeline from Vyborg, Russia to Greifswald, Germany
through the Baltic Sea. For details, see “— Transmission and Storage — Pipelines.”
In August 2006, E.ON Ruhrgas and Gazexport (now Gazprom Export) finalized a series of agreements in
Moscow. These agreements, which comprise extensions of existing contracts and a new supply contract, provide
for the delivery of an aggregate of approximately 400 billion cubic meters (“m3”) of gas through 2036, and E.ON
believes that these contracts represent an important contribution towards safeguarding long-term European gas
supplies. The two companies signed 15-year extensions of the existing contracts with Waidhaus, Germany as
delivery point through 2035, as well as a new supply contract for additional gas to be delivered via the Nord
Stream pipeline from 2010/2011 onwards.
Norway. In 2007, E.ON Ruhrgas purchased 174.7 billion kWh, or 25.0 percent of its total gas purchased,
from Norwegian sources. E.ON Ruhrgas has supply contracts with a number of major Norwegian and
international energy companies (as well as its subsidiary E.ON Ruhrgas Norge AS) that hold concessions for the
exploitation of Norwegian gas fields. Some of the contracts are of the “depletion”-type while others are
“supply”-type contracts. E.ON Ruhrgas takes delivery of its Norwegian supplies mainly at the gas import points
near Emden along the German North Sea coast.
The Netherlands. In 2007, E.ON Ruhrgas purchased 120.3 billion kWh, or 17.2 percent of its total gas
purchased, pursuant to a single long-term supply contract with GasTerra B.V. This contract provides E.ON
Ruhrgas with a certain degree of flexibility in managing its supply portfolio. E.ON Ruhrgas believes such
flexibility is particularly important in this case, as the Dutch gas fields are relatively close to the end consumers
in E.ON Ruhrgas’ markets, making it more economically viable for E.ON Ruhrgas to react to changes in market
demand by varying contract quantities. E.ON Ruhrgas takes delivery of Dutch gas at the German border.
Germany. In 2007, E.ON Ruhrgas purchased 127.1 billion kWh, or 18.2 percent of its total gas purchased,
from domestic gas production companies. E.ON Ruhrgas has long-term supply contracts for German natural gas
with ExxonMobil Gas Marketing Deutschland GmbH (formerly Mobil Erdgas-Erdöl GmbH), ExxonMobil Gas
Marketing Deutschland GmbH & Co. KG (50 percent of the gas trading business of BEB Erdgas und Erdöl
GmbH (“BEB”)), Shell Erdgas Marketing GmbH & Co. KG (the other 50 percent of the gas trading business of
BEB), Gaz de France Produktion Exploration Deutschland GmbH (formerly Preussag Energie GmbH) and RWE
Dea AG. The majority of the contracts provide E.ON Ruhrgas with significant additional flexibility by providing
for the supply of minimum and maximum quantities of gas, rather than a single fixed amount. E.ON Ruhrgas
expects the volume of gas it purchases from domestic sources to decline over the coming years due to the
depletion of German gas fields.
United Kingdom. In 2007, E.ON Ruhrgas purchased 68.2 billion kWh, or 9.8 percent of its total gas
purchased, from U.K. sources. These quantities were partly purchased from BP Gas Marketing Ltd under a longterm supply contract, partly purchased on the spot short-term market and partly received as “equity gas” through
E.ON Ruhrgas’ subsidiary E.ON Ruhrgas UK Exploration and Production Limited (“E.ON Ruhrgas UK”), which
has interests in U.K. gas fields and infrastructure. See “— Exploration and Production” below for more
information on E.ON Ruhrgas UK.
In contrast to much of its other imported gas, which E.ON Ruhrgas generally takes ownership of at the
German border, E.ON Ruhrgas takes delivery of its purchased U.K. gas supplies partly at Bacton and Easington
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terminals in the United Kingdom and partly at Zeebrugge terminal in Belgium. Gas from the U.K. gas fields is
transported to Belgium through the undersea gas pipeline run by the project company Interconnector (U.K.)
Limited (“Interconnector”).
Denmark. In 2007, E.ON Ruhrgas purchased 20.8 billion kWh, or 3.0 percent of its total gas purchased,
from the Danish supplier DONG Energy A/S (“DONG”), with which E.ON Ruhrgas has long-term supply
contracts. E.ON Ruhrgas takes delivery of Danish gas at the German-Danish and Swedish-Danish border.
Gas Release Program of E.ON Ruhrgas. In accordance with the obligations set out in the ministerial
approvals mandating the auctioning of an aggregate amount of 200 billion kWh of baseload gas, on May 10,
2007, E.ON Ruhrgas offered approximately 33 billion kWh of natural gas from its portfolio of long-term supply
contracts in the fifth of six internet-based annual auctions. Approximately 33 million kWh of gas remains for the
last of these auctions.
Trading
Until the end of 2007, in order to optimize and manage price risks of its long-term gas portfolio, E.ON
Ruhrgas engaged in gas, oil and coal trading. The gas trading activities are concentrated at the national balancing
point in the United Kingdom, at the Zeebrugge hub in Belgium, at the Title Transfer Facility in the Netherlands
and at the Virtuelle Handelspunkte in Germany, and are mainly handled via brokers participating in open markets
and exchanges. Financial, oil and coal trading activities are undertaken mainly for hedging purposes. Proprietary
trading is marginal compared to asset-based trading. In 2008, E.ON Ruhrgas’ trading activities will be transferred
to the new Energy Trading market unit with the transfer becoming effective retroactively as of January 1, 2008.
For information about EET, see “Business — Our Business.”
E.ON Ruhrgas’ total traded gas volume for 2007 was 14.8 percent of total E.ON Ruhrgas sales, as compared
with 10.1 percent in 2006, with the increase being attributable to increased hedging activities reflecting the
expansion of the arbitrage business in the markets in the United Kingdom, Belgium and the Netherlands.
All of E.ON Ruhrgas’ energy trading operations, including its limited proprietary trading, are subject to
E.ON’s risk management policies for energy trading. For additional information on these policies and related
exposures, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about
Market Risk.”
Exploration and Production
E.ON Ruhrgas participates in the exploration and production segment of the gas industry through its gas
production companies in the United Kingdom and in Norway.
United Kingdom. In the United Kingdom, E.ON Ruhrgas operates through its subsidiary E.ON Ruhrgas UK,
which directly and indirectly holds mainly minority shareholdings in a number of gas production fields,
exploration blocks and pipelines in the British North Sea.
In 2007, E.ON Ruhrgas UK acquired interests in two exploration blocks in the central North Sea, as well as
an interest in one additional license obtained within the 24th UK Seaward Licensing Round.
In 2007, the E.ON Ruhrgas UK group produced 8.1 billion kWh (751 million m3) of gas, compared with 7.7
billion kWh (725 million m3) of gas in 2006. The 5.2 percent increase reflects the first full year of gas production
from the Merganser field and the June 2007 start of production of the Minke field. In addition, the E.ON Ruhrgas
UK group produced 2.9 million barrels of liquids (oil and condensate) in 2007, compared with 2.7 million barrels
in 2006. In summer 2007, E.ON Ruhrgas UK had a significant discovery in the Block 22/14b (Huntington) in the
UK central North Sea that is expected to come into production in 2010. The working interest of E.ON Ruhrgas
UK in this Oilexco operated field is 25 percent.
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The following table shows the name of each producing field in which the E.ON Ruhrgas UK group holds an
interest, E.ON’s ownership interest in the field, and the date each field commenced production:
E.ON Ruhrgas UK Group
Name of Producing Field
E.ON Share in %
Ravenspurn North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Caister . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Johnston . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Schooner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Elgin/Franklin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scoter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hunter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Glenelg . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merganser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28.75
40.0
50.107
4.83
5.2
12.0
79.0
18.57
7.9185
42.67
Start-up Date
July 1990
October 1993
September 1994
September 1996
April 2001
December 2003
January 2006
April 2006
December 2006
June 2007
The E.ON Ruhrgas UK group received its share of production from all of the producing fields in which it
owned an interest in 2007.
Norway. E.ON Ruhrgas operates in Norway mainly through its subsidiary E.ON Ruhrgas Norge AS (“E.ON
Ruhrgas Norge”). E.ON Ruhrgas Norge owns 30.0 percent of the Njord oil and gas field. E.ON Ruhrgas Norge
obtained 2.1 million barrels of oil as a result of its stake in 2007 which were sold on the market. The field started
producing gas for sale in December 2007. In January 2007, the Norwegian Ministry of Petroleum and Energy
announced that E.ON Ruhrgas Norge had qualified for operatorship on the Norwegian Continental Shelf, thus
expanding its potential range of business. In August 2007, E.ON Ruhrgas acquired through its subsidiary E.ON
Ruhrgas Norge AS, an approximately 28.1 percent stake in the Norwegian natural gas fields Skarv and Idun from
Shell, with retroacive effect as of January 1, 2007.
Russia. In July 2006, E.ON Ruhrgas and Gazprom signed a framework agreement on the exchange of assets
in the sectors of gas exploration and production as well as gas sales and trading and power. As part of this
agreement, E.ON Ruhrgas is expected to acquire a stake of 25.0 percent minus one share in the company
Severneftegazprom, which holds the exploration and production license for the major Yushno Russkoje gas field
in Siberia. In December 2007, the companies announced that major progress has been made in the negotiations
on an asset swap between Gazprom and E.ON in the framework of which E.ON will acquire a stake in the west
Siberian gas field Yuzhno Russkoye and Gazprom will acquire stakes in E.ON assets in western and central
Europe. In particular, the E.ON assets from which Gazprom will be able to choose shareholdings in western and
central Europe were defined. They include power plants in various western and central European countries, as
well as underground storage facilities. The valuation of these assets still has to be made and, in the event of a
value imbalance between such values and that of the stake in Yuzhno Russkoye, additional assets would have to
be agreed on. The asset swap transaction therefore could not be completed by the time of the inauguration of the
field on December 18, 2007.
Liquefied Natural Gas
Liquefied natural gas (LNG), which is liquefied in the gas producing country, transported by tanker and then
converted back into gas at the receiving terminal, is an alternative to gas deliveries by pipeline. In 2007, E.ON
Ruhrgas completed the front end engineering & design study (a so called FEED) on the construction of an LNG
unloading and regasification terminal on the German North Sea coast near the city of Wilhelmshaven. This
would be Germany’s first such facility. E.ON Ruhrgas has a majority shareholding in DFTG-Deutsche
Flüssigerdgas Terminal Gesellschaft mit beschränkter Haftung (“DFTG”), which it recently increased through
the acquisition of a 12 percent share from BFB Transport GmbH on December 19, 2007 to a total shareholding of
90 percent. DFTG owns the land on which the terminal will be built and holds a valid permit for the construction
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of the terminal, which upon completion could handle as much as 10 billion m³ of natural gas per year. In a
second phase, its capacity could be expanded to 15 billion m³ of natural gas. In August 2007, DFTG issued an
invitation to tender for the turn-key construction of this terminal and in parallel conducted a so called ‘open
season’ to offer regasification capacity to third parties. The implementation of this terminal project will be in line
with E.ON’s strategy of expanding its sources of natural gas with the goal of enhancing and diversifying the
security of its supply. The final investment decision to build the terminal is envisaged for 2008.
A consortium comprising E.ON Ruhrgas (31.15 percent), OMV Gas International (25.58 percent), TOTAL
(25.58 percent), RWE (16.69 percent) and Geoplin, Croatia, (1 percent) has set up the Zagreb-based project
company Adria LNG d.o.o. to build an LNG terminal in Croatia. The new terminal will have an initial
regasification capacity of some 10 billion m³ per year, which can be increased to 15 billion m³ per year. It will be
designed for LNG tankers carrying up to 265,000 m³ of LNG. Once further investigations and planning activities
have been completed, the LNG receiving terminal could be ready to go into operation in 2012. The final
investment decision on this project is expected for 2008 or later.
In May 2007, E.ON Ruhrgas agreed to lease annual regasification capacity of approximately 1.7 billion m³
for the regasification of LNG during phase III of the Isle of Grain LNG terminal project in the UK. The contract
lasts until 2029 and Phase III is due to come onstream in October 2010. Synergies are expected to result from the
possibility of supplying E.ON UK’s Grain power station, which is being built near the Isle of Grain terminal.
In May 2007, E.ON Ruhrgas signed a ‘Heads of Agreement’ for a new LNG terminal project in Le Havre,
France. E.ON Ruhrgas currently owns a 24.5 percent stake in the project company Gaz de Normandie. The new
terminal would have an annual capacity of about 9 billion m³, the E.ON Ruhrgas share being 3 billion m³ per
year. Subject to further studies and planning activities, the LNG terminal could start its commercial operation as
early as 2012.
Transmission and Storage
E.ON Ruhrgas AG’s technical infrastructure in Germany is comprised of pipelines and transport compressor
stations (together, the “transmission system”), as well as underground gas storage facilities (including storage
compressor stations) owned by E.ON Ruhrgas AG, those co-owned directly by E.ON Ruhrgas AG and other gas
companies, and those owned by project companies in which E.ON Ruhrgas AG holds an interest.
Project companies are entities E.ON Ruhrgas AG has set up with German or European gas companies for a
special purpose, such as establishing a pipeline connection between two countries or building and operating
underground gas storage facilities. The following table provides more information on the E.ON Ruhrgas AG
share in each of its German project companies as of December 31, 2007:
E.ON
Ruhrgas Share
%
Project Company
DEUDAN (DEUDAN-Deutsch/Dänische Erdgastransport-Gesellschaft mbH & Co.
Kommanditgesellschaft) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EGL (Etzel Gas-Lager GmbH & Co. KG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GHG (GHG-Gasspeicher Hannover GmbH) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MEGAL (MEGAL Mittel- Europäische-Gasleitungsgesellschaft mbH & Co. KG) . . . . . . . . . . . . .
METG (Mittelrheinische Erdgastransportleitungsgesellschaft mbH) . . . . . . . . . . . . . . . . . . . . . . . .
NETG (Nordrheinische Erdgastransportleitungsgesellschaft mbH & Co. KG) . . . . . . . . . . . . . . . . .
NETRA (NETRA GmbH Norddeutsche Erdgas Transversale & Co. KG) . . . . . . . . . . . . . . . . . . . .
TENP (Trans Europa Naturgas Pipeline Gesellschaft mbH & Co. KG) . . . . . . . . . . . . . . . . . . . . . .
25.0
74.8
13.2
51.0
100.0
50.0
40.6
51.0
The E.ON Ruhrgas AG underground storage facilities are operated by E.ON Ruhrgas AG as storage system
operator. The E.ON Ruhrgas AG transmission system is operated by E.ON Gastransport, a wholly-owned
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subsidiary of E.ON Ruhrgas AG, as transmission system operator. The underground storage facilities and the
transmission system, based on service contracts, are monitored and maintained largely by E.ON Ruhrgas AG.
The transmission system is used to transport the gas that E.ON Ruhrgas and third party customers receive from
suppliers at gas import points on the German border or at other supply points within Germany to customers or to
storage facilities for later use.
In accordance with Germany’s energy law, the transmission system has been leased out to E.ON
Gastransport together with all transmission rights and rights of beneficial use that E.ON Ruhrgas AG possesses in
respect of third party transmission systems in Germany. For more information on this law, see “— Regulatory
Environment — EU/Germany: General Aspects (Electricity and Gas).” For more information on E.ON
Gastransport, see “— E.ON Gastransport” below.
The following map shows the pipelines as well as the location of compressor stations, gas storage facilities
and field stations belonging to E.ON Ruhrgas AG’s technical infrastructure:
E.ON Ruhrgas AG’s Technical Infrastructure
Flensburg
Hamburg
Emden
Berlin
Hanover
Natural gas pipeline
Compressor station
Underground storage facility
Maintenance station
Delivery station
Essen
Cologne
Leipzig
Dresden
Zwickau
Frankfurt/
Main
Waidhaus
Nuremberg
Passau
Stuttgart
Munich
Freiburg
As shown in the map above, E.ON Ruhrgas AG’s transmission system and its underground storage facilities
are located primarily in western Germany, the historical center of E.ON Ruhrgas’ operations.
Pipelines. As of the end of 2007, E.ON Ruhrgas AG owned gas pipelines totaling 6,746 km and co-owned
gas pipelines totaling 1,547 km with other companies. In addition, German project companies in which E.ON
Ruhrgas AG holds an interest owned gas pipelines totaling 3,318 km at the end of 2007.
118
The following table provides more information on E.ON Ruhrgas AG’s pipelines in Germany as of
December 31, 2007:
Pipelines
Total km
Owned by E.ON Ruhrgas AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Co-owned pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DEUDAN (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EGL (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MEGAL (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
METG (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NETG (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NETRA (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
TENP (PC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Companies in which E.ON Ruhrgas AG holds a stake through its subsidiaries
ERI and Thüga . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Owned by third parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total in Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(PC)
Maintained by
E.ON Ruhrgas AG km
6,746
1,547
110
67
1,092
425
285
341
998
6,428
602
0
67
1,092
425
144
106
998
—
—
11,611
2,037
1,043
12,942
project company
E.ON Ruhrgas AG’s share in the use of any particular pipeline it does not wholly own is determined by
contract and is not necessarily related to E.ON Ruhrgas AG’s interest in the pipeline. E.ON Ruhrgas AG’s
pipeline network is comprised of pipeline sections of varying diameters originally built according to the
estimated capacity needed for the relevant section of the system. Currently, the pipeline network comprises
2,019 km of pipelines with a diameter of less than or equal to 300 millimeters, 3,050 km of pipelines with a
diameter of more than 300 and less than or equal to 600 millimeters, 3,040 km of pipelines with a diameter of
more than 600 and less than or equal to 900 millimeters, and 3,502 km of pipelines with a diameter of more than
900 and less than or equal to 1,200 millimeters.
In 2007, E.ON Ruhrgas AG maintained 6,428 km of its own pipelines, 602 km of co-owned pipelines,
1,043 km of pipelines owned by third parties and 2,037 km of pipelines owned by companies in which E.ON
Ruhrgas AG holds a stake through its subsidiaries ERI and Thüga, as well as 2,832 km of pipelines owned by
project companies in which E.ON Ruhrgas AG holds an interest. In total, E.ON Ruhrgas AG maintained
(including providing local monitoring) 12,942 km of pipelines in 2007. For information on pipeline monitoring
and maintenance, see “— Monitoring and Maintenance” below.
In addition to E.ON Ruhrgas AG’s German transmission system, E.ON Ruhrgas has a 23.59 percent interest
in Interconnector, a U.K. project company that owns the Interconnector transmission system, comprising a
235 km undersea gas pipeline from the United Kingdom to Belgium, a transport compressor station at Bacton
(four units with a total installed capacity of approximately 116 MW) and a compressor station at Zeebrugge (four
units with a total installed capacity of approximately 140 MW). On November 9, 2007, E.ON Ruhrgas signed a
share purchase agreement to acquire an additional 1.5 percent interest in Interconnector.
In July 2004, E.ON Ruhrgas acquired a 20.0 percent interest in BBL Company V.O.F., which built a second
undersea transmission system between continental Europe and the United Kingdom. This transmission system
(comprising a 235 km undersea pipeline and a compressor station at Balgzand — three units with a total installed
capacity of approximately 69 MW), which links Balgzand in the Netherlands to Bacton in the United Kingdom,
started operation in December 2006.
E.ON Ruhrgas also owns small stakes in pipeline project companies in Switzerland and Austria.
In July 2007, Gazprom, E.ON Ruhrgas and Wintershall Aktiengesellschaft (“Wintershall”) signed the Final
Shareholders’ Agreement providing for the construction of the Nord Stream pipeline (formerly the North
119
European Gas Pipeline), which is planned to connect Vyborg on Russia’s Baltic coast with Greifswald on the
German Baltic coast, thereby providing an additional undersea route for the supply of Russian natural gas to
Germany, as compared with the current land routes through Ukraine and Poland. The three joint venture partners
have formed the Swiss company Nord Stream AG, in which Gazprom holds a 51.0 percent interest and E.ON
Ruhrgas and Wintershall each hold 24.5 percent stakes. In December 2007, Gazprom signed an umbrella
agreement with N.V. Nederlandse Gasunie regarding Gasunie’s participation in the Nord Stream project.
Gazprom has an option to require that Wintershall and E.ON Ruhrgas each assign up to a 4.5 percent interest in
the company to Gasunie, which will then become the fourth joint venture partner. It is not expected that the first
pipeline could be completed before 2010 at the earliest. The current estimates of E.ON Ruhrgas’ share of the
expected cost of the complete project are in the range of approximately €1.7 billion (assuming that E.ON
Ruhrgas will reduce its stake in Nord Stream to 20 percent).
In June 2007, E.ON Ruhrgas participated in the creation of a joint venture to plan a new European gas
pipeline in Scandinavia. This Skanled pipeline, in which E.ON Ruhrgas has a 15 percent stake, is to transport
Norwegian gas to Norway, Sweden and Denmark. The total investment for the pipeline (of which E.ON expects
to bear a pro rata share) is estimated at €1,300 million according to an updated design incorporating
developments in the markets for the procurement of materials and construction services. A final decision on the
construction of the pipeline is to be taken by the end of 2009.
Compressor Stations. Compressor stations are used to produce the pressure necessary to transport gas
through pipelines and to inject gas into underground storage facilities. E.ON Ruhrgas AG owns or co-owns 15
compressor stations, nine operating for gas transportation purposes (with a total installed capacity of 305 MW),
and six for gas storage purposes (with a total installed capacity of 79 MW). German project companies in which
E.ON Ruhrgas AG holds an interest own an additional 17 transport compressor stations with a total installed
capacity of 592 MW and two storage compressor stations with a total installed capacity of 17 MW. In 2007,
E.ON Ruhrgas AG provided monitoring and maintenance services under service contracts for the nine transport
compressor stations leased out to E.ON Gastransport and 13 transport compressor stations of the project
companies. E.ON Ruhrgas AG also operated, monitored and maintained its six compressor stations operating for
gas storage purposes. The current installed capacity of the compressor stations monitored and maintained by
E.ON Ruhrgas AG totals 908 MW.
The following table provides more information about E.ON Ruhrgas AG’s and its project companies’ gas
compressor stations in Germany as of December 31, 2007:
Owned or Co-owned by
Compressor
Stations
Compressor
Units
Total
Installed
Capacity
MW
Compressor Units
Monitored and
Maintained by
E.ON Ruhrgas AG
Installed Capacity of
Compressor Units
Monitored and
Maintained by
E.ON Ruhrgas AG MW
E.ON Ruhrgas AG (transportation
and storage) . . . . . . . . . . . . . . . . .
DEUDAN (PC) (transportation) . . .
EGL (PC) (storage) . . . . . . . . . . . . .
GHG Hannover (PC) (storage) . . . .
MEGAL (PC) (transportation) . . . .
METG (PC) (transportation) . . . . . .
NETG (PC) (transportation) . . . . . .
NETRA (PC) (transportation) . . . . .
TENP (PC) (transportation) . . . . . .
15
2
1
1
5
2
2
2
4
44
4
2
3
19
11
5
5
15
384
16
13
4
201
131
50
43
151
44
0
0
0
19
11
2
3
15
384
0
0
0
201
131
20
21
151
Total in Germany . . . . . . . . . . . . . .
34
108
993
94
908
(PC)
project company
120
Due to the complexity of the transmission system, together with transmission rights and rights of beneficial
use, as well as the number and complexity of factors influencing pipeline utilization, such as temperature, the
volume of gas transported and the availability of compressor units, no meaningful data on the utilization of the
transmission system is available. E.ON Ruhrgas AG had sufficient pipeline capacity in prior years and booked
sufficient pipeline capacity in 2007. E.ON Ruhrgas AG believes that a shortage of pipeline capacity is not a
material risk in the foreseeable future.
Storage. Underground gas storage facilities are generally used to balance gas supplies and heavily
fluctuating demand patterns. For example, the amount of gas sent out by E.ON Ruhrgas AG on a cold winter day
is roughly four times as high as that on a hot summer day, while the flow of gas produced and purchased is much
more constant. For this reason, E.ON Ruhrgas AG injects gas into storage facilities during warm weather periods
and withdraws it in cold weather periods to cope with peak demand. E.ON Ruhrgas AG stores gas in large
underground gas storage facilities, which are located in porous rock formations (depleted gas fields or aquifer
horizons) or in salt caverns. Underground gas storage facilities consist of an underground section (cavity or
porous rock and wells) and an above-ground part, namely the storage compressor station. As of the end of 2007,
E.ON Ruhrgas AG owned five storage facilities, co-owned another two storage facilities and leased capacity in
two storage facilities in order to meet its gas storage requirements. In addition, E.ON Ruhrgas AG had storage
capacity available through two project companies in which it is a shareholder. Through these owned, co-owned,
leased and project company storage facilities, a working gas storage capacity of approximately 5.3 billion m3 was
available to E.ON Ruhrgas AG in 2007. Due to the number and complexity of factors influencing storage
utilization, particularly temperature and the terms of supply and delivery contracts, E.ON Ruhrgas does not
consider data on the utilization of gas storage capacity to be meaningful. E.ON Ruhrgas AG had sufficient
storage capacity available both in 2007 and in prior years and does not consider a shortage of gas storage
capacity to be a material risk in the foreseeable future. However, depending on a number of factors such as future
gas sent out, E.ON Ruhrgas AG’s gas supply and delivery situation and further gas sales potential in European
countries other than Germany, E.ON Ruhrgas AG intends to increase working gas capacity by enlarging existing
storage facilities, building new facilities and by leasing additional gas storage capacity in the future. In
November 2007, E.ON Ruhrgas AG concluded a contract with IVG Kavernen GmbH to rent storage capacities at
the location of Etzel. The working gas capacity is expected to amount to up to 2.5 billion m³. Commissioning of
the storage facility is planned in stages from 2011 onwards. For information about risks related to the reliability
of gas supplies, see also “Risk Factors.” The following table provides more information about E.ON Ruhrgas
AG’s underground gas storage facilities, all of which are situated in Germany, as of December 31, 2007:
Underground Storage
Facilities
E.ON
Ruhrgas AG’s
Share in
E.ON
Ruhrgas AG’s Maximum
Withdrawal
Share in
Rate
Working
(thousand
Capacity
(3)
(3)
m hour)
(million m
Bierwang(P) . . . . . . . . . . . . . . . . . . . .
Empelde(C) . . . . . . . . . . . . . . . . . . . .
1,360
18
1,200
47
Epe(C) . . . . . . . . . . . . . . . . . . . . . . . .
Eschenfelden(P) . . . . . . . . . . . . . . . . .
Etzel(C) . . . . . . . . . . . . . . . . . . . . . . .
Hähnlein(P) . . . . . . . . . . . . . . . . . . . .
Krummhörn(C)(1) . . . . . . . . . . . . . . . .
Sandhausen(P) . . . . . . . . . . . . . . . . . .
1,761
48
371
80
0
15
2,450
87
987
100
0
23
Stockstadt(P) . . . . . . . . . . . . . . . . . . .
Breitbrunn(P) . . . . . . . . . . . . . . . . . . .
Inzenham-West(P) . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . .
135
992(2)
500
5,280
Owned by
E.ON Ruhrgas AG
GHG-Gasspeicher Hannover
Gesellschaft mbH(PC)
E.ON Ruhrgas AG
E.ON Ruhrgas AG/N-ERGIE AG
Etzel Gas-Lager GmbH & Co. (PC)
E.ON Ruhrgas AG
E.ON Ruhrgas AG
E.ON Ruhrgas AG/Gasversorgung
Süddeutschland GmbH
E.ON Ruhrgas AG
RWE Dea AG/ExxonMobil
Gasspeicher Deutschland GmbH(3)/
E.ON Ruhrgas AG(4)
RWE Dea AG
135
520
300
5,849
121
E.ON
Ruhrgas AG’s
Share in
Storage
Facility or in Operated by
the Project
E.ON
Company % Ruhrgas AG
100.0
13.2
Yes
—
100.0
66.7
74.8
100.0
100.0
50.0
Yes
Yes
—
Yes
Yes
Yes
100.0
Leased(3)
Yes
Yes(4)
Leased
—
(C)
(P)
(PC)
(1)
(2)
(3)
(4)
salt cavern
porous rock
project company
Currently out of service for repairs/adjustments.
992 million m3 is the current working gas capacity available to E.ON Ruhrgas AG.
Underground section.
Above ground part, particularly the storage compressor station.
Monitoring and Maintenance. In 2007, E.ON Ruhrgas AG carried out for itself and under service contracts
for E.ON Gastransport and some of the project companies E.ON Ruhrgas AG holds an interest in, monitoring
and maintenance services for almost all of E.ON Ruhrgas AG’s transmission system and its underground storage
facilities.
Transmission system and underground storage monitoring operations are centered at E.ON Ruhrgas AG’s
and E.ON Gastransport’s dispatching facilities in Essen. Among other tasks, the center keeps the technical
infrastructure under continual surveillance, handles all reports of disturbances in the system and arranges for the
necessary response to any disturbance report. In 2007, E.ON Ruhrgas AG performed this kind of system
monitoring for about 12,900 km of pipelines, 23 transport compressor stations, one storage compressor station
and seven underground storage facilities. Management of operations, general maintenance (including local
monitoring) and troubleshooting are handled by the E.ON Ruhrgas AG field stations and facilities located along
the network. E.ON Ruhrgas AG also deploys mobile units from these stations and facilities to carry out
maintenance and repair work. For certain sections of pipelines, primarily those where no field station or facility
is located nearby, maintenance (including local monitoring) is performed by third parties under service contracts.
E.ON Ruhrgas AG’s dispatching, monitoring and maintenance processes are regularly certified under
International Standards Organization (“ISO”) 9001:2000 (quality management), ISO 14001 (environmental
management), OHSAS 18001, an Occupational Health and Safety Assessment Series for health and safety
management systems (work safety management), and TSM, the Technical Safety Management rules of DVGW
(The German Technical and Scientific Association for Gas and Water). The DVGW is a self-regulatory body for
the gas and water industries, its technical rules serving as a basis for ensuring safety and reliability of German
gas and water supplies.
E.ON Gastransport. On January 1, 2004, E.ON Ruhrgas transferred its gas transmission business to a new
subsidiary, E.ON Ruhrgas Transport, which in mid-2006 was rebranded as E.ON Gastransport. E.ON
Gastransport has sole responsibility for the gas transmission business and functions independently of E.ON
Ruhrgas’ sales business, which is a customer of E.ON Gastransport. As the transmission system operator, E.ON
Gastransport operates, maintains and develops the E.ON Ruhrgas AG transmission system. It handles all major
functions needed for an independent gas transmission business: transmission management (including commercial
transport and hub operations), transportation contracts (including access fees), shipper relations, capacity
planning and allocation, controlling and billing. E.ON Gastransport obtains certain support services from E.ON
Ruhrgas AG under service agreements. On November 1, 2004, E.ON Ruhrgas Transport introduced an entry/exit
system called ENTRIX for access to the E.ON Ruhrgas AG gas transmission system as a result of an agreement
reached with the Competition Directorate-General of the European Commission with respect to a matter that had
been pending before the Competition Directorate. ENTRIX enables customers to book entry and exit capacities
for the transmission of gas separately, in different amounts and at different times. Booked capacities can be
transferred at short notice and combined with capacities of other customers of E.ON Gastransport.
In order to comply with requirements of the Energy Law of 2005 (described in “— Regulatory
Environment”), further improvements of the E.ON Gastransport entry/exit system (now called ENTRIX 2) were
launched in February 2006, giving customers more flexible services and making it possible to book freely
allocable capacities online. The refined, web-based user interface of ENTRIX 2 contains all customer-relevant
information on network access. Screen-based communication has been extended and simplified, serving as a
user-friendly interface for all requests. A major refinement of ENTRIX 2 is the possibility to freely allocate entry
and exit capacities to each other within the four market areas of the E.ON Ruhrgas AG transmission network, so
122
that capacities that are separately booked can be interlinked without any further case-by-case examination. An
additional significant improvement is the replacement of cubic meters per hour as booking unit with kWh per
hour, which makes transmission handling easier for customers.
In order to comply with the new gas network access requirements of Germany’s Energy Law of 2005, the
gas industry negotiated and signed an agreement regarding cooperation between operators of gas supply
networks located in Germany which contains principles for the cooperation of the network operators and standard
terms and conditions for access to networks. The agreement uses one network access model with different market
areas. Within each market area, which each include a number of network subsections, shippers are entitled to
choose the following contractual alternatives for gas transportation: 1) transmission over different networks from
an entry point to an exit point at the end consumer or 2) transmission from an entry point to an exit point within a
network subsection (the so-called “city gate” alternative). E.ON Gastransport adjusted its entry/exit system in
view of the cooperation agreement in October 2006, the date that the new network access model took effect.
Following the development of the gas industry cooperation agreement, a single gas trader and a German
energy association filed claims against three network operators (including E.ON Hanse) which challenged the use
of the city gate alternative. In November 2006, the German energy regulator decided that this contractual
alternative does not comply with the Energy Law of 2005, thus necessitating changes to the existing gas network
operators’ cooperation agreement as well as amendments of E.ON Gastransport’s existing transmission contracts.
E.ON Gastransport implemented all necessary changes ahead of the October 1, 2007 deadline. For more
information, see “— Regulatory Environment — Germany: Gas.”
As from October 2007, E.ON Gastransport will only have two market areas: one for high-calorific gas
(H-gas) and one for low-calorific gas (L-gas). By taking this step, E.ON Gastransport is seeking to improve its
competitive position on the gas market by trying to create a nationwide market area uniting large quantities of
gas from all of Germany’s major international sources. E.ON Gastransport expects its nationwide market area to
be highly liquid and particularly attractive for shippers and gas traders.
The level of transmission fees charged by E.ON Gastransport is determined by a revenue benchmark with
reference to European peer companies and pipeline and transport competition in Germany (a so-called marketbased model for network charges). However, it is possible that the BNetzA will force all gas network operators
applying this market-based model to change to a cost-based model, which would result in a significant reduction
of network charges of such gas network operators. For further details, see “Risk Factors.”
In September 2005, E.ON Ruhrgas Transport received certification for all of its operations under
ISO 9001:2000, ISO 14001 and OHSAS 18001, and in December 2005 received certification under TSM, all of
which were confirmed by a reaudit in 2006.
Sales
Germany. E.ON Ruhrgas was the largest distributor of natural gas in Germany in 2007, selling a total volume
of 532.4 billion kWh of gas. E.ON Ruhrgas also sold 180.4 billion kWh of gas outside of Germany in 2007.
E.ON Ruhrgas sells gas to supraregional and regional distributors, municipal utilities and industrial
customers. Customers are concentrated in the western and southern parts of Germany and the areas around Berlin
and Bremen, although E.ON Ruhrgas potentially serves customers throughout Germany. The following table sets
forth information on the sale of gas by E.ON Ruhrgas’ sales business in Germany for the periods presented:
Total 2007
billion kWh
Sale of Gas to:
%
Total 2006
billion kWh
%
Distributors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipal utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
292.5
169.8
70.1
54.9
31.9
13.2
318.7
163.1
67.6
58.0
29.7
12.3
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
532.4
100.0
549.4
100.0
123
In the table above, sales volumes are presented for all periods excluding relatively minimal amounts of gas
that E.ON Ruhrgas does not consider part of its primary sales business, including volumes handled for third
parties. In addition, these gas volumes do not include gas volumes attributable to ERI or Thüga.
In January 2006, the German Federal Cartel Office issued a decision prohibiting E.ON Ruhrgas from
enforcing its existing long-term gas sales contracts with municipal utilities after October 1, 2006 and from
entering into new sales contracts with those customers that are identical or similar in nature. In justifying its
decision, the Federal Cartel Office contended that the longer-term sales contracts violate German and European
competition law and lead to market foreclosure as they involve long-term customer commitment and typically
account for a large share of municipal utilities’ gas requirements. Accordingly, the Federal Cartel Office ruled
that sales contracts that account for more than 80 percent of any such customer’s requirements may have a
maximum duration of two years, contracts that account for more than 50 percent and up to 80 percent of any such
customer’s requirements may have a maximum duration of four years and contracts that account for up to 50
percent of any such customer’s requirements may have longer durations. In addition, the so-called ban on
participation in competition is to apply: if it already meets part of any such customer’s requirements, E.ON
Ruhrgas is excluded from supplying any additional volume if it would exceed the percentage and duration
criteria described above, even temporarily.
E.ON Ruhrgas unsuccessfully sought temporary relief in a summary proceeding in order to prevent the
decision from taking immediate effect. Consequently, E.ON Ruhrgas had to terminate, as of September 30, 2006,
the contracts with municipal utilities that were covered by the Federal Cartel Office decision. E.ON Ruhrgas
challenged the Federal Cartel Office’s decision in a full proceeding before the State Superior Court in
Düsseldorf, which ruled in favor of the Federal Cartel Office in October 2007. E.ON Ruhrgas has accepted the
decision concerning the limitation of the duration of contracts according to the amount of a customer’s
requirements supplied. As far as the decision concerned the ban on participation in competition, E.ON Ruhrgas
has decided to challenge it in a proceeding before the Federal Court of Justice. In the mean time, E.ON Ruhrgas
has concluded new contracts having a duration of only 1 or 2 years with virtually all of the municipal utilities
whose prior contracts it has been required to cancel. See also “Risk Factors.”
As described in “E.ON Gastransport” above, Germany’s energy regulator has decided that a form of gas
network access contract widely used by the gas industry does not comply with Germany’s Energy Law of 2005,
and E.ON Gastransport has therefore amended its existing gas transmission contracts accordingly. This decision
also requires that E.ON Ruhrgas amend its gas sales contracts, and E.ON Ruhrgas made all necessary changes
ahead of the October 1, 2007 deadline.
Price terms in all types of sales contracts are generally pegged to the price of competing fuels, primarily gas
oil or heavy fuel oil, and provide for automatic quarterly price adjustments based on fluctuations in underlying
fuel prices. In addition, medium- and long-term contracts, with terms of over two years, usually contain clauses
which enable the parties to review prices and price formulas at regular intervals (usually every one to four years)
and to negotiate adjustments in accordance with changed market conditions. Contracts for industrial customers
generally provide for some form of take or pay obligation, usually in an amount of 50 to 90 percent of the overall
annual contract volume. Contracts with distributors and municipal utilities generally do not include fixed take or
pay provisions.
In 2007, the selling prices of E.ON Ruhrgas generally tracked the level of heating oil prices with a time lag.
In the course of the year, heating oil prices initially dropped, but then rose from February onwards. Due to the
time lag, those increases were not reflected in the selling prices of E.ON Ruhrgas until October 2007.
Gas prices in Germany are also affected by applicable taxes on fossil fuels. In Germany, customers in the
commercial/residential sector pay gas prices that include at least 0.67 €cent/kWh in duties and taxes, while
industrial customers pay up to 0.47 €cent/kWh in duties and taxes.
124
International. In 2007, E.ON Ruhrgas delivered 180.4 billion kWh of gas to customers in other European
countries, or 25.3 percent of the total volume of gas sold by E.ON Ruhrgas, compared with 160.3 billion kWh or
22.6 percent in 2006. The destinations for E.ON Ruhrgas’ external sales are the United Kingdom, Switzerland,
the Benelux countries, Austria, France, Hungary, Italy, Sweden, Denmark, Poland, Liechtenstein and Slovakia.
The 12.5 percent increase in international sales in 2007 was largely attributable to higher sales volumes in the
Netherlands and UK.
Downstream Shareholdings
E.ON Ruhrgas owns numerous shareholdings in integrated gas companies, gas distribution companies and
municipal utilities through its subsidiaries ERI and Thüga.
ERI holds both majority and minority shareholdings in European and German energy companies, while
Thüga holds primarily minority shareholdings in about 90 regional and municipal utilities in Germany. In
addition, Thüga’s international shareholdings, which are held through its wholly-owned Italian subsidiary Thüga
Italia S.r.l. (“Thüga Italia”), consist of interests in a number of Italian energy companies. Effective as of
January 1, 2008, Thüga has sold its wholly-owned Italian subsidiary Thüga Italia together with all its majority
and minority shareholdings in Italy to E.ON Italia Holding S.r.l.
ERI: As of December 31, 2007, ERI’s portfolio of shareholdings included stakes in three domestic and 22
foreign companies. In 2007, ERI (including its fully consolidated shareholdings) contributed sales of €4.6 billion
(approximately 20.3 percent of E.ON Ruhrgas’ total sales, excluding natural gas and electricity taxes) and had
sales volumes of 177.6 billion kWh in 2007 (2006: 152.0 billion kWh).
In May 2007, E.ON Gaz România S.A. was transferred from E.ON Ruhrgas AG to ERI. According to legal
unbundling requirements E.ON Gaz România S.A. was split into the two companies E.ON Gaz România S.A.
and E.ON Gaz Distributie S.A. at the beginning of July 2007. As of January 15, 2008, the shares in both
companies were assigned by ERI to E.ON Gaz Romania Holding S.A.
Germany. As of December 31, 2007, ERI held interests in the following regional gas distribution companies
in Germany:
Share held
by ERI
%
Shareholding
Ferngas Nordbayern GmbH(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas-Union GmbH(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Saar Ferngas AG(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53.10
25.93
20.00
(1) Interest held via ERI’s wholly-owned subsidiary RGE Holding GmbH.
These companies are also customers of E.ON Ruhrgas. Other German gas companies also hold interests in
certain of these companies.
125
International. As of December 31, 2007, ERI held interests in the following companies in countries outside
of Germany, primarily in central Europe and the Nordic region:
Share held
by ERI
%
Shareholding
Gasnor AS, Norway . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Swedegas AB ( formerly: Nova Naturgas AB), Sweden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gasum Oy, Finland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AS Eesti Gaas, Estonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
JSC Latvijas Gaze, Latvia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AB Lietuvos Dujos, Lithuania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rytu Skirstomieje Tinklai, Lithuania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inwestycyjna Spólka Energetyczna Sp.z o.o. (IRB), Poland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EUROPGAS a.s., Czech Republic(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Földgáz Trade ZRT, Hungary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Földgáz Storage ZRT, Hungary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Panrusgáz Zrt., Hungary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colonia-Cluj-Napoca-Energie S.R.L. (CCNE), Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Ruhrgas Mittel- und Osteuropa GmbH(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nafta a.s., Slovakia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S.C. Congaz S.A., Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Servicii Romania S.R.L., Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ekopur d.o.o., Slovenia(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SOTEG — Société de Transport de Gaz S.A., Luxembourg . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Holdigaz SA, Switzerland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Gaz Distributie S.A., Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Gaz România S.A., Romania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14.00
29.59
20.00
33.66
47.23
38.91
20.28
50.00
50.00
100.00
100.00
50.00
33.33
100.00
40.45
28.59
50.00
100.00
20.00
2.21
51.00
51.00
(1) EUROPGAS a.s. holds 50.0 percent of SPP Bohemia a.s. and 48.18 percent of Moravské naftové doly a.s.
(MND) in the Czech Republic.
(2) E.ON Ruhrgas Mittel- und Osteuropa GmbH has an indirect interest of 24.50 percent in SPP, Slovakia.
(3) Ekopur d.o.o. holds 6.52 percent of Geoplin d.o.o. in Slovenia.
As with its German shareholdings, ERI holds some stakes in companies which are customers of E.ON
Ruhrgas.
Thüga: As of December 31, 2007, Thüga holds primarily minority shareholdings in about 90 regional and
municipal utilities in Germany. In addition, Thüga’s international shareholdings are held through its whollyowned Italian subsidiary Thüga Italia, and consist mainly of interests in a number of majority and minority
shareholdings in Italian gas distribution and sales companies. Through its shareholdings in Italian energy
companies, Thüga supplied natural gas to approximately 900,000 end customers in Italy by the end of December
2007, primarily in the regions of Lombardy, Emilia Romagna, Veneto, Friuli-Venezia Giulia and Piedmont.
Effective as of January 1, 2008, Thüga has sold its wholly-owned Italian subsidiary Thüga Italia together with all
its majority and minority shareholdings in Italy to E.ON Italia Holding S.r.l.
With respect to its minority shareholdings, Thüga is an active shareholder, offering operational competence
as well as other services. In 2007, Thüga contributed sales of €1.1 billion (4.6 percent of E.ON Ruhrgas’ total
sales, excluding natural gas and electricity taxes). Thüga’s gas sales volumes decreased by 13.8 percent to 19.9
billion kWh in 2007 from 23.1 billion kWh in 2006, primarily as a result of unfavorable weather conditions.
As of December 31, 2007, E.ON Ruhrgas Thüga Holding GmbH held 81.1 percent of Thüga and E.ON
Ruhrgas AG, through its subsidiary CONTIGAS Deutsche Energie-Aktiengesellschaft (“Contigas”), held the
remaining 18.9 percent.
126
Germany. As of December 31, 2007, Thüga held interests in operating companies which are primarily
municipal utilities. The top ten shareholdings in terms of total sales in 2007 are as follows:
Share held
by Thüga
%
Shareholding
Stadtwerke Hannover Aktiengesellschaft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
N-ERGIE Aktiengesellschaft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mainova Aktiengesellschaft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gasag Berliner Gaswerke Aktiengesellschaft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
badenova AG & Co. KG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
HEAG Südhessische Energie AG (HSE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DREWAG-Stadtwerke Dresden GmbH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Erdgas Südbayern GmbH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stadtwerke Duisburg AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stadtwerke Karlsruhe GmbH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24.00
40.81
24.44
36.85
47.30
40.01
10.00
50.00
20.00
10.00
International. Effective as of January 1, 2008, Thüga sold its wholly-owned Italian subsidiary Thüga Italia
together with all its majority and minority shareholdings in Italy, to E.ON Italia Holding S.r.l. As of
December 31, 2007, Thüga held, through its subsidiary Thüga Italia, mainly the following shareholdings in
privately owned gas distribution and sales companies as well as in one municipal utility in Italy:
Share held
by Thüga
%
Shareholding
E.ON Vendita S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thüga Laghi S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thüga Mediterranea S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thüga Orobica S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thüga Padana S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thüga Triveneto S.r.l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
G.E.I. S.p.A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AMGA Azienda Multiservizi S.p.A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100.00
100.00
100.00
100.00
100.00
100.00
48.94
21.60
Competitive Environment
Along with oil and lignite/hard coal, natural gas is one of the three primary sources of energy used in
Germany. Gas is currently used for a little more than 23 percent of Germany’s energy consumption, and satisfies
about a third of the energy demand of the German industrial and commercial/residential sectors. Competing
sources of energy include electricity and coal in all sectors, gas oil and district heating in the commercial/
residential sector and gas oil and heavy fuel oil in the industrial sector. Natural gas is also used, but on a limited
basis, as an energy source for power stations. Since the 1970s, natural gas has made particular gains in the
residential space heating market, where it is marketed as a modern and environmentally-friendly energy source
for heating homes. At year-end 2007, approximately 48 percent of German homes were heated using gas, making
gas the leading energy source for this market. In 2007, gas was chosen as the heating method for the majority of
new homes under construction. Although renewable energies are increasingly popular, natural gas was able to
defend its leading position in the heating market.
Within the German gas market, E.ON Ruhrgas competes with domestic and foreign gas companies, the gas
subsidiaries of oil producers and pure trading companies. Major domestic competitors include RWE Energy,
Verbundnetz Gas AG and Wingas. Foreign competitors include Gaz de France, Econgas, Essent and Nuon. E.ON
Ruhrgas currently enjoys a strong market position, supplying approximately 49 percent of all gas consumed in
Germany in 2007. Nevertheless, E.ON Ruhrgas considers competition in the German gas market to be vigorous,
127
with both new and established competitors vying for the business of E.ON Ruhrgas’ direct and indirect
customers. E.ON Ruhrgas believes it was able to successfully compete in 2007 by remaining flexible in its
contract and price negotiations and by offering attractive terms and services to its established and potential
customers. In the future it is expected that the new network access model described above in “— Transmission
and Storage — E.ON Gastransport” will lead to further intensification of competition.
For information about the debate on long-term gas sales contracts, which the Federal Cartel Office considers
to be an obstacle to competition, as well as information about gas price trends in 2007, see “— Sales” above. For
information about regulatory developments which are affecting or may affect competition in the German gas
market, see “— Regulatory Environment” and “Risk Factors,” which also includes information on investigations
of gas prices charged by some German utilities, including utilities in which E.ON Ruhrgas and E.ON Energie
hold interests.
Outside Germany, the gas markets in which E.ON Ruhrgas operates are also subject to strong competition.
The Company cannot guarantee it will be able to compete successfully in the gas markets in which it is already
present or in new gas markets E.ON Ruhrgas may enter.
U.K.
Overview
E.ON UK is one of the leading integrated electricity and gas companies in the United Kingdom. It was
formed as one of the four successor companies to the former Central Electricity Generating Board as part of the
privatization of the electricity industry in the United Kingdom in 1989. E.ON UK and its associated companies
are actively involved in electricity generation, distribution, retail and trading. As of December 31, 2007, E.ON
UK owned or through joint ventures had an attributable interest in 10,581 MW of generation capacity, including
359 MW of CHP plants and 251 MW of operational wind and hydroelectric generation capacity. E.ON UK
served approximately 8.0 million electricity and gas customer accounts at December 31, 2007 and its Central
Networks business served 4.9 million customer connections. The U.K. market unit recorded sales of €12.6 billion
in 2007 and adjusted EBIT of €1.1 billion.
Operations
In the United Kingdom, electricity generated at power stations is delivered to consumers through an
integrated transmission and distribution system. For information about the principal segments of the electricity
industry, see “— Central Europe — Operations.” All electricity transmission in Great Britain is operated by
National Grid Transco plc (“National Grid”).
E.ON UK operates significant wholesale and retail gas and electricity businesses and engages in gas and
electricity trading. The company served approximately 8.0 million customer accounts at December 31, 2007,
including approximately 5.3 million electricity customer accounts and 2.7 million gas customer accounts. As
planned, E.ON UK exited the telecoms business in March 2007, and now has no fixed line telephone customer
accounts. E.ON UK’s Central Networks distribution business served 4.9 million customer connections as of the
end of 2007.
The U.K. market unit comprises the non-regulated business, including energy wholesale (generation and
energy trading), retail and energy services, the regulated distribution business, and other activities, such as
certain non-distribution assets and the E.ON UK corporate center. In 2007, electricity accounted for 65 percent of
E.ON UK’s sales, gas revenues accounted for 33 percent and other activities accounted for 2 percent.
128
The following table sets forth the sources and sales channels of electric power in E.ON UK’s operations
during each of 2007 and 2006:
Total 2007
million kWh
Total 2006
million kWh
%
Change
Sources of Power
Own production(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power from power stations in which E.ON UK has an interest of 50
percent or less . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power purchased from other suppliers(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power used for operating purposes, network losses and pump storage . . . . . . .
41,236
35,866
+15.0
1,239
35,499
(159)
731
38,131
(971)
+69.5
-6.9
-83.6
Net power supplied(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77,815
73,757
+5.5
Sales of Power
Mass market sales (residential customers and small and medium sized
enterprises)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial and commercial sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market sales(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34,164
18,363
25,288
37,893
18,371
17,493
-9.8
0
+44.6
Net power sold(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77,815
73,757
+5.5
(1) The increase in own production in 2007 was primarily attributable to improved plant availability and a
reduction in wholesale gas prices, which made generation more economically attractive than buying power.
(2) The decrease in power purchased from other suppliers and increase in market sales in 2007 compared with
2006 primarily reflects the significant increase in own generation.
(3) Mass market sales were lower in 2007 due to lower customer numbers, customer behavior and warmer
weather.
(4) The increase in market sales results from the reduction in mass market sales and the increase in own
generation.
(5) Excluding proprietary trading volumes. For information on proprietary trading volumes, see “Non-regulated
Business — Energy Wholesale — Energy Trading.”
The following table sets forth the sources and sales channels of gas in E.ON UK’s operations during each of
the periods presented:
Total 2007
million kWh
Total 2006
million kWh
%
Change
Sources of Gas
Long-term gas supply contracts(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market purchases(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
39,205
167,185
42,918
151,064
-8.7
+10.7
Total gas supplied(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
206,390
193,982
+6.4
Sales and Use of Gas
Gas used for own generation(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales to industrial and commercial customers(5) . . . . . . . . . . . . . . . . . . . . . . . .
Sales to retail mass market customers(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market sales(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49,347
23,352
55,518
78,173
38,632
28,663
63,888
62,799
+27.7
-18.5
-13.1
+24.5
Total gas used and sold(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
206,390
193,982
+6.4
(1) The reduction in the volume of gas purchased under long-term gas supply contracts in 2007 was primarily
the result of reductions in wholesale gas prices, which made spot purchases more economic.
(2) The increase in the volume of market gas purchases was attributable to the decline in supply contract
volumes as well as an increase in activities to optimize E.ON UK’s gas position.
129
(3) Excluding proprietary trading volumes. For information on proprietary trading volumes, see “Non-regulated
Business — Energy Wholesale — Energy Trading.”
(4) The increase in gas used for own generation reflects the increase in own generation and excellent rates of
plant availability
(5) During 2007, the industrial and commercial sales business continued to focus on securing higher value
customers, which resulted in lower sales volume in 2007 compared with 2006.
(6) Mass market sales were lower in 2007 due to lower customer numbers, customer behavior and warmer
weather.
(7) Market sales in 2007 were higher than in 2006, reflecting a more dynamic marketplace and increased
utilization of trading activity to drive margins combined with reduced mass market sales (see note 6)
Market Environment
E.ON UK primarily operates in the electricity generation, electricity and gas trading and the electricity and
gas retail energy markets in Great Britain (England, Wales and Scotland) and in the market for electricity
distribution in England.
Electricity. Demand for electricity in the United Kingdom has been relatively stable in recent years. In the
near term, E.ON UK expects electricity demand in the United Kingdom to grow by an average of approximately
1 percent per annum under normal weather conditions.
The principal commercial features of the electricity industry in the United Kingdom in recent years have
been increasing competition in supply through a principle of open access to the transmission and distribution
systems. Suppliers are free to compete with each other in supplying electricity to consumers anywhere within
England, Wales and Scotland. All electricity supply (retail) and distribution activities were separated in Great
Britain in 2001, splitting the market into a liberalized supply sector and a regulated network distribution sector.
On April 1, 2005, a new set of rules known as the British Electricity Trading and Transmission
Arrangements (“BETTA”) was introduced in England, Wales and Scotland. This extended the existing NETA
arrangements in force in England and Wales to Scotland, providing a market-based framework for electricity
trading and wholesale sales, as well as a method of settling trading imbalances and a mechanism for maintaining
the stability of the network. Trading activities are characterized by bilateral contracts for the purchase and sale of
bulk power and are carried out both on exchanges and over the counter. The Office of Gas and Electricity
Markets (“Ofgem”) is responsible for regulatory oversight of BETTA.
E.ON UK believes that it is able to compete more effectively in Scotland (which represents approximately
10 percent of the electricity market in Great Britain as a whole) following BETTA’s introduction.
Gas Market, The UK gas market has been shaped by the decline in the UK’s indigenous production sources
on the UK Continental Shelf (“UKCS”). The UK has become increasingly reliant on gas imports and this trend
can be expected to continue in the future. New build supply import capacity initially lagged behind the pace of
UKCS decline but has been remedied by the completion of the Langeled gas pipeline, BBL gas pipeline and the
Teesside Gassport LNG terminal. In general, reliance on imported gas sources has led to greater uncertainty in
the market, as UK gas deliveries are heavily influenced by conditions in both the continental European and
global gas market. Uncertainty in the market has generally resulted in increased price volatility, which is often
further exacerbated by the activities of speculative traders in the market, driving sharp changes in forward prices.
Gas Prices. Prices saw substantial declines during the first quarter of 2007, as mild weather and oversupply
on the continent impacted the market. Norwegian deliveries to the UK were very strong, as a result of reduced
continental demand. Prices fell further in April, to around 16p/therm, but experienced significant correction at the
start of May, to around 25p/therm, as volumes from pipelines reduced when producers experienced production
problems. In the third quarter, the market experienced a supply shock in the form of an unplanned outage to the
130
UK CATS pipeline and prices rose to around 30p/therm. In September, the damaged pipeline returned to
operation and prices were briefly depressed. A slight upturn in demand however prompted prices to rise to
around 40p/therm, as simultaneous planned outages at Rough and IUK storage facilities limited the availability
of marginal gas volumes. The fourth quarter saw prices sensitive to weather conditions with storage withdrawals
limited.
Power Market. The first quarter of 2007 saw a decline in gas prices which also reduced power prices,
keeping spark spreads (difference between power prices and gas and carbon prices) relatively constant. Static
coal prices meant that gas generation was the preferable source of power. Towards the end of the second quarter
gas prices began to strengthen. The third quarter saw steadily rising coal prices, and some spikes in gas prices,
leading to a steady increase in power prices. Gas and coal prices rose sharply in the fourth quarter, leading to
sharp increases in power prices. In the fourth quarter, spot power prices have been at their highest levels since
March 2006 due to nuclear outages, increased demand during cold weather, extreme supply tightness on the
continent, and rising gas prices. Coal prices almost doubled between the first half of the year and November
2007.
Competition. E.ON UK’s exposure to wholesale electricity prices in the United Kingdom is partially hedged
by the balance provided by its retail business. The retail energy market in the United Kingdom has consolidated
over the last few years into six major competitors. Based on data from Datamonitor, Centrica, previously the
monopoly gas supplier branded as British Gas, is currently the market leader in terms of size in both gas and
electricity with approximately 17.0 million customer accounts. According to Datamonitor, E.ON UK is now the
third largest energy retailer with approximately 8.0 million accounts, during 2007 Scottish and Southern
Electricity moved into second place with approximately 8.1 million accounts. The market is characterized by
substantial levels of customers switching suppliers in any given year; approximately half of the customers in
Great Britain have now switched either their gas or electricity supplier since market liberalization. Churn levels,
which measure the percentage of customers switching suppliers, fell generally from 2002 through 2005 as the
market matured, before increasing in 2006 in the context of significant price increases. 2007 saw a reduction
from 2006 rates, but the increased price sensitivity meant levels remained relatively high. This resulted in E.ON
UK’s annual churn rate decreasing from 15.4 percent in 2006 to 15.1 percent in 2007.
Impact of Environmental Measures. The ongoing implementation of environmental legislation is expected to
have a significant impact on the energy market in the United Kingdom in coming years. In response, E.ON UK is
increasing its production of electricity from renewable sources, as described in more detail below. Environmental
measures of particular importance include:
•
The U.K.’s Renewables Obligation requires electricity retailers to source an increasing amount of the
electricity they supply to retail customers from renewable sources. Under the current regime, for the
period from April 1, 2007 until March 31, 2008, the renewables obligation is equal to 7.9 percent, rising
to a figure of 15.4 percent by 2015/2016. The U.K. government is currently consulting on options to
potentially extend targets to a maximum of 20 percent by 2020. The requirement applies to all retail
sales over a twelve-month period beginning on April 1 of each year, and Renewables Obligation
Certificates (“ROCs”) are issued to generators as evidence of qualified sourcing. ROCs are tradeable,
and retailers who fail to present Ofgem with ROCs representing the full amount of their renewables
obligation are required to make a balancing payment in the amount of any shortfall into a buy-out fund.
Receipts from the buy-out fund are re-distributed to holders of ROCs.
•
The application in the United Kingdom of the EU Large Combustion Plant Directive prevents coal- and
oil-powered generation facilities that have not been fitted with specified sulphur oxide and oxides of
nitrogen and particulate matter reduction measures from operating for more than a total of 20,000 hours
starting in 2008.
Further information on the emissions allowance trading scheme and the Large Combustion Plant Directive
is given in “— Regulatory Environment” and “— Environmental Matters.”
131
Non-regulated Business
Energy Wholesale
During 2007, E.ON UK’s power generation and energy trading activity was operated and managed under
the name of “Energy Wholesale.” This had been the case since 2004, a measure designed to provide a greater
strategic focus in the management of E.ON UK’s generation and trading activities and reinforce the close
operational ties between the two businesses. For example, the energy trading business is responsible for
purchasing commodities used in the production of energy from the generation portfolio. The trading business is
best positioned to decide whether E.ON UK should generate or purchase electricity to cover its retail obligations,
depending upon the prevailing market price of electricity. For the purpose of describing the business activities of
E.ON UK, the two businesses are described separately since they each cover distinct areas of activity.
Power Generation
E.ON UK focuses on maintaining a low cost, efficient and flexible electricity generation business in order to
compete effectively in the wholesale electricity market. As of December 31, 2007, E.ON UK owned either
wholly, or through joint ventures, power stations in the United Kingdom with an attributable registered
generating capacity of 10,581 MW, including 359 MW of CHP plants and 50 MW of hydroelectric plant, while
its attributable portfolio of operational wind capacity stood at 201 MW. E.ON UK’s share of the generation
market in Great Britain remained relatively stable in 2007, at approximately 10 percent.
E.ON UK generates electricity from a diverse portfolio of fuel sources. In 2007, approximately 52.3 percent
of E.ON UK’s electricity output was fuelled by coal and approximately 46.2 percent by gas, of which
approximately 1.9 percent was from CHP schemes, with the remaining 1.5 percent being generated from
hydroelectric, wind and oil-fired plants. E.ON UK is continuing its effort to secure a balanced and diverse
portfolio of fuel sources, giving it the flexibility to respond to market conditions and to minimize costs.
E.ON UK also regularly monitors the economic status of its plant in order to respond to changes in market
conditions.
E.ON UK also owns a minority interest in a company that operates a gas-fired power plant in Turkey (see
“— Midlands Electricity Non-Distribution Assets” below).
E.ON UK is progressing with significant investments to improve its generation capacity. This is partly to
replace capacity which will be taken out of production in coming years due to applicable environmental
regulations. In 2007, E.ON UK started construction of one of the largest gas fired CHP stations in the U.K. at the
Isle of Grain in Kent. The scheme is expected to generate 1,200 MW of power and export up to 340 MW of heat
and is due to be commissioned in 2009. Progress is also being made on regulatory consents for the construction
of two new highly efficient coal units at the Kingsnorth power station site in Kent. The two new units would be
built next to the existing four units, incorporating ‘super critical’ boiler technology and are currently expected to
come on line during 2012.
Nuclear. E.ON UK does not operate any nuclear power plants.
Renewable Energy. E.ON UK plans to grow its renewable electricity generation business in response to the
U.K. regulatory initiatives summarized above. E.ON UK is already one of the leading developers and owner/
operators of wind farms in the United Kingdom, with interests in 21 operational onshore and offshore wind farms
with total capacity of 212 MW, of which 201 MW is attributable to E.ON UK.
Potential onshore and offshore projects with an aggregate capacity of approximately 1,134 MW are now in
the development phase. In 2007, E.ON UK completed construction of the 18 MW Stags Holt onshore wind farm
in Cambridgeshire which became operational in the third quarter.
In 2007, E.ON UK commenced construction of the Robin Rigg offshore wind farm in the Solway Firth on
the northwest coast of England. Due for completion in the second quarter of 2009, the 180 MW wind farm is
132
expected to be one of the United Kingdom’s largest offshore wind farms to date, with plans for 60 turbines, each
with a capacity of 3 MW. In terms of generating capacity, Robin Rigg is expected to generate 550 GWh each
year.
In addition to the planned expansion of its wind farm portfolio, E.ON UK generated from biomass in 2007
(co-firing with coal at the Kingsnorth and Ironbridge power stations), generating a total of 192 GWh of
renewable energy by this method during the year. During 2007, work was completed on the construction of a
44 MW wood-burning plant at Steven’s Croft, near Lockerbie in southwest Scotland which is currently being
commissioned. Steven’s Croft will be one of the United Kingdom’s largest dedicated biomass plants with annual
generation of 330 GWh.
During 2008, E.ON UK expects to continue to develop its capability in marine generation (using tidal,
stream and wave power) to position itself to capture future opportunities in this area.
As a part of its balanced approach, E.ON UK seeks to fulfill its renewables obligation through a
combination of its own generation, renewable energy purchased from other generators under tradeable ROCs,
and direct payment of any residual obligation into the buy-out fund. For the period from April 1, 2006 to
March 31, 2007, E.ON UK achieved 46 percent of its renewables obligation through own generation and
purchases.
CHP. E.ON UK also operates large scale CHP schemes. CHP is an energy efficient technology which
recovers heat from the power generation process and uses it for industrial processes such as steam generation,
product drying, fermentation, sterilizing and heating. E.ON UK’s total operational CHP electricity capacity at
December 31, 2007 was 359 MW. Clients range across a number of sectors, including healthcare,
pharmaceuticals, chemicals, paper and oil refining.
Energy Trading
During 2007, E.ON UK’s energy trading unit engaged in asset-based energy trading in gas and electricity
markets to assist E.ON UK in commercial risk management and the optimization of its U.K. gross margin. The
energy trading unit has played a key role in E.ON UK’s integrated electricity and gas business in the United
Kingdom by acting as the “commercial hub” for all energy transactions. It manages price and volume risks and
seeks to maximize the integrated value from E.ON UK’s generation and customer assets. In 2008, management
responsibility for E.ON UK’s trading activities will be transferred to the new Energy Trading market unit. For
information about EET, see “Business — Our Business.”
Energy trading activities include:
•
Purchasing of coal, gas and oil for power stations;
•
Dispatching generation and selling the electrical output and ancillary services provided by E.ON UK’s
power stations;
•
Purchasing gas and electricity as required for E.ON UK’s retail portfolio;
•
Managing the net position and risks of E.ON UK’s generation and retail portfolio;
•
Managing renewable obligations for the retail portfolio through long-term purchases and trading of
ROCs;
•
Purchasing and/or trading of CO2 emission certificates and other environmental products, including
Levy Exempt Certificates (issued in relation to the U.K. Climate Change Levy); and
•
Achieving portfolio optimization and risk management.
E.ON UK also engages in a controlled amount of proprietary trading in gas, power, coal, oil and CO2
emission certificates markets in order to take advantage of market opportunities and maintain the highest levels
133
of market understanding required to support its optimization and risk management activities. The following table
sets forth E.ON UK’s electricity and gas proprietary trading volumes for 2007 and 2006:
2007
Electricity
billion kWh(1)
2006
Electricity
billion kWh
2007
Gas
billion kWh(1)
Energy bought . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32.3
32.3
14.0
14.0
127.4
127.4
57.7
57.7
Gross volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
64.6
28.0
254.8
115.4
Proprietary Trading Volumes
2006
Gas
billion kWh
(1) The increase in traded gas and electricity volumes in 2007 was primarily attributable to favorable market
opportunities.
In its energy trading operations, E.ON UK uses a combination of bilateral contracts, forwards, futures,
options contracts and swaps traded over-the-counter or on commodity exchanges. E.ON UK also undertakes
relatively low levels of trading in other commodities, including ROCs, environmental products and weather
derivatives. All of E.ON UK’s energy trading operations, including its limited proprietary trading, are subject to
E.ON’s risk management policies for energy trading. For additional information on these policies and related
exposures, see “Operating and Financial Review and Prospects — Quantitative and Qualitative Disclosures about
Market Risk.”
E.ON UK has in place a portfolio of fuel contracts of varying volume, duration and price, reflecting market
conditions at the time of commitment. Coal contracts with a variety of suppliers within the United Kingdom and
overseas ensure that supplies are secured for E.ON UK’s coal-fired plants, while maintaining enough flexibility
to minimize the cost of generation across the total generation portfolio. E.ON UK’s coal import facilities at
Kingsnorth power station and Gladstone Dock, Liverpool, provide secure access to international coal supplies.
The supply of gas for E.ON UK’s CCGT and CHP plants is sourced through non-interruptible long-term gas
supply contracts with gas producers (certain of which contain take or pay provisions), and through purchases on
the forward and spot markets. Since October 2004, E.ON Ruhrgas has been a significant supplier of natural gas
to E.ON UK pursuant to a long-term supply contract between the parties. The agreed framework for the E.ON
Ruhrgas contract is essentially that of a “take or pay” arrangement. Risk management arrangements in respect of
the volume and price risks associated with E.ON UK’s gas supply contracts are conducted through trading on the
spot, over-the-counter and bilateral markets. For additional details on these contractual commitments, see
“Operating and Financial Review and Prospects — Contractual Obligations” and Notes 24 and 25 of the Notes to
Consolidated Financial Statements.
Retail
E.ON UK sells electricity, gas and other energy-related products to residential, business and industrial
customers throughout Great Britain. As of December 31, 2007, E.ON UK supplied approximately 8.0 million
customer accounts, of which 7.4 million were residential customer accounts and 0.6 million were small and
medium-sized business and industrial customer accounts. During the year, there was a net decrease in the total
number of customer accounts of approximately 0.4 million as some customers switched suppliers as a
consequence of E.ON’s retail price position in the market. E.ON UK continues to focus on reducing the costs of
its retail business, through efficiency improvements, more economical procurement of services and the utilization
of lower cost sales channels.
Residential Customers. The residential business had approximately 7.4 million customer accounts as of
December 31, 2007. Approximately 65 percent of E.ON UK’s residential customer accounts are electricity
134
customers and 35 percent are gas customers. Individual retail customers who buy more than one product (i.e.,
electricity, gas or other energy-related products) are counted as having a separate account for each product,
although they may choose to receive a single bill for all E.ON UK-provided services. In the residential customers
sector, E.ON UK sold 24.6 TWh of electricity and 48.3 TWh of gas in 2007, as compared with 26.5 TWh of
electricity and 52.4 TWh of gas in 2006. The lower volumes reflected in both lower customer numbers and
warmer weather.
E.ON UK targets residential customers through national marketing activities such as media advertising
(including print, television and radio), targeted direct mail, public relations and online campaigns. During 2007,
there was a gradual transition from the former Powergen brand to the E.ON brand, with the E.ON brand being
used exclusively since December. E.ON seeks to create significant national brand awareness through high profile
sponsorships under its E.ON brand. This includes the sponsorship of the FA Cup, England’s most historic soccer
competition, which commences each year in August. E.ON UK also sponsors the Tour of Britain cycle race and
the King of the Mountains. E.ON UK is in the last year of sponsoring Ipswich Town, a soccer team playing in the
English Championship league.
2007 initially saw an environment of falling wholesale energy prices, which drove reductions in electricity
and gas retail prices across the industry, although specific decreases varied by supplier. In January, E.ON UK
reduced gas and electricity prices for average customers by 16 percent and 5 percent, respectively. The fall in
wholesale prices was partially offset by increases in transport costs, distribution costs and environmental costs,
and in the final quarter of 2007 wholesale prices rose significantly, putting upward pressure on retail prices.
Wholesale costs (calculated during the first quarter 2008) have gone up by 60 percent for gas and 88 percent for
electricity since February 2007. As a consequence a number of suppliers increased their prices during the first
quarter of 2008; RWE NPower announced price rises of 17.2 percent for gas and 12.7 percent for electricity;
EDF Energy announced price rises of 12.9 percent for gas and 7.9 percent for electricity, British Gas announced
price rises of 15.4 percent for both gas and electricity and Scottish Power announced price rises of 15 percent for
gas and 14 percent electricity. E.ON UK has also announced price rises of 15 percent for gas and 9.7 percent for
electricity from February 8, 2008. Approximately 550,000 customers on price protection, fixed price or
Staywarm products will be unaffected. E.ON UK has also implemented a package of measures to limit the effects
of rising wholesale costs by offering subsidized energy efficient products including cavity wall and loft
insulation to a significant proportion of its customers and delaying the price increases to vulnerable customers
until after the winter months. Some of these initiatives contribute to the requirements placed on suppliers in
relation to the Energy Efficiency Commitment, which is described in “— Regulatory Environment — U.K.”
Small and Medium-Sized Business and Industrial and Commercial Customers. E.ON UK’s number of
accounts in this sector totaled approximately 0.6 million at year-end 2007. In this sector, E.ON UK sold 27.9
TWh of electricity and 30.6 TWh of gas in 2007, as compared with 29.7 TWh of electricity and 40.1 TWh of gas
in 2006. E.ON UK’s focus in this area remains on acquiring and retaining the most profitable contracts available.
Energy Services
E.ON UK’s Energy Services business was created in July 2005, bringing together the new connections and
metering businesses from Central Networks and the home installation activities from Retail with the vision of
providing E.ON UK customers with all the services they need to get connected to energy supplies, heat their
homes and understand their energy use. As well as establishing a profitable growth business, Energy Services has
three further aims in the medium term: (1) to deliver products and services for the Retail and Central Networks
businesses; (2) to improve the level of customer service E.ON UK provides; and (3) to demonstrate the E.ON
brand values of ‘Performance and Expertise’. Energy Services employs more than 4,000 people, undertakes more
than 50 million meter readings and carry out work in around 400,000 homes per year, playing a key part in E.ON
UK’s low carbon agenda by delivering energy efficiency measures such as loft and cavity wall insulation
services. The results of this business have been reported within the non-regulated business unit since 2006.
135
Regulated Business
Distribution
The electricity distribution business in the United Kingdom is effectively a natural monopoly within the area
covered by the existing network due to the cost of providing an alternative distribution network. Accordingly, it
is highly regulated. However, new distribution licenses are available for network developments, including for
those areas already covered by an existing distribution license, and electricity distribution could also face indirect
competition from alternative energy sources such as gas. For details on the license system, see “— Regulatory
Environment — U.K.”
Within the UK there are 14 licensed distribution network operators (DNOs), each responsible for a
distribution services area. EON UK’s Central Networks business owns and manages two DNO licenses through
Central Networks East plc and Central Networks West plc. The combined service area covers approximately
11,312 square miles, extending from the Welsh border in the West to the Lincolnshire coast in the East and from
Chesterfield in the North to the northern outskirts of Bristol in the South and contains a resident population of
about 10 million people. The networks distribute electricity to approximately 4.9 million homes and businesses
in the combined service area and transport virtually all electricity supplied to consumers in the service area
(whether by E.ON UK’s retail business or by other suppliers). Separate distribution licenses are issued for the
operation of the two networks but the combined business is managed by a centralized management team and uses
the same methodology and staff to operate both networks.
The following table sets forth the total distribution of electric power by E.ON U.K.’s Central Networks
business for each of the periods presented:
Total
2007
million kWh
Total
2006
million kWh
%
Change
Large non-domestic customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Domestic and small non-domestic customers . . . . . . . . . . . . . . . . . . . . . . . . . .
25,579
30,426
25,915
31,238
-1.3
-2.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56,005
57,153
-2.0
Distribution of Power to
The decline in the volume of power distributed reflected usage declines following retail price increases to
residential and business customers and the mild winter and spring in 2007, which resulted in much less demand
for heat.
Distribution charges are billed on the basis of published tariffs, which are set by the company and adhere to
Ofgem’s price control formulas. The current price controls that run from April 2005 until March 2010 were
agreed with Ofgem in December 2004. The price controls incorporate an allowed rate of return for investing in
and operating the network, as well as a five year performance target.
Other
Midlands Electricity Non-Distribution Assets
E.ON UK also acquired a number of non-distribution businesses in the Midlands Electricity plc (“Midlands
Electricity”) transaction, including an electrical contracting operation and an electricity and gas metering
business in the United Kingdom, as well as minority equity stakes in companies operating electricity generation
plants in England, Pakistan and Turkey. Following disposals in 2004 and 2005, the only remaining generation
stake is a 31.0 percent interest in Trakya Electric Uretin ve Ticaret A.S., which owns and operates a 478 MW
Combined Cycle Gas Turbine (“CCGT”) plant in Turkey. E.ON UK has decided to retain the electricity and gas
metering services business and core parts of the contracting business (including street lighting) within the newlyformed Energy Services business, but has closed or sold the non-core parts of the contracting business.
136
Nordic
Overview
E.ON Nordic’s principal business, carried out mainly through E.ON Sverige, is the generation, distribution,
sales, and trading of electricity, gas and heat, mainly in Sweden. E.ON Sverige is the second-largest Swedish
utility (on the basis of electricity sales and production capacity). E.ON Nordic is the largest shareholder in E.ON
Sverige, currently holding 55.3 percent of the share capital and a 56.6 percent voting interest. On October 12,
2007, E.ON and Statkraft signed a letter of intent on an asset swap under which E.ON will acquire the
44.6 percent stake in E.ON Sverige held by Statkraft and will thus become the sole shareholder of E.ON Sverige,
aside from a small remaining minority interest of 0.05 percent. In return, Statkraft will receive from E.ON power
generation assets in Sweden, Germany and the United Kingdom, as well as shares of E.ON AG to make up for
the remaining difference in value. The transaction is expected to close in the third quarter of 2008. It requires the
consent of the responsible boards and institutions.
For the first half of 2006, E.ON Nordic also held a majority shareholding in E.ON Finland. On June 26,
2006, E.ON Nordic and Fortum Power and Heat Oy (“Fortum”) finalized the transfer of this interest pursuant to
an agreement signed on February 2, 2006. In total, 10,246,565 shares, equivalent to 65.56 percent of the share
capital and voting interest of E.ON Finland, were transferred to Fortum for total consideration of €393 million.
For additional information, see “Operating and Financial Review and Prospects — Results of Operations —
Discontinued Operations.”
E.ON Nordic and its associated companies are actively involved in the ownership and operation of power
generation facilities. As of December 31, 2007, E.ON Nordic owned, through E.ON Sverige, interests in power
stations with a total installed capacity of approximately 18,300 MW, of which its attributable share was
approximately 7,400 MW (not including mothballed and shutdown power plants).
In 2007, about 51 percent of the electric power generated by E.ON Nordic through E.ON Sverige was
generated at nuclear facilities and about 44 percent at hydroelectric plants. The remaining approximately 5
percent was generated using fuel oil, biomass, natural gas, wind power and waste. E.ON Nordic also supplies
gas, is active in the heat and waste business and conducts electricity trading activities. In 2007, E.ON Nordic had
sales of €3.7 billion (including €337 million of energy taxes) and adjusted EBIT of €670 million. Electricity
contributed 75 percent, heat 12 percent, gas 6 percent and other 7 percent of 2007 sales, net of energy taxes.
Other sales are mainly attributable to the waste business, as well as contracting activities. E.ON Nordic traded a
total of approximately 62.5 TWh of electricity in 2007 (including both purchases and sales). E.ON Nordic is
primarily active in Sweden, but also operates to a minor degree in Finland, Denmark and Poland. In 2007, E.ON
Nordic estimates that it supplied about 21 percent of the electricity consumed by end users in Sweden.
In January 2007, a severe storm hit Sweden cutting power to approximately 300,000 households, including
approximately 170,000 E.ON Nordic customers. The expenses incurred by E.ON Nordic for providing
mandatory compensation to affected customers in accordance with newly enacted Swedish legislation, as well as
rebuilding infrastructure, amounted to €95 million.
Operations
In the Nordic region, electricity generated at power stations is delivered to consumers through an integrated
transmission and distribution system. For information about the principal segments of the electricity industry, see
“— Central Europe — Operations.” E.ON Nordic and its associated companies are actively involved in
electricity generation, distribution, sales, and trading.
137
The following table sets forth the sources and sales channels of electric power in E.ON Nordic’s operations
during each of 2007 and 2006:
Total
2007
million kWh
Total
2006
million kWh
%
Change
Sources of Power
Own generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power from jointly owned power stations . . . . . . . . . . . . . . . . . . . . .
Power purchased from outside sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30,150
9,845
5,473
27,901
10,173
4,646
+8.1
-3.2
+17.9
Total power procured . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power used for operating purposes and network losses . . . . . . . . . . . . . . . . . . .
15,318
(2,065)
14,819
(2,154)
+3.4
-4.1
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43,403
40,566
+7.0
Sales of Power
Residential customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales partners(1)/Nord Pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,113
12,027
25,264
6,618
12,845
21,103
-7.6
-6.4
+19.7
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43,403
40,566
+7.0
(1) Sales partners are co-owners in E.ON Nordic’s majority-owned power plants, primarily nuclear power
plants, to which E.ON Nordic sells electricity at prices equal to the cost of production.
In 2007, E.ON Nordic produced and procured a total of 43.4 billion kWh of electricity, including 2.1 billion
kWh used for operating purposes and network losses. E.ON Nordic purchased a total of 9.8 billion kWh of power
from power stations in which it has an interest of 50 percent or less. In addition, E.ON Nordic purchased 5.5 billion
kWh of electricity from other sources, mainly from the Nord Pool power exchange. In 2007, E.ON Nordic’s own
generation volumes increased by approximately 2.2 billion kWh, primarily as a result of higher water reservoir
inflow in the beginning of 2007 and end of 2006. Nuclear power production declined by approximately 0.3 billion
kWh due to unplanned outages at Oskarshamn 2 and 3. As a result of lower power production volumes in its jointly
owned power plants, E.ON Nordic purchased significantly more power from outside sources (0.8 billion kWh).
Sales to residential and commercial customers decreased by approximately 0.5 billon kWh in 2007, mainly due to
the unseasonably warm weather during the first half of 2007. Sales to sales partners and Nord Pool increased by
approximately 4.2 billion kWh in 2007, mainly due to higher hydroelectric production.
E.ON Nordic also operates wholesale and retail gas businesses in Sweden, Denmark and Finland. The
following table sets forth the sources and sales channels of gas in E.ON Nordic’s operations during each of 2007
and 2006:
Total
2007
million kWh
Total
2006
million kWh
%
Change
Sources of Gas
Long-term gas supply contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,796
121
7,156
400
-5.0
-69.9
Total gas supplied . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,917
7,556
-8.5
Sale and Use of Gas
Gas used for own generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales to industrial and distribution customers . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales to residential customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,609
4,997
228
82
1,775
5,006
257
518
-9.3
-0.2
-11.3
-84.1
Total gas used and sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,917
7,556
-8.5
138
Since September 2005, E.ON Ruhrgas has been the sole supplier of natural gas to E.ON Nordic pursuant to
long-term supply contracts between the parties. The agreed framework for the E.ON Ruhrgas contracts is
essentially that of a “take or pay” arrangement, though it will provide E.ON Nordic with a certain amount of
flexibility in relation to the purchase of additional quantities and the deferral of quantities not taken
Market Environment
Electricity. The electricity market in the Nordic countries has undergone major and far-reaching changes
since the mid-1990s. Electricity market reforms have been instituted with the goal of increasing efficiency.
Market integration and increased competition were seen as means to attain this objective. Privatization has not
been an objective, and consequently the degree of public ownership in the electricity supply industry is
essentially unaffected by the electricity market reforms.
The first major step in Swedish market reform was taken in 1991, with the decision to separate transmission
from generation. Svenska Kraftnät, established to manage the main Swedish 200-400 kV transmission network,
started operating in 1992. The networks were opened to new participants, and legislation providing for
competition became effective January 1, 1996.
Today, the key feature of the Nordic electricity market is that there is a strict separation between the natural
monopoly and the competitive parts of the industry. Thus, transmission and distribution, which are seen as
natural monopolies, are separated from generation, retail sales and trading. The transmission network in Sweden
is therefore owned and managed by Svenska Kraftnät, a state agency controlled by the Swedish state, while
distribution activities must be carried out by a legal entity separate from those engaged in retail sales (though
common ownership is allowed). In order to make competition in generation and retail sales possible in the Nordic
area, third party access to transmission and distribution networks is guaranteed. The prices and quality of
transmission and distribution services are subject to regulation by a sector-specific regulator in each country.
Moreover, in each country a central transmission system operator is responsible for the stability of the system.
Thus, although there is a common spot market and free trade across the national borders, system control remains
a national responsibility.
Following deregulation, the electricity trading market in the Nordic countries is a liquid and transparent
commodity market with trading taking place through the Nordic electricity exchange Nord Pool. The market
participants at Nord Pool include power generators, retail companies, end users, traders and portfolio managers.
The electricity exchange markets consist of a physical market (day-ahead for delivery in the next 24-hour period
and an intra-day market) and a financial market (contracts of up to six years for hedging and trading). Nord Pool
also has clearing operations where all financial contracts traded at Nord Pool and most OTC contracts for Nordic
power, contracts for differences between price areas, and emissions allowances are cleared. The current volume
of electricity traded at the Nord Pool spot market exchange is equal to more than 60 percent of underlying
consumption in the Nordic countries and the volume traded at the financial market is about 6 times the
underlying physical consumption in the Nordic countries. The pricing in the Nordic market is therefore efficient,
with low transaction costs and high transparency. In addition, the exchange price is used as a reference price for a
large part of bilateral trading contracts. The prices on the spot and forward markets are generally used as the
price basis in sales contracts with end customers.
The electricity supply system in the Nordic countries is highly dependent on the hydroelectric systems in
Norway and Sweden. In a normal year, total hydroelectric generation in the Nordic countries amounts to
approximately 190-200 TWh. Hydropower has low variable costs and is highly flexible due to the possibility to
regulate the flow of water from the reservoirs. Weak hydrologic balance, meaning less hydropower being
produced, entails that more thermal production units with considerable higher marginal costs will have to be put
into operation, implying increasing wholesale prices. Although long-term precipitation is relatively stable in the
region, wide variations occur in the short term both within individual years and between years. As a result, the
price on the Nord Pool electricity spot market can vary widely both within a given year and between years.
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Since the introduction of the EU emissions trading scheme on January 1, 2005, CO2 emission certificates
have had a significant impact on electricity prices in the Nordic countries. The price of CO2 emission certificates
is set on the European emissions market, through trading on marketplaces such as ECX and Nord Pool and on the
European OTC market for CO2 emission certificates. The price of CO2 emission certificates for 2007 declined
steadily from 5.6 to 0.2 €/ton during 2007.
In 2006, which had a dry start of the year and a wet autumn, the total volume of electrical energy generated
by hydropower in the Nordic countries was 191 TWh. The hydrological balance started at a level slightly below
normal and reached its lowest level at more than 30 TWh below normal at the end of the summer before
increasing to levels near normal at the end of the year. The development of the hydrological situation and the
impact of the EU emissions trading scheme resulted in generally high and volatile prices for electricity. The daily
average Nordic spot price peaked in August above 80 €/MWh when four nuclear reactors had to be shut down
due to the Forsmark incident described below. The monthly average spot price was 40 €/MWh in January,
reached its highest value of 66 €/MWh in August and ended up with its lowest value, 33 €/MWh, in December.
The volatile spot prices during the year caused an increase in the average electricity spot price in 2006, which
reached 49 €/MWh compared with only 29 €/MWh in 2005.
2007 started with high hydroelectric production due to more precipitation than normal in the beginning of
the year. Throughout the rest of 2007 the hydrological balance stabilized at above average levels. The overall
water inflow amounted to about 220 TWh, roughly 10 percent higher than in a normal year. At the end of 2007,
reservoir levels were approximately 10 percent above normal. With a production volume of about 87 TWh,
nuclear production developed at nearly the same level as 2006. While 2006 production volumes were negatively
affected by precautionary shut downs of nuclear power plants due to the Forsmark 1 incident, production in 2007
was again negatively influenced by unplanned outages of all Swedish power plants, especially Ringhals 1-3 in
the beginning of the year. Altogether, the generally good hydrological situation and much lower emission costs
resulted in a lower average spot price of 28 €/MWh in 2007 compared to 49 €/MWh in 2006. The spot prices
remained rather stable until autumn 2007, when increasing fuel prices led to a sharp rise in the system spot
prices, reaching its top at 53 €/MWh in the end of November 2007.
In 2006, the Swedish parliament decided to prolong the electricity certificate system until 2030 in order to
support renewable electrical energy. This system, which was introduced in 2003, is a market-based support
system in which the price of electricity certificates is the result of the relation between supply and demand on the
electricity certificate market. The aim of the system is to increase the volume of electricity produced from
renewable sources by 17 TWh by 2016 as compared with the 2002 level. Electricity certificates are granted by
the Swedish government to generators of electricity from certain types of renewable sources. For every MWh of
electricity produced from such sources the generator is given one certificate that it can sell in addition to the
electricity generated. In order to create a demand for electricity certificates, it is mandatory for most electricity
end users (including residential end users) to purchase a certain number of certificates in proportion to their
consumption. This is known as the quota obligation. During 2004, the quota obligation amounted to 8.1 percent
of electricity consumed, and has since risen to 10.4 percent in 2005, 12.6 percent in 2006 and 15.1 percent in
2007. The quota obligation is scheduled to peak at 17.9 percent in 2010-2012 and thereafter decline to 8.9
percent in 2013 due to the phase out of some production units from the system. Any applicable end user who fails
to meet this quota obligation must instead pay a quota obligation charge to the Swedish government. E.ON
Nordic generally has earned a sufficient number of electricity certificates through its own wind power and
biomass production, and also has purchasing agreements with a number of small renewable electricity producers.
E.ON Nordic’s main competitors in the Nordic wholesale market are the Swedish energy company
Vattenfall AB (“Vattenfall”), the Finnish utility Fortum and the Norwegian energy company Statkraft. Vattenfall
and Fortum are also the main competitors of E.ON Nordic in the Swedish retail market, which is completely
deregulated.
Natural Gas. The Swedish gas pipeline system is constructed along the western coast of Sweden, starting in
Dragör, Denmark and ending in Gothenburg, Sweden. Gas represents 20 percent of the total energy supply in this
140
region, while at the national level, it comprises somewhat less than 2 percent of Sweden’s total energy supply. In
2007, gas consumption in Sweden amounted to approximately 10 TWh. The Swedish gas market is characterized
by a small number of companies and a high degree of vertical integration. There are currently about five
competitors active in the Swedish market, with E.ON Nordic accounting for the distribution and sale of
approximately half of all gas distributed and sold in Sweden in 2007. The major competitor in the end customer
market is the Danish gas company DONG and to a smaller extent municipally owned companies with customers
mainly in the geographic area of their municipality. The Finnish pipeline system is constructed in southern part
of Finland, and there is only one supply connection, coming from Russia. Total natural gas consumption volumes
in Finland are about 40 TWh, of which E.ON Nordic covers 0.7 TWh.
District Heating. District heating supplies residential buildings, commercial premises, and industry with
heat for space heating and residential hot water production.
In Sweden, most district heating companies are still owned by municipalities, although the current trend is
for large energy groups to acquire municipal companies. E.ON Nordic is actively participating in this
privatization process. District heating is not price-controlled. The price of competing alternatives serves,
however, as a ceiling for the prices that district heating companies can charge. E.ON Nordic also conducts some
heating operations in Denmark and Finland.
Non-regulated Business
Power Generation
General. E.ON Nordic owns interests in electric power generation facilities, mainly in Sweden, with a total
installed capacity of approximately 18,300 MW, of which its attributable share is approximately 7,400 MW (not
including mothballed, shutdown or reduced power plants).
E.ON Nordic generates electricity primarily at nuclear and hydroelectric plants, with a small percentage
generated at other types of power plants. In 2007, approximately 51 percent of E.ON Nordic’s electric output was
generated by nuclear, 44 percent by hydroelectric, and the remaining 5 percent by other fuels including oil, hard
coal, biomass, natural gas, wind and waste.
Based on the consolidation principles under IFRS, E.ON Nordic reports 100 percent of revenues and
expenses from majority-owned power plants in its consolidated accounts without any deduction for minority
interests. Conversely, 50 percent and minority-owned power plants are accounted for by the equity method.
Power generation in jointly owned plants is generally reported based on E.ON’s ownership percentage.
The construction of a new gas-fired CHP facility in the Swedish city of Malmö was initiated by E.ON
Nordic during 2006. The new plant is expected to begin commercial operation in early 2009 and to contribute a
total capacity of 440 MW of electricity and 250 MW of heat. In addition, efficiency improvements, which are
aimed at increasing generation capacity, are planned for the nuclear reactors in Forsmark, Ringhals and
Oskarshamn. The implementation of these efficiency measures was started in 2005. Pending receipt of the
necessary approvals, E.ON Nordic expects that all major efficiency improvements will be completed by 2011.
Nuclear Power. E.ON Nordic operates three Swedish nuclear power plants (Oskarshamn 1 — 3), which
provided 51 percent of E.ON Nordic’s total power output in 2007. In addition, E.ON Nordic holds minority
participations in all other Swedish nuclear power reactors. E.ON Nordic receives a share of the electrical power
produced at these plants according to its respective shareholding. The purchase price for this electricity is
determined on the basis of the total costs for each facility and is paid according to the shareholding in each
reactor.
E.ON Nordic’s nuclear power plants are required to meet applicable Swedish safety standards, which are
described in “— Environmental Matters — Nordic.” In Sweden, nuclear waste is handled by Svensk
141
Kärnbränslehantering AB (“SKB”), which is owned by the domestic nuclear power producers and supervised by
various state institutions. Sweden’s low and intermediate-level nuclear waste is deposited in the Repository for
Radioactive Operational Waste, located at the Forsmark nuclear power plant. Spent nuclear fuel and other highlevel nuclear waste are placed in temporary storage at the Central Interim Storage Facility for Spent Nuclear
Fuel, situated near the Oskarshamn nuclear power plant. No long-term repository has yet been constructed for
spent nuclear fuel, but SKB is planning to build a deep repository for the long-term storage of all spent nuclear
fuel. E.ON Nordic expects that a decision will be taken on where the deep repository is to be built at the earliest
by 2012, with the first nuclear waste expected to be stored there after 2020.
In 1997, a law concerning the phase out of nuclear power was passed pursuant to which the government can
decide to revoke a license to conduct nuclear operations, but must compensate the owner of the nuclear plants
that are phased out. E.ON Nordic’s Barsebäck 1 reactor was closed under this law in 1999, while Barsebäck 2
was closed in 2005, with E.ON Nordic receiving compensation in each case. During 2006, the compensation
agreement concerning the closure of Barsebäck 2 was fully and finally implemented, with E.ON Sverige’s
interest in Ringhals AB being increased to 29.56 percent at no cost to E.ON Nordic.
E.ON Nordic currently has no other nuclear power plants that have been explicitly targeted for early
phase-out by the Swedish government. However, it is unclear if and to what extent such shutdowns may be
required in the future.
In Sweden, the financing system for the handling of high-level nuclear waste as well as the dismantling of
nuclear facilities is currently based on a fee charged per generated kWh of electricity. The exact amount is
regularly calculated based on assumptions about the expected period of operation for each reactor by the Swedish
Nuclear Power Inspectorate and ultimately determined by the Swedish government. Nuclear power operators
include this fee in the price of electricity and transfer it to the national Nuclear Waste Fund. The purpose of this
fund is to cover all expenses incurred for the safe handling and final disposal of spent nuclear fuel, as well as for
dismantling nuclear facilities and disposing of decommissioning waste. For information on changes to this
financing system, see “— Environmental Matters — Nordic.” Expenses for other low and intermediate-level
operational nuclear waste have to be directly covered by the nuclear operators. For this purpose, E.ON Nordic
has provisions totaling €8.2 million as of December 31, 2007.
In Sweden, taxes are levied on the production of nuclear power based on the installed nuclear power
capacity. This tax amounted to approximately €7,230 per MW of thermal power in 2005. In December 2005, the
Swedish parliament approved an 85 percent increase in the nuclear tax effective as of January 2006, at which
time the tax increased to approximately €13,400 per MW of thermal power. As a consequence, E.ON Nordic’s
related tax expense increased by €36 million in 2006. In 2007, there was no further increase in nuclear
production tax. In December 2007, the Swedish parliament approved a further 24 percent increase in the nuclear
tax effective as of January 2008, at which time the tax increased to approximately €16,620 per MW of thermal
power. As a consequence, E.ON Nordic’s related tax expense will increase by €25 million in 2008.
E.ON Nordic purchases fuel elements for nuclear power plants from international suppliers. E.ON Nordic
considers the supply of uranium and fuel elements on the world market to be adequate.
Nuclear generated electricity in the Swedish market decreased significantly in 2007 compared to 2006. 2006
was characterized by high production during the first half of the year and low production during the second half
of the year due to the Forsmark incident (a transmission related incident at Forsmark 2 in late July 2006 that
resulted in an emergency shutdown of Forsmark 2, and the precautionary shutdown of Oskarhshamn 1 and
Oskarshamn 2). The reduced nuclear generation in Sweden during 2007 compared to 2006 was mainly a
consequence of prolonged outages at Ringhals and Oskarshamn. Due to the 2006, Forsmark incident, the
availability of Forsmark was naturally higher than in 2006 thus partly offsetting lower production from the other
Swedish nuclear power plants. Total nuclear generation in the Swedish market was 0.7 TWh lower than in 2006.
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Hydroelectric. E.ON Nordic operates 115 Swedish hydroelectric plants, which provided approximately 44
percent of E.ON Nordic’s total power output in 2007. Due to the presence of mountains and rivers, hydroelectric
plants are generally located in northern Sweden. Due to natural variances in annual water inflow to the hydro
reservoirs, hydroelectric plants can be subject to reduced operations during periods of low precipitation. Notably,
during periods of low precipitation market prices for electricity increase, while during periods with high
precipitation market prices decrease. Thus, variances in rainfall in the region can have a significant positive or
negative effect on the Nordic market unit’s financial and operating results. In 2007, the inflow to E.ON Nordic’s
hydro reservoirs was about 10 percent above normal inflow. Therefore, the production from hydroelectric assets
was significantly higher in the year 2007 compared to 2006. According to the letter of intent signed by E.ON AG
and Statkraft, approximately one third of E.ON Nordic’s hydropower plant capacity will be transferred to Statkraft.
Hydropower plants in Sweden are subject to real estate taxes. In 2006, the Swedish parliament approved an
increase of the real estate tax rate from 0.5 percent to 1.7 percent. As a consequence, E.ON Nordic’s real estate
tax expense increased by €27 million in 2006. In 2007, the Swedish parliament approved a further increase of the
real estate tax rate from 1.7 percent to 2.2 percent effective as of January 2008. As a consequence, E.ON
Nordic’s real estate tax expense will increase by €13 million in 2008.
Other Power Plants. Power plants fuelled by fuel oil, hard coal, biomass, natural gas, wind power and waste
provided the remaining 4 percent of E.ON Nordic’s total power output in 2007. Wind power plants are usually
used for electricity base load operations. Oil- and gas-fired plants are only used for peak load operations, when
market prices cover the operational cost. The production planning of CHP plants is to a large degree dependent
on temperature conditions. Fuel oil, natural gas, hard coal and biomass are generally available from multiple
sources, though prices are determined on international commodities markets and are therefore subject to
fluctuations. Waste is purchased under supply contracts with local providers.
Demand for power tends to be seasonal, rising in the winter months and typically resulting in additional
electricity sales by E.ON Nordic in the first and fourth quarters.
Although E.ON Nordic’s power plants are maintained on a regular basis, there is a risk of failure for power
plants of every fuel type. Depending on the associated generation capacity, the length of the outage and the cost
of the required repair measures, the economic damage due to such failure can vary significantly. Thus, as with
water shortages, power plant outages can negatively affect the market unit’s financial and operating results.
Retail
E.ON Nordic and its associated companies sell electricity, gas and district heating, as well as other energyrelated services, to residential and commercial customers, mainly in the southern parts of Sweden. In addition,
E.ON Nordic sells a limited amount of electricity, gas and district heating to end customers in Denmark, Finland
and Poland.
Electricity. As of December 31, 2007, E.ON Nordic supplied electricity to approximately 833,000 electricity
customer accounts in Sweden and to a minor degree in Denmark. Through its subsidiaries E.ON Suomi Oy,
Kainuun Energia Oy and Karhu Voima Oy, E.ON Nordic supplied approximately 87,000 customers in Finland.
Although the majority of E.ON Nordic’s customer accounts are with residential customers, the majority of its
sales volumes are with commercial customers. E.ON Nordic sold a total of 18.0 TWh of electricity in 2007, of
which 5.5 TWh was delivered to residential customers and 12.5 TWh was delivered to commercial customers
(including municipal distributors). E.ON Nordic’s electricity customers are concentrated in the south of Sweden,
the areas of Stockholm, Örebro and Norrköping, the Mid-Norrland region, as well as in the eastern and southern
parts of Finland, although E.ON Nordic potentially serves customers throughout the Nordic region.
Gas. In the Swedish gas market, E.ON Nordic supplied approximately 13,500 customers with gas in 2007;
3.5 TWh were delivered to large industrial and (mostly municipal) distribution customers, and 0.1 TWh was
delivered to residential customers. E.ON Nordic also supplied a small amount of gas in Denmark (0.4 TWh) and
Finland (0.7 TWh) in 2007.
143
Heat & Waste. E.ON Nordic sells heating, primarily district heating, to approximately 31,500 customers in
Sweden, Denmark and Finland. In 2007, sales of district heating amounted to 5.3 TWh in Sweden, 0.1 TWh in
Denmark, and 0.3 TWh in Finland. In addition, E.ON Nordic sold a de minimis amount of heat in Poland in
2007.
E.ON Nordic is also active in the Swedish waste business, mainly through SAKAB Ecoplus AB and
SAKAB AB (“SAKAB”). SAKAB’s operations focus on recycling and destroying hazardous waste. In addition,
SAKAB treats a small portion of household waste and industrial refuse for heat-recovery purposes. In 2007,
E.ON Nordic’s waste activities had combined sales of approximately €60 million. Waste volumes handled
amounted to approximately 590,000 tons.
Other Activities. E.ON Nordic provides services for distribution networks and other services primarily in
Sweden through E.ON Sverige’s subsidiary E.ON ES AB (formerly ElektroSandberg AB). In August 2006,
E.ON Sverige sold a 75.1 percent interest in the broadband communication business E.ON Sverige Bredband AB
(“E.ON Sverige Bredband”) to Tele2 Sverige AB (“Tele2”). In June 2007, E.ON Sverige exercised its put option
on the remaining 24.9 percent interest in E.ON Sverige Bredband and no longer holds any interest in the
company.
Trading
Until the end of 2007, E.ON Nordic’s energy trading activities focused on electricity trading on the Nord
Pool exchange, but also to a lesser extent include other commodities such as oil, natural gas, CO2 emission
certificates and propane. As soon as E.ON AG takes over Statkraft’s 44.6 percent interest in E.ON Sverige, E.ON
Nordic’s trading activities will be transferred to the new Energy Trading market unit. For information about EET,
see “Business — Our Business.”
E.ON Nordic uses energy trading to optimize the value of and manage risks associated with its energy
portfolio. E.ON Nordic also performs a limited amount of proprietary trading, as well as providing portfolio
management services for external clients, including access to energy exchanges, advice and risk management for
their portfolios. Since 1999, E.ON Trading Nordic AB has been fully authorized by the Swedish Financial
Supervisory Authority to advise and conduct trading on behalf of portfolio management clients.
All of E.ON Nordic’s energy trading operations, including its limited proprietary trading, are subject to
E.ON’s risk management policies for energy trading.
The following table sets forth the total volume of E.ON Nordic’s traded electric power in 2007 and 2006.
2007
million kWh
2006
million kWh
%
Change
Power sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power purchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31,023
31,508
28,281
28,304
+9.7
+11.3
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62,531
56,585
+10.5
Trading of Power
The major part of realized trading volumes is usually contracted in the year prior to realization. Trading
volumes increased in 2007 compared with 2006 due to higher volumes being contracted as well as realized
during 2007.
Regulated Business
Electricity Distribution
E.ON Nordic and its associated companies are actively involved in electricity distribution activities in both
Sweden and Finland.
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In Sweden, the 200-400 kV electricity grid is owned and managed by Svenska Kraftnät, a state agency
controlled by the Swedish state. 30-130 kV electricity is transmitted through a regional distribution network with
a length of around 40,000 km, of which E.ON Nordic owns and manages 8,000 km, located in southern Sweden
and around Sundsvall in the north of Sweden. The local distribution networks are managed by about 180
different grid companies, including E.ON Nordic. The length of the total local network for Sweden is about
550,000 km, of which E.ON Nordic owns 117,000 km. Balance control for the whole system is managed by
Svenska Kraftnät.
In January 2007, Sweden was hit by storm “Per”. This storm caused significant damage to E.ON’s
distribution network. In addition, outage compensation to the customers had to be paid according to the current
regulatory framework. Approximately 300,000 households in Sweden, including approximately 170,000 of E.ON
Sverige’s customers, were affected by power outages. Some customers, including E.ON Sverige customers, were
left without electricity for up to ten days. In total, storm-related costs amounted to €95 million, which were
accounted for as non-operating expenses.
As a result of a similarly severe storm in 2005, the Swedish government passed new legislation concerning
electricity distribution in December 2005. Under the new law, the major part of which came into force on
January 1, 2006, a customer shall be compensated for power outages that last more than 12 hours, with the
compensation payment being equal to at least 12.5 percent and up to 300 percent of the customer’s annual
network charges, with compensation being based on the length of the outage. With effect from January 1, 2011,
the maximum allowable period of time for a power outage is 24 hours. Following this new legislation, E.ON
Nordic has set the timetable for a major part of the ongoing reinvestments in the electricity network to be
completed by 2010. E.ON Nordic expects that this will to a large extent reduce its exposure to weather-related
damage in the future. The investments done in “Krafttag”, the major reinvestment program launched after storm
“Gudrun” in 2005 to secure and increase the reliability of the local and regional distribution grids, have so far
resulted in the number of customers being affected by major disturbances, as well as related costs for the outage
fee, being reduced by about 25 percent.
The electricity grid in Sweden is linked to the power transmission grids in Norway, Finland and Denmark.
In addition, the Baltic Cable links the Swedish transmission grid to the grid of E.ON Netz in Germany. The
Baltic Cable is one of the longest (250 km) direct current submarine cables in the world, with a capacity of 600
MW. E.ON Nordic owns one-third of the cable through E.ON Sverige, with the remaining two-thirds owned by
the Norwegian company Statkraft.
In 2007, E.ON Nordic’s distribution network served approximately one million customers, including
approximately 593,000 customers in southern Sweden, 325,000 customers in the metropolitan areas of
Stockholm/Örebro/Norrköping and 83,000 customers in the Mid-Norrland region. The areas around the cities of
Malmö (in southern Sweden), Stockholm, Örebro and Norrköping belong to the more densely populated areas of
Sweden, but parts of southern Sweden and Norrland are more rural areas with a lower density.
E.ON Nordic also owns and operates local power distribution grids in Finland through Kainuun Energia Oy
(approximately 54,800 customers in eastern Finland), with a length of 12,663 km, and Karhu Voima Oy (16
industrial customers in southern Finland), with a length of 17 km.
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The following map shows E.ON Nordic’s current distribution areas.
Kainuun Energia
Mid-Norrland
Stockholm
Mälardalen/Örebro
Norrköping
Southern Sweden
Malmö
In Sweden and Finland, electricity customers have separate contracts with a retail supplier and an electricity
distributor. For this reason, distribution customers of E.ON Nordic may choose other retail suppliers and E.ON
Nordic may sell electricity to customers not covered by its own distribution grids. For information on grid access,
see “— Regulatory Environment — Nordic.”
Gas Transmission, Distribution and Storage
The Swedish gas pipeline system is constructed along the western coast of Sweden, starting in Dragör,
Denmark and ending in Gothenburg, Sweden. Gas represents approximately 20 percent of total energy supply in
the Nordic region, while at the national level, it comprises somewhat less than 2 percent of Sweden’s total energy
supply. The 320 km national gas transmission pipeline is owned by Swedegas AB, a consortium in which E.ON
Ruhrgas International AG holds a 29.6 percent interest. E.ON Nordic owns, operates and maintains a regional
high-pressure gas pipeline with a length of 202 km and a low-pressure gas distribution pipeline with a length of
1,700 km. In addition, E.ON Nordic has an underground gas storage facility in Getinge with a working capacity
of 8.5 million m3 and a maximum withdrawal rate of 40 thousand m3/hour. In 2006, E.ON Nordic transported a
total of 6.0 TWh of gas through its gas pipeline system.
The Swedish natural gas market is currently connected to the Danish natural gas market through one supply
route. Sweden’s strategic location between two of the largest producers, Russia and Norway, has led to the
initiation of several studies and projects with the aim of increasing supplies to or via Sweden.
U.S. Midwest
Overview
E.ON U.S. is a diversified energy services company with businesses in power generation, retail gas and
electric utility services, as well as asset-based energy marketing. Asset-based energy marketing involves the
146
off-system sale of excess power generated by physical assets owned or controlled by E.ON U.S. and its affiliates.
E.ON U.S.’s power generation and retail electricity and gas services are located principally in Kentucky, with a
small customer base in Virginia and Tennessee. As of December 31, 2007, E.ON U.S. owned or controlled
aggregate generating capacity of approximately 7,500 MW. In 2007, E.ON U.S. served more than one million
customers. The U.S. Midwest market unit recorded sales of €1,819 million in 2007 and adjusted EBIT of €388
million.
Operations
In the areas of the United States in which E.ON U.S. operates, electricity generated at power stations is
delivered to consumers through an integrated transmission and distribution system. For information about the
principal segments of the electricity industry, see “— Central Europe — Operations.” In 2007, E.ON U.S. was
actively involved in generation, transmission, distribution, retail and trading in the states in which it had utility
operations.
E.ON U.S. divides its operations into regulated utility and non-regulated businesses. Utility operations are
subject to state regulation that sets rates charged to retail customers.
In the regulated utility business, which accounted for 97 percent of E.ON U.S.’s revenues in 2007 (85
percent electricity, 15 percent gas), E.ON U.S. operates two wholly-owned utility subsidiaries: Louisville Gas
and Electric Company (“LG&E”), an electricity and natural gas utility based in Louisville, Kentucky, which
serves customers in Louisville and 17 surrounding counties, and Kentucky Utilities Company (“KU”), an electric
utility based in Lexington, Kentucky, which serves customers in 77 Kentucky counties, five counties in Virginia
and one county in Tennessee.
E.ON U.S.’s non-regulated business, which accounted for 3 percent of E.ON U.S.’s sales in 2007, is
comprised of the operations of E.ON U.S. Capital Corp. (“ECC”).
Market Environment
In the United States, the market environment for electricity companies varies from state to state, depending
on the level of deregulation enacted in each jurisdiction.
The electric power industry remains highly regulated at the retail level in much of the U.S., including
Kentucky, although in some parts of the country, it has become more competitive as a result of price and supply
deregulation and other regulatory changes. In approximately one-third of the United States, retail electricity
customers can now choose their electricity supplier; however, some states have taken steps to halt deregulation or
implement re-regulation, including Virginia. To better support a competitive industry, federal regulators are
transforming the manner in which the electric transmission grid is operated. Transmission owning entities are
generally encouraged by federal regulators to transfer individual control over the operation of their transmission
systems to regional transmission organizations (“RTOs”). These RTOs are intended to ensure non-discriminatory
and open access to the nation’s electric transmission system. Depending on the specifics of deregulation in the
states in which they operate, U.S. electric utilities have adopted different strategies and structures, sometimes
divesting one or more of the generation, transmission, distribution or supply components of their businesses.
E.ON U.S. was previously part of MISO. See the further discussion under “Transmission” below.
E.ON U.S.’s electric service territories are located in Kentucky, Virginia and Tennessee. At present, due to
the absence of customer choice or competitive market requirements in Kentucky and Tennessee and the passage
of legislation in Virginia exempting KU from the provisions of that state’s liberalization measures, none of E.ON
U.S.’s retail utility operations are subject to customer choice or competitive market conditions. E.ON U.S.’s
customers are therefore generally required to purchase their electric service from E.ON U.S.’s utility subsidiaries
at prices approved by state governmental regulators.
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E.ON U.S.’s primary retail electric service territories are located in Kentucky, which accounted for
74 percent of E.ON U.S.’s total revenues in 2007. To date, neither the Kentucky General Assembly nor the
Kentucky Public Service Commission (“KPSC”) have adopted or announced a plan or timetable for retail electric
industry competition in Kentucky. However, the nature or timing of any new legislative or regulatory actions
regarding industry restructuring or the introduction of competition and their impact on LG&E and KU cannot
currently be predicted.
Although retail choice became available for many customers in Virginia in January 2002 pursuant to the
Virginia Electric Restructuring Act (the “Restructuring Act”), KU remains exempt from the provisions of the
Restructuring Act until such time as KU provides competitive electric service to retail customers in any other
state. Further, in April 2007, Virginia enacted legislation which will terminate competitive electric service in the
state at the end of 2008 and adopt a hybrid model of re-regulation, whereby utility rates would be reviewed
biannually and a utility’s rate of return on equity will be set so as not to be lower than the average of the rates of
return for other regional utilities, subject to certain caps, floors or adjustments. Subject to further developments,
KU may or may not undertake such a rate proceeding in early 2009 under this legislation based upon calendar
year 2008 financial data. During 2007, KU’s Virginia operations accounted for 5 percent of KU’s total revenues
and 2 percent of E.ON U.S.’s total revenues. E.ON U.S.’s very limited Tennessee operations accounted for less
than 1 percent of its total revenues in each of 2007 and 2006.
Seasonal variations in U.S. demand for electricity reflect the summer cooling period as the time of peak load
requirements, with a lesser peak during the winter heating period, the latter primarily in regions which do not
have extensive gas distribution networks. The peak period of retail gas demand is the winter heating period.
Regulated Business
LG&E. LG&E is a regulated public utility that generates and distributes electricity to approximately
401,000 customers and supplies natural gas to approximately 326,000 customers in Louisville and adjacent areas
of Kentucky as of December 31, 2007. LG&E’s service area covers approximately 700 square miles in 17
counties. LG&E’s coal-fired electric generating plants, most of which are equipped with systems to reduce SO2
emissions, produce a significant amount (97 percent) of LG&E’s electricity; the remainder is generated by
gas-fired combustion turbines (approximately 2 percent) and by a hydroelectric power plant. Underground
natural gas storage fields assist LG&E in providing economical and reliable gas service to customers. As of
December 31, 2007, LG&E owned steam and combustion turbine generating facilities with an attributable
capacity of 3,083 MW and a 50 MW hydroelectric facility on the Ohio River.
KU. KU is a regulated public utility engaged in producing, transmitting, distributing and selling electric
energy. KU provides electric service to approximately 506,000 customers in 77 counties in central, southeastern
and western Kentucky and approximately 30,000 customers in five counties in southwestern Virginia as of
December 31, 2007. In Virginia, KU operates under the name Old Dominion Power Company. KU also sells
wholesale electric energy to 12 municipalities and five customers in Tennessee. KU’s coal-fired electric
generating plants produce a significant amount (96 percent) of KU’s electricity; the remainder is generated by
gas-fired combustion turbines (approximately 4 percent) and a hydroelectric facility. As of December 31, 2007,
KU owned steam and combustion turbine generating facilities with an attributable capacity of 4,362 MW and a
24 MW hydroelectric facility.
Power Generation
Fuel. Coal-fired steam and combustion turbine generating units provided approximately 97 percent of
LG&E’s and KU’s net kWh generation for 2007. The remainder of 2007 net generation was produced by natural
gas-fueled combustion turbine peaking units (approximately 3 percent) and hydroelectric plants. E.ON U.S. is
currently building a second coal-fired (750 MW) unit at Trimble County which is expected to come on line in
2010. E.ON U.S.’s interest will be 75.0 percent. E.ON U.S. has no nuclear generating units and coal will
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continue to be the predominant fuel used by E.ON U.S.’s subsidiaries for the foreseeable future. LG&E and KU
have entered into coal supply agreements with various suppliers for coal deliveries for 2008 and beyond and
normally augment their coal supply agreements with spot market purchases. The companies have coal inventory
policies which they believe provide adequate protection under most contingencies. Reliability of coal deliveries
can be affected from time to time by a number of factors, including fluctuations in demand, coal mine labor
issues and other supplier or transporter operating or contractual difficulties.
Each of LG&E and KU expect to continue purchasing much of their coal, which has varying sulphur content
ranges, from western Kentucky, southern Indiana, southern Illinois, Ohio and West Virginia, with additional KU
purchases from eastern Kentucky. In general, the delivered cost of coal has been rising since late 2002.
LG&E purchases natural gas transportation services from both of the major, trans-continental natural gas
transmission pipeline companies operating in the southern Midwest region. LG&E also has a portfolio of gas
supply arrangements with a number of suppliers in order to meet its firm sales obligations. These gas supply
arrangements have various terms and include pricing provisions that are market-responsive. LG&E believes these
firm supplies, in tandem with the pipeline transportation services, provide the reliability and flexibility necessary
to serve LG&E’s gas customers. LG&E operates five underground gas storage fields with a current working gas
capacity of 15.1 billion cubic feet. Gas is purchased and injected into storage during the summer season and is
then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter
heating season. LG&E and KU primarily buy natural gas and oil fuel used for generation on the spot market.
LG&E and KU have limited exposure to market price volatility in prices of coal and natural gas, as long as
cost pass-through mechanisms, including the fuel adjustment clause and gas supply clause, exist for retail
customers. For a more detailed explanation of these mechanisms, see “— Regulatory Environment — U.S.
Midwest.”
Asset-Based Energy Marketing. LG&E and KU conduct energy trading and risk management activities to
maximize the value of power sales from physical assets they own. These off-system sales accounted for 1.6 TWh
in 2007. Energy trading activities are principally forward financial transactions to hedge price risk and are
accounted for on a mark-to-market basis in accordance with IAS 39. Prior to the Midwest Independent
Transmission System Operator, Inc. (“MISO”) establishing its energy market in April 2005, wholesale forward
transactions were treated as own use under IAS 39 and were not marked-to-market.
Transmission
E.ON U.S.’s utility subsidiaries LG&E and KU operate 4,924 miles of transmission line. In September
2006, these entities withdrew from MISO, in which they had participated as transmission owning members since
1998 and which commenced commercial operations in February 2002. In connection with their withdrawal from
MISO, LG&E and KU paid an exit fee of $33 million, which remains subject to certain adjustments, including a
potential partial refund of $6.4 million over eight years, subject to regulatory approval and future calculations.
Following exit from MISO, LG&E and KU have contractually engaged two independent third parties to perform
certain of oversight and function control activities formerly performed by MISO relating to their transmission
systems, in accordance with applicable Federal Energy Regulatory Commission (“FERC”) regulations. The
Southwest Power Pool, Inc. (“SPP”) now functions as the transmission system operator and the Tennessee Valley
Authority (“TVA”) now functions as the reliability coordinator, respectively, for LG&E and KU.
For additional information about transmission developments, see “— Regulatory Environment — U.S.
Midwest.”
Distribution/Retail
The electric retail activities of LG&E and KU are limited to their respective service territories in Kentucky,
with a small KU service region in Virginia and service to five customers in Tennessee. In 2007, LG&E’s total
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electric retail sales to residential, commercial and industrial customers were 11.3 billion kWh and its total
aggregate electric sales, including off-system sales, were 14.2 billion kWh. In 2007, KU’s total electric retail
sales to residential, commercial and industrial customers were 17.1 billion kWh and its total aggregate electric
sales were 21.7 billion kWh.
The following table sets forth LG&E’s and KU’s sale of electric power for the periods presented:
Total 2007
million kWh
Total 2006
million kWh
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial and industrial customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-system sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,333
17,038
2,059
3,871
1,629
10,330
16,628
1,978
3,703
2,650
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35,930
35,289
Sales of Electric Power to
The gas retail activities of LG&E are limited to its service territory in Kentucky. In 2007, LG&E’s total
retail gas sales were 13.1 billion kWh (2006: 12.3 billion kWh) and its total aggregate gas sales (including
off-system sales) were 13.6 billion kWh (2006: 12.4 billion kWh).
Non-regulated Businesses
ECC. ECC is the primary holding company for E.ON U.S.’s non-regulated businesses, which now consist
primarily of interests in Argentine gas distribution operations which provide natural gas to approximately one
million customers in Argentina through two distributors, Distribuidora de Gas del Centro S.A. (“Centro”) and
Distribuidora de Gas Cuyana S.A. (“Cuyana”)). ECC owns 45.9 percent of Centro, and 14.4 percent of Cuyana.
These operations continue to be subject to economic and political risks typical of emerging markets. In June
2007, ECC sold its interests in the Argentine gas distribution company, Gas Natural BAN S.A. (“Ban”) and
related companies for €37 million. ECC had held an approximate 19.6 percent interest in Ban since 1999. In June
2006, ECC sold (i) its 50.0 percent ownership interest in a coal-fired facility in North Carolina and (ii) its
remaining operations and maintenance contracts relating to the North Carolina plant and four independent power
generation facilities for total consideration of €21 million. ECC also currently owns the discontinued operations
of Western Kentucky Energy Corp. and affiliates (“WKE”). For further details, see “Operating and Financial
Review and Prospects — Results of Operations — Discontinued Operations.”
Environmental Matters
General
E.ON is subject to numerous national and local environmental laws and regulations concerning its
operations, products and other activities in the various jurisdictions in which it operates. Although E.ON believes
that its domestic and international production facilities and operations are currently in material compliance with
the laws and regulations with respect to environmental matters, such laws and regulations could require E.ON to
take future action to remediate the effects on the environment of prior disposal or release of substances or waste.
Such laws and regulations could apply to various sites, including power plants, pipelines and gas storage
facilities, and waste disposal sites. Such laws and regulations could also require E.ON to install additional
controls for certain of its emission sources or undertake changes in its operations in future years. For greater
detail on the application of environmental laws and regulations to E.ON’s operations, see below. E.ON has
established and continues to establish accruals for environmental liabilities where it is probable that a liability
will be incurred and the amount of the liability can be reasonably estimated. The provisions made are considered
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to be sufficient for known requirements. E.ON adjusts accruals as new remediation commitments are made and
as information becomes available which changes estimates previously made.
The extent and cost of future environmental restoration and remediation programs are inherently difficult to
estimate. They depend on the magnitude of any possible contamination, the timing and extent of corrective
actions required and E.ON’s share of liability relative to that of other responsible parties.
Any failure to comply with present or future environmental laws or regulations could result in the
imposition of fines, suspension of operations or production or alteration of production processes. Such laws or
regulations could also require acquisition of expensive remediation equipment or other expenditures to comply
with environmental regulation.
Germany
During the conference in Meseberg in 2007, the Federal Government enacted the main issues of the
Integrated Energy and Climate program (Integriertes Energie- und Klimaprogramm, or “IEKP”). This program
aims at the national implementation of the European decisions of spring 2007 concerning climate protection,
expansion of renewable energy and energy efficiency. The targets are documented in a package of measures,
which is to be concretized in 2008 and to be achieved continuously until 2020. The IEKP has basic consequences
for the environmental policy of energy supply companies including E.ON.
A first package of 14 measures on energy efficiency (revision of CHP law, liberalization metering, outline
for a new Energy Savings Act, Power Plant Emissions Act, guideline for public sourcing), renewable energies for
power and heat (Renewables Act, Regenerative Heat Act, Access Rules for Biogas), biofuels, motor vehicle
taxation and on other GHG emissions was adopted by the German Federal Government on December 5, 2007.
The legislative procedure started in January 2008.
Combined heat and power generation. To employ fuels more efficiently, the proportion of combined heat
and power generation is supposed to be doubled from currently about 12 percent to approximately 25 percent. In
order to hit this target, an amendment of the Combined Heat and Power Act (Kraft-Wärme-Kopplungs-Gesetz) is
planned to financially support new combined heat and power plants — also for industrial use — and district
heating grids.
Renewable Energy Sources Act. The Federal Government aims to increase the share of renewable energies
in the electricity sector from currently 14 percent to 25 – 30 percent in 2020 and a continuous increase thereafter.
For that purpose, an amendment of the Renewable Energy Sources Act (Erneuerbare-Energien-Gesetz) is
envisioned to rearrange among other things the remuneration for the feed in to the network of electricity from
offshore wind parks.
Regenerative Heat Act. The Federal Government sees a high potential for renewable energy sources in the
heat sector in order to support climate protection and the reduction of fossil fuel consumption. The share of
renewable energy in heat supply is to be increased from 6.5 percent in 2007 up to 14 percent by 2020. For these
purposes the Regenerative Heat Act (Erneuerbare-Energien-Wärmegesetz) shall define obligations to use
renewable energy sources in new buildings.
Main issues to draft an amendment of the Ordinance on Energy Savings. In the building sector, energy
requirements determined by the Ordinance on Energy Savings (Energieeinsparverordnung) are going to be raised
successively (30 percent in 2009, a post 2012 increase of comparable magnitude). Furthermore the Federal
Government envisages the interdiction of electric night storage heaters post 2020. The Cabinet is expected to
enact a complete amendment of the Ordinance on Energy Savings in May 2008.
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Support programs for energy-efficient construction and refurbishment of buildings and social
infrastructure. The existing CO2- refurbishment program for buildings (CO2-Gebäudesanierungsprogramm) is
going to be enhanced and continuously advanced till 2011. Moreover the support program is intended to tap the
full potential of energy savings in urban structures and social infrastructure. Up to €200 million is being provided
for reductions in the interest rates of related loans to local authorities.
Research and innovation in the energy sector. The Federal Government strives for new initiatives focusing
on climate protection, energy efficiency, renewable energy sources and storage of CO2, thus strengthening the
technological leadership of German companies on the global market.
Allocation of funds from the federal budget. The integrated energy and climate policy is also reflected in the
federal budget. Approximately €3.3 billion (including up to €400 million from sales of emission certificates and
about €700 million from bilateral and multilateral development cooperation) are to be available for climate
policy during the fiscal year 2008.
Europe
2007 marked a turning point for the European Union’s climate and energy policy. The European Council
agreed in March 2007 to set legally binding targets: A reduction of at least 20 percent in greenhouse gases by
2020 — rising to 30 percent if there is an international agreement committing other developed countries to
“comparable emission reductions and a 20 percent share of renewable energies in EU energy consumption by
2020. To translate the European Union’s political decision into action the European Commission proposed a
package of measures (Green Package) on January 23, 2008. The proposals are now going into the EU legislative
codecision procedure. The process will most likely not be finished before end of 2008. The two major aspects of
the package are:
•
Promotion of Renewable Energies: Today, the share of renewable energy in the EU’s final energy
consumption is 8.5 percent. An increase of 11.5 percent is needed on average to meet the target of 20
percent in 2020. The Commission’s proposal is based on a methodology according to which half of the
additional effort is shared equally between Member States. The other half is modulated according to
GDP per capita. The Commission is not setting sectoral targets except of a minimum requirement of 10
percent for biofuels. Further, the proposed directive aims at removing unnecessary administrative
barriers to the growth of renewable energy.
•
New Emission Trading Scheme post-2012: The European Commission has submitted its proposal
concerning the energy policy aiming at the reduction of CO2-emissions. Based on the decision of the EU
Council from March 2007, a decrease of greenhouse gas emissions of 20 percent by 2020 compared to
the year 1990 is assumed in the proposal. According to the concept of the Commission, as from 2013
industry, heat production from CHP, refineries and the aviation sector have to purchase by auction on
average 20 percent of the hitherto predominantly freely allocated certificates, with the quota rising to
100 percent in 2020. Energy suppliers are supposed to pay for all emission rights as from 2013. A
further shortage of CO2 rights could have consequences for the energy suppliers strategies. With regard
to the energy mix, the price for power from coal could increase in relation to gas and consequently
influence investment decisions concerning the construction of new power plants.
•
The EU directive on energy end-use efficiency and energy services (Directive 2006/32/EC of the
European Parliament and of the Council of April 5, 2006 on Energy End-Use Efficiency and Energy
Services Repealing Council Directive 93/76/EEC) was adopted in February 2006 and must be
implemented into national law by May 2008. It provides for indicative targets for member states to
reduce overall end energy consumption by nine percent over a nine-year period (ending in 2016), which
would be achieved by boosting energy efficiency measures in the EU. The deadline for member states to
propose national action plans on end-user energy efficiency was July 2007. The German action plan was
submitted in September 2007. The EU Commission is currently monitoring all the national action plans
and will then deliver further proposals in the field of energy efficiency. The action plan is currently
without legal effect and we cannot predict when the Commission will come out with new proposals.
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U.K.
While E.ON UK in the United Kingdom is subject to the same EU environmental legislation as is E.ON
Energie (described above under “— Germany: Electricity”), details of the implementation of that legislation as
adopted in the United Kingdom differ from those implemented by the German government. E.ON UK is also
subject to national legislation which includes the obligations of the United Kingdom and international
conventions to which the United Kingdom adheres. These obligations relate principally to emissions from
generating facilities to air, notably of SO2, NOx and dust. Although historically such legislation has primarily
affected coal-fired plants, all fossil-fuelled generation may be impacted in the future. E.ON UK is currently in
compliance with all applicable emissions regulations.
As an alternative to setting rigid emission limit values, the EU Large Combustion Plants Directive (LCPD)
allows each member state to include its existing large combustion plants within a single National Emissions
Reduction Plan. The European Commission has agreed to the United Kingdom using a “combined approach”
scheme which would allow individual plants to elect to either to be subject to emission limit values, to be part of
the National Emissions Reduction Plan or to opt out of the scheme (in which case the plant must shut by the end
of 2015 and is limited to 20,000 hours of operation in the period from 2008 to 2015). E.ON UK has decided to
opt out the Grain, Kingsnorth and Ironbridge power stations (which it must therefore close by 2015) and to use
the emission limit value option for the Ratcliffe power station. The scheme is scheduled to take effect as of
January 1, 2008.
The U.K. government has implemented a greenhouse gas emissions allowance trading scheme, as required
by the EU’s Emissions Trading Directive. For more information on the Emissions Trading Directive, see
“— Regulatory Environment.” The trading scheme requires that each participating plant be covered by one or
more CO2 emission certificates, which initially were issued free of charge. E.ON UK has obtained the necessary
certificates and is currently participating in the trading scheme. The second commitment period of the trading
scheme commenced on January 1, 2008 and will continue until the end of 2012. Installations in the large
electricity producer sector, including participating plants operated by E.ON UK, have been allocated certificates
according to a set of technology based benchmarks with the level of free allocation varying in relation to the
technology of the plant. In addition, large electricity producers, including E.ON UK, have received a reduced
level of free allocation compared to the first period, requiring a greater proportion of allowances to be bought
from the market to offset actual emissions.
Each of E.ON UK’s fossil-fuelled power stations in the United Kingdom is required to have a Pollution
Prevention and Control (PPC) Authorization, issued by a government agency, which regulates releases into the
environment and seeks to minimize their impact. The current system of authorizations has been expanded via a
new permit system to cover a wider range of matters such as noise, waste minimization and energy conservation,
reflecting extended requirements now applicable to all new installations. Applications were made for the
necessary permits to bring existing power stations into compliance with the newly-expanded Integrated Pollution
Prevention and Control regime during 2006. The permits were all successfully issued during 2007.
Using the flexibility available to it, E.ON UK has responded to the requirements imposed by emission
controls with a combination of actions, notably the increased use of gas-fired CCGT plants, the use of low
sulphur content fuels, the installation of emission abatement equipment and the development of renewable
energy systems.
E.ON UK has operated its own environmental management system since 1991. On January 1, 1999,
E.ON UK achieved corporate certification to ISO 14001, the international standard for environmental
management, for its electricity production, gas operations and associated services. The certificate was updated to
the revised standard ISO 14001:2004 on November 13, 2006 and is valid for a further three years.
E.ON UK is also subject to further environmental regulations affecting its business, including packaging
waste regulations and oil storage regulations. In order to comply with the applicable packaging waste regulations,
E.ON UK has joined an appropriate recycling scheme. The majority of the waste involved is paper.
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Nordic
Air Pollution. The power and heat production plants of E.ON Nordic’s subsidiaries are subject to EU,
international and/or national regulations, and are equipped where necessary with pollution removal devices. The
production plants are subject to emission limits for air pollutants such as SOx, NOx and dust, and relevant
emissions are continuously measured and reported. In Sweden, there are taxes attached to emitting SOx (for coal,
oil and peat) and CO2 (applicable primarily to heat production from coal, oil, natural gas and liquefied petroleum
gas). There is also a fee for emitting NOx (applicable to large combustion plants).
Emissions trading for carbon dioxide started in the EU on January 1, 2005. For details on the Emissions
Trading Directive, as well as information on the Swedish electricity certificate system, see “— Regulatory
Environment.”
The major subsidiaries within E.ON Nordic are operated according to certified environmental management
systems (ISO 14001).
Nuclear Energy. In Sweden, the regulatory framework regarding nuclear power regulations is also governed
by the international agreements discussed in “— Germany: Electricity” above. In addition, Swedish nuclear
power regulations are governed by Swedish law, mainly the Act on Nuclear Activities (SFS 1984:3), the Nuclear
Liability Act (SFS 1968:45) and the Act on Financial Measures for handling of Nuclear Waste from Nuclear
Operations (SFS 2006:647). Under Swedish law, the owner of a nuclear power station is obliged to conduct
operations in such a manner that the required safety standards are maintained and is responsible for nuclear waste
management and decommissioning of nuclear facilities. A license is required in order to own or operate a nuclear
facility, which is granted by the Swedish government on recommendation by the Swedish Nuclear Power
Inspectorate, which supervises all nuclear facilities in Sweden.
According to the Act on Financial Measures for handling of Nuclear Waste from Nuclear Operations
(SFS 2006:647), the owner of a nuclear facility in Sweden is under the obligation to pay an amount determined
by the Swedish government for each kWh produced in the facility to the Swedish Nuclear Waste Fund. The
amounts thus paid, together with any capital gains on the amounts, are to cover the costs for nuclear waste
management and the decommissioning of nuclear facilities. In accordance with Swedish law, E.ON Sverige has
also given guarantees to governmental authorities to cover possible additional costs related to the disposal of
high-level radioactive waste and nuclear power plant decommissioning. See also Note 27 of the Notes to
consolidated financial statements.
The main change in the new Financing Act is that the licensed owner and operator of a nuclear reactor,
when the reactor is closed, can be obligated to pay an additional fee (in addition to the fee per kWh produced
mentioned above) until all the costs of the final disposal of nuclear waste are covered.
For more information about E.ON Nordic’s nuclear power operations, see “— Nordic — Non-Regulated
Business — Power Generation.”
Liability. In Sweden, the owner of a nuclear facility is liable for damages caused by accidents in the nuclear
facility and accidents caused by nuclear substances to and from the facility. As of December 31, 2007, the
liability is limited to an amount equal to SEK 3,063 million (€322 million) per accident, which must be insured
according to the Nuclear Liability Act. E.ON Sverige has the necessary insurance for its nuclear power plants.
In November 2004, the Swedish government began an inquiry on Swedish nuclear liability. In May 2006, a
final report issued by the inquiry proposed unlimited liability for the proprietor of the facility and that proprietors
should be obligated to purchase insurance covering an amount of €700 million per nuclear facility, with an upper
limit on obligations to finance the unlimited liability set at €1.2 billion per nuclear facility. If at any given facility
one reactor fails, it is not possible to run the remaining reactors. The inquiry has also proposed that the Swedish
government — within the model of state guarantees — enter into a reinsurance agreement with the Nordic
Nuclear Insurers as direct insurer to cover any remaining liability. It is still unclear when the inquiry’s report will
lead to a legislative proposal from the government.
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U.S. Midwest
E.ON U.S.’s operations are subject to a number of environmental laws and regulations in each of the
jurisdictions in which it operates, governing, among other things, air emissions, wastewater discharges, the use,
handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee
health and safety.
Clean Air Act Requirements. The Clean Air Act (“CAA”) establishes a comprehensive set of programs
aimed at protecting and improving air quality in the United States by, among other things, controlling stationary
sources of air emissions such as power plants. While the general regulatory framework for these programs is
established at the federal level, most of the programs are implemented and administered by the states under the
oversight of the U.S. EPA. The key CAA programs relevant to E.ON U.S.’s business operations are described
below.
Ambient Air Quality. The CAA requires the EPA to periodically review the available scientific data for six
criteria pollutants and establish concentration levels in the ambient air sufficient to protect the public health and
welfare with an extra margin for safety. These concentration levels are known as national ambient air quality
standards (“NAAQS”). Each state must identify “non-attainment areas” within its boundaries that fail to comply
with the NAAQS and develop a state implementation plan (“SIP”) to bring such non-attainment areas into
compliance. If a state fails to develop an adequate plan, the EPA must develop and implement a plan. As the EPA
increases the stringency of the NAAQS through its periodic reviews, the attainment status of various areas may
change, thereby triggering additional emission reduction obligations under revised SIPs aimed at achieving
attainment.
In 1997, the EPA established new NAAQS for ozone and fine particulates that required additional
reductions in SO2 and NOx emissions from power plants. In 1998, the EPA issued its final “NOx SIP Call” rule
requiring reductions in NOx emissions of approximately 85 percent from 1990 levels in order to mitigate ozone
transport from the midwestern United States to the northeastern United States. To implement the new federal
requirements, in 2002 Kentucky amended its SIP to require electric generating units to reduce their NOx
emissions to 0.15 pounds weight per million British thermal units (“lb./mmBtu”) on a company-wide basis. In
2005, the EPA issued the Clean Air Interstate Rule (“CAIR”), which requires additional SO2 emission reductions
of 70 percent and NOx emission reductions of 65 percent from 2003 levels. The CAIR provides for a two-phase
cap and trade program, with initial reductions of NOx and SO2 emissions due by 2009 and 2010, respectively,
and final reductions due by 2015. The final rule is currently being challenged in a number of federal court
proceedings. In 2006, Kentucky proposed to amend its SIP to adopt state requirements similar to those under the
federal CAIR. Depending on the level of action determined necessary to bring local non-attainment areas into
compliance with the new ozone and fine particulate standards, E.ON U.S.’s power plants are potentially subject
to additional reductions in SO2 and NOx emissions. LG&E’s and KU’s weighted-average company-wide
emission rates for SO2 in 2007 were approximately 0.50 and 1.33 lbs/MMBtu of heat input, respectively, with
every generating unit below its emission limit established by the Kentucky Division for Air Quality and the
Louisville Metro Air Pollution Control District (with respect to LG&E).
Hazardous Air Pollutants. As provided in the 1990 amendments to the CAA, the EPA investigated
hazardous air pollutant emissions from electric utilities and submitted a report to Congress identifying mercury
emissions from coal-fired power plants as warranting further study. In 2005, the EPA issued the Clean Air
Mercury Rule (“CAMR”), establishing mercury standards for new power plants and requiring all states to issue
new SIPs including mercury requirements for existing power plants. The EPA issued a model rule which
provides for a two-phase cap and trade program with initial reductions due by 2010 and final reductions due by
2018. The CAMR provides for reductions of 70 percent from 2003 levels. The EPA closely integrated the CAMR
and CAIR programs to ensure that the 2010 mercury reduction targets will be achieved as a “co-benefit” of the
controls installed for purposes of compliance with the CAIR. The CAMR is also currently under challenge in the
federal courts. In February 2008, in one proceeding, a federal appellate court has issued a decision vacating the
current CAMR, an outcome which may have the effect of resulting in more stringent mercury reduction rules, but
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which ruling could be subject to further appeal. In 2006, Kentucky proposed to amend its SIP to adopt state
requirements similar to those under the federal CAMR. In addition, in 2006 and 2007 state and local air agencies
in Kentucky have proposed or adopted rules aimed at regulating additional hazardous air pollutants from sources
including power plants. To the extent those rules are final, they are not expected to have a material impact on
E.ON U.S.’s power plant operations.
Acid Rain Program. The 1990 amendments to the CAA imposed a two-phase cap and trade program to
reduce SO2 emissions from power plants that were thought to contribute to “acid rain” conditions in the
northeastern United States. The 1990 amendments also contained requirements for power plants to reduce NOx
emissions through the use of available combustion controls.
Regional Haze. The CAA also includes visibility goals for certain federally designated areas, including
national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing
future impairment and remedying any existing impairment of visibility in those areas. In 2005, the EPA issued its
Clean Air Visibility Rule (“CAVR”), detailing how the CAA’s best available retrofit technology (“BART”)
requirements will be applied to facilities, including power plants, built between 1962 and 1974 that emit certain
levels of visibility impairing pollutants. Under the final rule, since the CAIR will result in more visibility
improvement than BART, states are allowed to substitute the CAIR requirements in their regional haze SIPs in
lieu of controls that would otherwise be required by BART. The CAVR is also currently being challenged in the
federal courts.
Installation of Pollution Controls. Many of the programs under the CAA utilize cap and trade mechanisms
that require a company to hold sufficient emissions allowances to cover its authorized emissions on a companywide basis and do not require installation of pollution controls on every generating unit. Under cap and trade
programs, companies are free to focus their pollution control efforts on plants where such controls are
particularly efficient and utilize the resulting emission allowances for smaller plants where such controls are not
cost effective. LG&E had previously installed flue gas desulphurization equipment on all of its generating units
prior to the effective date of the acid rain program, while KU met its acid rain Phase I SO2 requirements
primarily through installation of flue gas desulphurization equipment on Ghent Unit 1. E.ON U.S.’s combined
strategy for its acid rain Phase II SO2 requirements, which commenced in 2000, uses accumulated emissions
allowances to defer additional capital expenditures and also includes fuel switching or the installation of
additional flue gas desulphurization equipment. In order to achieve the NOx emission reductions and associated
obligations, E.ON U.S. installed additional NOx controls, including selective catalytic reduction technology,
during the 2000 to 2007 time period. In 2001, the KPSC granted approval to recover the costs incurred by LG&E
and KU for these projects through the environmental cost recovery surcharge mechanism. Such monthly recovery
is subject to periodic review by the KPSC.
In order to achieve the emissions reductions mandated by the CAIR and CAMR, E.ON U.S. expects to incur
additional capital expenditures totaling approximately $850 million, during the 2008 through 2010 time period,
for pollution controls including flue gas desulphurization and selective catalytic reduction, and to incur additional
operating and maintenance costs in operating such controls. In 2005, the KPSC granted recovery in principal of
these costs incurred by LG&E and KU, with approval of specific expenditures to occur via its periodic
environmental surcharge rate review mechanisms. E.ON U.S. believes its costs in reducing SO2, NOx and
mercury emissions to be comparable to those of similarly situated utilities with like generation assets.
E.ON U.S.’s compliance plans are subject to many factors including developments in the emissions allowance
and fuels markets, future legislative and regulatory enactments, legal proceedings and advances in clean air
technology. E.ON U.S. will continue to monitor these developments to ensure that its environmental obligations
are met in the most efficient and cost-effective manner.
Potential Greenhouse Gas Controls. In 2005, the Kyoto Protocol to the United Nations Framework
Convention on Climate Change (“Kyoto Protocol”) for reducing greenhouse gas emissions took effect, obligating
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37 industrialized countries to undertake substantial reductions in greenhouse gas emissions. For details, see “Risk
Factors — External Risks.” The U.S. has not ratified the Kyoto Protocol and there are currently no mandatory
greenhouse gas emissions reduction requirements at the federal level. Legislation mandating greenhouse gas
reductions has been introduced in the Congress, but no federal legislation has been enacted to date. In the
absence of a program at the federal level, various states have adopted their own greenhouse gas emissions
reduction programs, including approximately 12 northeastern states under the Regional Greenhouse Gas
Initiative program as well as California. Substantial efforts to pass federal greenhouse gas legislation are
ongoing. In addition, litigation is currently pending before various courts to determine whether the EPA and the
states have the authority to regulate greenhouse gas emissions under existing law. In one such proceeding, in
April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions
under the CAA. E.ON U.S. is monitoring ongoing efforts to enact greenhouse gas reduction requirements at the
state and federal level and is assessing potential impacts of such programs and strategies to mitigate those
impacts. E.ON U.S. is unable to predict whether mandatory greenhouse gas reduction requirements will
ultimately be enacted or to determine the reduction targets and deadlines that would be applicable under such
programs. As a company with significant coal-fired generating assets, E.ON U.S. could be substantially impacted
by programs requiring mandatory reductions in greenhouse gas emissions, although the precise impact on the
operations of E.ON U.S. cannot be determined prior to the enactment of such programs.
Brown New Source Review Litigation. During 2006, the EPA issued notices alleging that KU had violated
certain provisions of the CAA’s new source review rules relating to work performed in 1997 on a unit at KU’s
E.W. Brown generating station and that such unit exceeded heat input values in violation of its air permit. In
March 2007, the Department of Justice filed a complaint in federal court in Kentucky alleging the same
violations specified in the EPA’s prior notices of violations. The complaint seeks civil penalties, including
potential per-day fines, remedial measures and injunctive relief. In April 2007, KU filed an answer in the civil
suit denying the allegations. In July 2007, a July 2009 date for trial on the merits was scheduled. The parties
continue periodic settlement discussions and a $2 million accrual has been recorded based on the current status of
those discussions, however, KU cannot determine the overall outcome or potential effects of these matters,
including whether substantial fines, penalties or required remedial construction may result.
General Environmental Proceedings. From time to time, E.ON U.S. appears before the EPA, various state
or local regulatory agencies, and state and federal courts regarding matters involving compliance with applicable
environmental laws and regulations. Such matters include a notice of violation for alleged noncompliance with
the opacity provisions of the CAA at KU’s Ghent station; administrative requests for information issued by the
EPA under Section 114 of the CAA requesting new source review data regarding certain construction and
maintenance activities at units of LG&E’s Mill Creek and Trimble County and KU’s Ghent generating stations;
remediation obligations for former manufactured gas plant sites; liability under the Comprehensive
Environmental Response, Compensation and Liability Act for cleanup at various off-site waste sites; ongoing
claims regarding alleged particulate emissions from LG&E’s Cane Run station; and ongoing claims regarding
greenhouse gas emissions from E.ON U.S. generating stations. Based on analysis to date, the resolution of such
matters is not expected to have a material impact on the operations of E.ON U.S.
Property, Plants And Equipment
General
The Company owns most of its production facilities and other properties. Some of E.ON’s facilities are
subject to mortgages and other security interests granted to secure indebtedness to certain financial institutions.
As of December 31, 2007, the total amount of indebtedness collateralized by these facilities was approximately
€1.4 billion. E.ON believes that the Group’s principal production facilities and other significant properties are in
good condition and that they are adequate to meet the needs of the E.ON Group. E.ON’s headquarters are located
at E.ON-Platz 1, D-40479 Düsseldorf, Germany. E.ON owns its headquarters.
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Production Facilities
Central Europe
E.ON Energie produces electricity at jointly and wholly-owned power plants. Its power generation facilities
have a total installed capacity of approximately 37,200 MW, E.ON Energie’s attributable share of which is
approximately 28,500 MW (not including mothballed, shutdown and reduced power plants). Electricity is
transmitted to purchasers by means of high-voltage transmission lines and underground cables owned by E.ON
Energie. For further details, see “— Central Europe.” E.ON Energie believes that its power plants are in good
operating condition and that its machinery and equipment have been well maintained. E.ON Energie’s German
base load nuclear power plants operated at approximately 86 percent of available capacity in 2007. E.ON Energie
believes that average utilization data calculated on the basis of all of its international and German power stations
would not reflect differences between base load and peak load requirements or differential costs of generation
and would therefore dilute the significance of such a measure.
Pan-European Gas
E.ON Ruhrgas AG owns, co-owns or has interests through project companies in gas pipelines in Germany
totaling 11,611 km. In addition, E.ON Ruhrgas AG owns, co-owns or has interests through project companies in
34 compressor stations in Germany. The current installed capacity of these compressor stations totals 993 MW.
E.ON Ruhrgas AG also owns, co-owns, leases or has interests through project companies in 11 underground gas
storage facilities in Germany; E.ON Ruhrgas AG’s share in the usable working gas storage capacity of these
facilities is approximately 5.3 billion m3. Due to the number and complexity of factors influencing gas pipeline
and storage utilization, E.ON Ruhrgas AG does not consider data on the utilization of the transmission system
and gas storage capacity to be meaningful. E.ON Ruhrgas AG also owns interests in six project companies
operating and developing gas transmission systems outside of Germany. For further details, see
“— Pan-European Gas — Transmission and Storage.”
E.ON Ruhrgas AG believes that its transmission system (including transport compressor stations) and gas
storage facilities (including storage compressor stations) are in good operating condition and that its machinery
and equipment have been well maintained.
U.K.
E.ON UK produces electricity at jointly and wholly-owned power plants. Its power generation facilities
have a total installed capacity of approximately 10,793 MW, E.ON UK’s attributable share of which is
approximately 10,581 MW. Electricity is transmitted to purchasers by means of the National Grid transmission
network in the United Kingdom. For further details, see “— U.K.” E.ON UK believes that its power plants are in
good operating condition and that its machinery and equipment have been well maintained. In 2007, E.ON UK’s
power plants operated at approximately 44 percent of theoretical capacity. This average utilization is calculated
for all U.K. power stations and does not reflect differences between base load and peak load power stations.
Nordic
E.ON Nordic produces electricity at jointly and wholly-owned power plants. Its power generation facilities
have a total installed capacity of approximately 18,300 MW, its attributable share of which is approximately
7,400 MW (not including mothballed and shutdown power plants). In Sweden and Finland, electricity is
transmitted to purchasers via 200-400 kV electricity grids, which are operated by state-owned companies, and
through regional and local distribution networks. E.ON Nordic owns and operates regional and local electricity
distribution networks in Sweden and Finland through E.ON Sverige. Through E.ON Sverige, E.ON Nordic also
owns one-third of the Baltic Cable, an undersea electricity cable linking the Swedish electricity grid to the grid of
E.ON Energie in Germany. In Sweden, E.ON Nordic also owns and operates high-and low-pressure gas pipelines
through E.ON Sverige. For more information, see “— Nordic.” E.ON Nordic believes that its power plants,
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electricity distribution networks and gas pipelines are in good operating condition and that its machinery and
equipment have been well maintained. The Swedish base load nuclear power plants in which E.ON Nordic holds
an interest operated at approximately 79 percent of available capacity in 2007. E.ON Nordic believes that
average utilization data calculated on the basis of all of its power stations would not reflect differences between
base load and peak load requirements or differential costs of generation and would therefore dilute the
significance of such a measure.
U.S. Midwest
E.ON U.S. produces electricity at jointly and wholly-owned power plants. Its power generation facilities
have a total installed capacity of approximately 7,600 MW, E.ON U.S.’s attributable share of which is
approximately 7,500 MW (not including mothballed and shutdown power plants). Electricity is transmitted to
purchasers by means of E.ON U.S.’s transmission network (for which certain functional control is provided by
third parties pursuant to FERC regulation) in the United States. For further details, see “— U.S. Midwest.” E.ON
U.S. believes that its power plants and transmission networks are in good operating condition and that its
machinery and equipment have been well maintained. In 2007, E.ON U.S.’s power plants operated at
approximately 55 percent of theoretical capacity. This average utilization is calculated for all U.S. power stations
and does not reflect differences between base load and peak load power stations.
Employees
As of December 31, 2007, E.ON had 87,815 employees. This increase of 8.9 percent from year-end 2006 is
mainly due to the inclusion of the staff from the newly acquired Russian company OGK-4 at the Corporate
Center segment. Of the total number of employees, 39.4 percent were based in Germany. The following table sets
forth information about the number of employees of E.ON as of December 31, 2007, 2006 and 2005, not
including apprentices and managing directors or board members:
Employees at
December 31, 2007
Total
Germany Foreign
Employees at
December 31, 2006
Total
Germany Foreign
Employees at
December 31, 2005
Total
Germany Foreign
Central Europe . . . . . . . . . . . . . 44,051 30,598 13,453 43,546 30,199 13,347 44,476 30,307 14,169
Pan-European Gas . . . . . . . . . . . 12,214 3,446 8,768 12,417 3,371 9,046 13,366 3,411 9,955
U.K . . . . . . . . . . . . . . . . . . . . . . 16,786
23 16,763 15,621
13 15,608 12,891
10 12,881
Nordic . . . . . . . . . . . . . . . . . . . . 5,804
5 5,799 5,693
3 5,690 5,424
2 5,422
U.S. Midwest . . . . . . . . . . . . . . . 2,977
3 2,974 2,890
2 2,888 3,002
2 3,000
Corporate Center . . . . . . . . . . . . 5,983
540 5,443
445
426
19
411
395
16
Total . . . . . . . . . . . . . . . . . . . . . 87,815 34,615 53,200 80,612 34,014 46,598 79,570 34,127 45,443
In addition, E.ON employed 2,656, 2,574 and 2,471 apprentices with limited contracts in Germany at
year-end 2007, 2006 and 2005, respectively.
Personnel expenses totaled €4.6 billion in 2007, compared with €4.5 billion in 2006.
Many of the Group’s employees are members of labor unions. Almost all of the union members in Germany
belong to the national chemicals/mining/energy and the united services unions. None of E.ON’s facilities in
Germany is operated on a “closed shop” basis. In Germany, employment agreements for blue collar workers and
for white collar employees below management level are generally collectively negotiated between the association
of the companies within a particular industry and the respective unions. In addition, under German law, works
councils comprised of both blue collar and white collar employees participate in determining company policy
with regard to certain compensation matters, work hours and hiring policy. Management believes its relations
with the German trade unions may be characterized as constructive and cooperative.
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E.ON U.K.’s organizational structure comprises a number of businesses which are supported by a common
services business and central functional teams, including finance, legal and human resources. E.ON U.K. has in
place a framework, at company and business level, for consultation and collective bargaining with its recognized
trade unions. At company level, the E.ON UK Consultative Forum considers matters of common interest across
all business units (e.g. E.ON UK performance, business plans, etc.) and consults about UK wide employment
policies. At the individual business level, detailed negotiation of pay and other business-specific terms and
conditions is negotiated by business level employee forums. These forums consist of representatives from
management, trade unions and employees and fulfill a consultative, as well as a negotiating role. Since
privatization, E.ON U.K. believes it has maintained constructive relationships with its recognized unions.
In Sweden, approximately 80 percent of E.ON Sverige’s employees are members of various trade unions.
E.ON Sverige adheres to two main central collective labor agreements at the national level, on the basis of which
E.ON Sverige’s corporate human resources department and representatives from the different trade unions have
negotiated a framework for E.ON Sverige. Local human resources departments and local trade union
representatives negotiate at the local level. Pursuant to Swedish law, representatives of the unions are members
of E.ON Sverige’s board of directors. According to Swedish law, all issues that have an impact on the
employees’ working conditions must be negotiated with the trade unions. Management believes its relations with
the Swedish trade unions may be characterized as constructive and cooperative.
The level of trade union participation is very high in the eastern European countries in which the Company
has operations. Almost all of the Company’s employees in Romania, Hungary, Bulgaria and the Czech Republic
are members of the trade unions in the energy and gas sector or at least participate in the collective bargaining
agreements that are used in the energy and gas industries. These collective bargaining agreements, which are
negotiated between the association of the companies within a particular industry or the individual employer and
the respective unions, stipulate compensation levels and most other working conditions for employees.
Management believes that its relations with the relevant trade unions may be characterized as constructive and
cooperative, and that the continuation of a constructive and cooperative relationship is of great importance for the
successful integration of the Company’s recently-acquired operations in Eastern Europe.
The employees of E.ON U.S. who are members of labor unions belong to local units of the International
Brotherhood of Electrical Workers (“IBEW”) and The United Steelworkers of America. Most of these union
employees are involved in operational and maintenance work in power generation and distribution operations.
The majority of E.ON U.S.’s employees are not union members. In the United States, Collective Bargaining
Agreements (“CBA”) are negotiated between the local management (i.e., LG&E and KU) and local union
representatives. Each CBA generally has a term of three to four years and includes no strike or lock out clauses
during the term of the agreement. While E.ON U.S. had an adversarial relationship in the past with the IBEW, its
primary union, management believes relations have significantly improved and may now be characterized as
cooperative.
Pursuant to EU requirements, E.ON also established a European works council in 1996 that is responsible
for cross-border issues. The Company believes that it has satisfactory relations with its works councils and
unions and therefore anticipates reaching new agreements with its labor unions on satisfactory terms as the
existing agreements expire. There can be no assurance, however, that new agreements will be reached without a
work stoppage or strike or on terms satisfactory to the Company. A prolonged work stoppage or strike at any of
its major facilities could have a material adverse effect on the Company’s results of operations. The Group has
not experienced any material strikes during the last ten years.
Legal Proceedings
A number of different court actions (including product liability lawsuits), governmental investigations and
proceedings, and other claims are currently pending or may be instituted or asserted in the future against
companies of the E.ON Group. This in particular includes legal actions and proceedings concerning alleged
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price-fixing agreements and anti-competitive practices. In addition, there are lawsuits pending against E.ON AG
and U.S. subsidiaries in connection with the disposal of VEBA Electronics in 2000. E.ON Ruhrgas is a party to a
number of different arbitration proceedings in connection with the acquisition of Europgas a.s. and in connection
with gas delivery contracts entered into with Norsk Hydro Produksjon AS, Gasversorgung Süddeutschland
GmbH and Gas Terra B.V. Since litigation or claims are subject to numerous uncertainties, their outcome cannot
be ascertained; however, in the opinion of management, any potential obligations arising from these matters will
not have a material adverse effect on the financial condition, results of operations or cash flows of the Company.
For information about the conditions and obligations imposed on E.ON in connection with the ministerial
approval for E.ON’s acquisition of E.ON Ruhrgas, see “Business — History and Development of the Company.”
For information about proceedings instituted by German or European antitrust authorities affecting E.ON
Ruhrgas, E.ON Energie and certain of their subsidiaries, see “Risk Factors.”
E.ON maintains general liability insurance covering claims on a worldwide basis with coverage limits and
retention amounts which management believes to be adequate and appropriate in light of E.ON’s businesses and
the risks to which they are subject. For a discussion of E.ON Energie’s and E.ON Sverige’s nuclear accident
protection, see “— Environmental Matters.”
REGULATORY ENVIRONMENT
EU/Germany: General Aspects (Electricity and Gas)
Overview
In order to promote competition in the EU energy market, the EU adopted electricity and gas directives
(Directive 96/92/EC Concerning Common Rules for the Internal Market in Electricity, or the “First Electricity
Directive” and Directive 98/30/EC Concerning Common Rules for the Internal Market in Natural Gas, or the
“First Gas Directive”) in 1996 and 1998, respectively.
The First Electricity Directive was intended to open access to the internal electricity markets of EU member
states. Germany implemented the First Electricity Directive by enacting an Energy Law
(Energiewirtschaftsgesetz, or the “Energy Law”) that entered into force on April 29, 1998.
The First Gas Directive was intended to open access to the internal gas markets of EU member states. The
Energy Law already included elements of the First Gas Directive, while an amendment to the Energy Law, which
came into effect on May 24, 2003, completed the implementation of the First Gas Directive in German law.
In June 2003, the EU Energy Council amended the First Electricity Directive and replaced it with a new
electricity directive (Directive 2003/54/EC Concerning Common Rules for the Internal Market in Electricity, or
the “Second Electricity Directive”) and also adopted a second gas directive (Directive 2003/55/EC Concerning
Common Rules for the Internal Market in Natural Gas and Repealing Directive 98/30/EC, or the “Second Gas
Directive”), which replaced the First Gas Directive. Germany implemented these directives by enacting the new
Energy Law of 2005 (Zweites Gesetz zur Neuregelung des Energiewirtschaftsrechts, or the “Energy Law of
2005”), which came into force on July 13, 2005. Corresponding network access and network charges ordinances
for electricity and gas came into force on July 29, 2005.
The following paragraphs outline relevant aspects of the Energy Law, the Second Electricity and Gas
Directives, and amendments to the Energy Law, as well as other EU proposed and adopted directives and
regulations that affect the German energy industry.
E.ON’s operations outside of Germany are subject to the different national and local regulations in the
relevant countries.
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The German Energy Law of 1998
Germany’s Energy Law of 1998 implemented the First Electricity Directive. The Energy Law abolished
exclusive supply contracts, thereby introducing competition in the supply of electricity to all consumers and
provided (in addition to the so-called “single-buyer” system) for non-discriminatory negotiated third party access
to electricity networks (“nTPA”) for all utilities. The German market was opened for all customers in one step,
going far beyond the requirements of the First Electricity Directive and also beyond the steps taken by
Germany’s neighboring countries. Specifically, in assessing a request for energy transmission, the Energy Law
required a transmission company to take into account the extent to which such transmission displaced electricity
generated from CHP plants, renewable energy sources and, in eastern Germany, lignite-based power plants and
the extent to which it impedes the commercial operation of such power plants. Furthermore, the Energy Law
introduced a provision for third party access into the Law Against Restraints of Competition (Gesetz gegen
Wettbewerbsbeschränkungen, or “GWB”). In 1998, the first electricity association agreement provided the main
basis for an nTPA network access system for electricity in Germany. See “— Germany: Electricity — Electricity
Network Access” below.
The Energy Law of 1998 also included — prior to the adoption of the First Gas Directive — certain parts of
the First Gas Directive. The Energy Law of 1998 enhanced competition in gas supply to consumers and provided
for non-discriminatory nTPA for all utilities. The German gas market was opened for all customers in one step in
the year 1998, in this respect going far beyond the requirements of the First Gas Directive and also beyond the
steps taken by Germany’s neighboring countries. In 2000, the first gas association agreement provided the main
basis for an nTPA network access system for gas in Germany. Technical access rules for household and small
commercial customers were introduced in September 2002.
The Second Electricity and Gas Directives
Completion of the Internal Electricity Market/The Second Electricity Directive. On June 26, 2003, the EU
Energy Council adopted the Second Electricity Directive, which replaced the First Electricity Directive. The
Second Electricity Directive required full market opening to competition in each member state by July 1, 2004
for commercial customers and by July 1, 2007 for household customers. The Directive also sets forth general
rules for the organization of the EU electricity market, such as the option of the member states to impose certain
public service obligations, customer protection measures and provisions for monitoring the security of the EU’s
electricity supply. The previous framework of negotiated third party access in Germany is no longer allowed
under the Second Electricity Directive. Instead, the Directive requires, at a minimum, that a methodology for
calculating network charges be fixed by law or approved by an independent regulatory body, the establishment of
which the Second Electricity Directive requires. In addition, the Second Electricity Directive contains provisions
requiring the organizational and legal unbundling of transmission and distribution system operators, as well as
mandatory electricity labeling for fuel mix, emissions and waste data.
The following paragraphs provide more detail on the independent regulatory authority, legal unbundling,
electricity labeling and certain of the public service requirements.
The Second Electricity Directive (as well as the Second Gas Directive, see below) requires the
establishment of a regulatory body that is independent of the interests of the electricity and gas industries.
According to the Directive, the independent regulator shall be responsible for ensuring non-discriminatory
network access, monitoring effective competition and ensuring the efficient functioning of the market. Further,
the regulator shall be responsible for fixing or approving the terms and conditions for connection and access to
national transmission and distribution networks (or at least the methodologies to calculate such terms), including
transmission and distribution charges, and for the provision of balancing services, and shall also have the
authority to require transmission and distribution system operators, if necessary, to modify their terms and
conditions in order to ensure that they are proportionate and applied in a non-discriminatory manner.
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In addition, the Second Electricity Directive requires that each transmission and distribution system operator
be independent, at least in terms of legal form, organization and decision-making, from other activities not
relating to transmission or distribution (“legal unbundling”). This requirement does not imply or result in the
requirement to separate the ownership of assets of the transmission network from the vertically integrated
undertaking. The Second Electricity Directive enabled member states to postpone the implementation of
provisions for legal unbundling of distribution system operations until July 1, 2007 at the latest. Derogations
from legal unbundling may also be granted to distribution companies serving less than 100,000 connected
customers or small isolated networks. Member states can request an exemption from legal unbundling if they can
prove that total and non-discriminatory access to the distribution networks can be achieved by other means.
The Second Electricity Directive requires electricity suppliers to specify in or with bills, as well as in
promotional materials for end-user customers, the following information:
•
The contribution of each energy source to the overall fuel mix of the supplier over the preceding year;
and
•
A reference to where information is publicly available on the environmental impact of the supplier’s
activities, including the amount of CO2 and radioactive waste produced.
Finally, the Second Electricity Directive requires that household customers and — where member states
deem it appropriate — small companies must be provided with “universal service,” i.e., the right to be supplied
with electricity of a specified quality at reasonable prices.
Completion of the Internal Gas Market/The Second Gas Directive. On June 26, 2003, the EU also adopted
the Second Gas Directive, which replaced the First Gas Directive. Similar to the Second Electricity Directive, the
Second Gas Directive required full opening of each member state’s gas market to competition by July 1, 2004 for
all non-household customers and by July 1, 2007 for all customers. The Directive also sets forth similar general
rules for the organization of the EU gas market. The previous framework of negotiated third party gas network
access in Germany is no longer allowed under the Second Gas Directive. Instead, as in the Second Electricity
Directive, the Second Gas Directive requires regulated third party access and at least a methodology for
calculating network charges to be fixed by law or approved by an independent regulatory authority, the
establishment of which, the Second Electricity Directive requires. The Directive also requires integrated gas
companies to legally unbundle their transmission and distribution system operators from other operations.
The Second Electricity and Gas Directives were required to be implemented by each member state by
July 1, 2004.
Revisions of the German Energy Law
Prior to the adoption of the Second Gas Directive, the German government amended the Energy Law in
May 2003. The amended Energy Law (Erstes Gesetz zur Änderung des Gesetzes zur Neuregelung des
Energiewirtschaftsrechts) fully completed the implementation of the First Gas Directive into national law. Apart
from provisions to facilitate the opening of the gas market, a new section determined the legal basis for
non-discriminatory access to gas networks. In addition, the amended Energy Law formally recognized the
relevant electricity and gas association agreements (Verbändevereinbarung Strom II+ and
Verbändevereinbarung Gas II) as good commercial practice until December 31, 2003. Furthermore, this
amendment modified the provisions of the GWB concerning the suspensive effect of appeals made against
decisions of the Federal Cartel Office, so that decisions issued pursuant to the third party access provision of the
GWB become immediately applicable.
In order to implement the Second Electricity and Gas Directives, the German legislature passed the Energy
Law of 2005 (Zweites Gesetz zur Neuregelung des Energiewirtschaftsrechts), which came into force on July 13,
2005. Corresponding network access and network charge ordinances for electricity and gas came into force on
July 29, 2005.
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Under this new legal framework, the German legislature has authorized the Federal Network Agency
(Bundesnetzagentur, or the “BNetzA,” previously called the Regulatory Authority of Telecommunications and
Post) to act as the independent regulatory body required by the Second Electricity and Gas Directives, initially
with ex-ante supervisory powers. The BNetzA is responsible for fixing or approving or controlling the terms and
conditions for connection and access to national transmission and distribution networks, including transmission
and distribution charges. The BNetzA (and the state-level regulators) also have the authority to require
transmission and distribution system operators, if necessary, to modify their conduct in order to ensure that they
act in a non-discriminatory manner.
The following paragraphs provide more detail on the most significant elements of the Energy Law of 2005
for German utilities:
Network access and network charge regulation: The Energy Law of 2005 provides for two phases of
regulation. In the starting phase of regulation, the BNetzA and the state-level regulators have to approve the
network charges which are calculated by the utilities using a cost-based rate-of-return model if an exemption
from cost calculations is not granted for gas transmission networks in case of actual or potential pipeline
competitions. If the cost-based rate-of-return-model is applied, the BNetzA and the state-level regulators
effectively set the network charges for network operators ex-ante. The allowed capital costs for existing
investments are derived from a regulated asset base that is partly valued at current cost. For new investments, the
allowed capital costs are derived from a regulated asset base valued at historic cost. See also “— Germany:
Electricity — Electricity Network Charges” and “— Germany: Gas — Gas Network Charges” below. A second
phase of regulation envisages a new incentive-based regulation system which will replace the current cost-based
rate-of-return model. The original BNetzA proposal to the Ministry of Economics in the summer of 2006 was
followed by intense political discussion. Due to delay in the legislative process, which only was overcome in
November 2007, a second cost-based ex-ante approval scheme of network charges is being used for 2008; the
allowed network charges for 2008 will be the starting point for the incentive regulation system in 2009. Under
the incentive regulation system, within 10 years, network operators will be expected to lower costs to the level of
the most efficient network operators. In addition to individual efficiency (or x-) factors, every electricity network
operator will be expected to accomplish a general efficiency gain of 1.25 percent in the first five-year period
(four years for gas) and 1.5 percent in the second such period. The individual x-factors are based upon different
benchmarkings reflecting network operators’ varying supply situations. Major investments are to be supported by
investment budgets, smaller investments to be covered by a flat-rate investment premium of up to 1 percent of
annual capital costs. Since major parameters are still to be determined by BNetzA, at this time, E.ON is unable to
predict its effects on the Company and on the German energy industry generally.
The Energy Law of 2005 contains an exemption from cost calculations for gas transmission networks if
actual or potential pipeline competition can be proven. The law also provides for the development of a special
entry/exit system for gas network access, whereby network operators have to offer entry and exit capacities for
the transmission of gas separately to system users in order to ensure that system users only need one contract for
entry capacities and one contract for exit capacities. The gas network operators together with the Association of
the German Gas Industry (Bundesverband der deutschen Gas- und Wasserwirtschaft or “BGW”) developed an
entry/exit model in 2006, offering two variants for gas transportation. Following proceedings instituted by a gas
trader and a German energy association, however, the BNetzA determined in a November 2006 decision that one
of the variants for gas transportation does not comply with the Energy Law of 2005 and required that the gas
network operators change their contracts to comply by October 1, 2007. For more information, see “— Germany:
Gas — Gas Network Access” below.
Unbundling of network operators: The Energy Law of 2005 requires legal as well as operational
(organizational), information and accounting unbundling of each transmission and distribution system operator
from the other activities of the utilities. Network operators serving less than 100,000 connected customers are
exempt from the legal and operational unbundling obligations.
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The Company’s German transmission and distribution system operations comply with the legal, operational
(organizational), informational and accounting unbundling requirements contained in the Energy Law of 2005.
New Ordinances. The exact interpretation of some of the new regulatory rules is still unclear. Therefore, the
Company cannot predict all consequences of the new legal framework for its operations or the overall effect of
the new law on its future earnings and financial condition. However, the BNetzA has already interpreted some of
the new regulatory rules and ordinances to reach a conclusion that is different than that reached by, and in some
cases less favorable to, the Company as well as other German network operators. For more information, see
“— Germany: Electricity — Electricity Network Charges” and “— Germany: Gas” below. In 2006, the
following ordinance came into effect under the Energy Law of 2005:
Network Connection Ordinance: In November 2006, the network connection ordinance came into force.
This ordinance increases potential liability for network operators for damages caused by energy supply
disturbances by lowering the negligence threshold required for customers to collect damages. Under the
ordinance, simple rather than gross negligence is the required threshold, while damages are capped at a
maximum of €5,000 per customer.
In addition, the following ordinance came into effect in 2007:
Power Station Grid Connection Ordinance: In June 2007, the German Ministry of Economics issued a
power station grid connection ordinance in the same package with its incentive regulation ordinance. The power
station ordinance addresses regulatory aspects of power station connection to the electricity grid, and gives
certain preferential treatment to the grid connection of new power stations with respect to capacity bottlenecks.
For the ordinance which has replaced the Federal Electricity Charge Regulation (Bundestarifordnung
Elektrizität, or “BTOElt”), see “— Germany: Electricity — Electricity Rate Regulation” below.
Further German Legislation
Law on the Acceleration of Planning Procedures for Infrastructure. The Law on the Acceleration of
Planning Procedures for Infrastructure (Infrastrukturplanungsbeschleunigungsgesetz) came into force in
December 2006. Pursuant to this law the costs for the connection of offshore wind power plants will not be paid
by the plant operator, but will be borne by all grid users via an apportionment of indirect costs. The additional
costs through 2020 are initially distributed among all four transmission system operators in Germany (including
E.ON) and will lead to increased grid fees for all grid users.
Energy Tax Act. On August 1, 2006, the Energy Tax Act (Energiesteuergesetz) came into force. The Energy
Tax Act, which is based on and incorporates the old Oil Taxation Law (Mineralölsteuergesetz), is the national
implementation of the EU energy taxation directive from October 27, 2003 that requires certain minimal tax rates
for different forms of energy. Furthermore, the former taxation of gas as an input in electricity generation has
been abolished in order to comply with the EU directive, which stipulates that there be no taxation for inputs for
electricity production. Since all proposed tax rates in the EU directive are below the actual German tax rates that
apply to E.ON, there is currently no risk for the Company of a higher tax burden.
Revisions of the German Competition Law. In Germany, an amendment to the GWB was approved by both
houses of parliament in November and December 2007, respectively, was published on December 21, 2007 in the
Official Law Bulletin (Bundesgesetzblatt) and entered into force on December 22, 2007. The law extends the
competences of the FCO and tightens the rules concerning the abuse of a dominant position. The amendment,
which will expire in 2012, stipulates that entities holding a dominant position in an energy market shall not
charge or impose prices or other commercial conditions that are less favorable than those of other entities in
comparable markets or charge prices that disproportionately exceed their costs. Moreover, the amendment
stipulates a shift in the burden of proof to the affected energy companies in antitrust administrative proceedings
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(but not in civil/private proceedings). We believe that these provisions, if enforced by the FCO or privately,
would significantly reduce competition in Germany’s energy markets. The FCO has established, as of January 1,
2008, a new unit dealing with the implementation of this new section of the GWB. Presumably, the FCO will
open inquiries about the gas and electricity pricing systems during the course of 2008. Currently we are unable to
give any indication about the outcome of possible inquiries or any effects that they could have on us.
European Regulation on Cross-Border Trading
The Second Electricity Directive was accompanied by a new EU regulation on cross-border electricity
trading (Regulation (EC) No. 1228/2003 on Conditions for Access to the Network for Cross-Border Exchanges in
Electricity, or the “Regulation on Cross-Border Electricity Trading”). This regulation required the establishment
of a committee of national experts chaired by the European Commission. The committee will adopt guidelines on
inter-transmission system operator compensation (“ITC Guidelines”) for electricity transit flows, on the
harmonization of national transmission charges and on network congestion management. The applicable
guidelines have already been drafted; the congestion management guidelines entered into force at the beginning
of December 2006. The ITC Guidelines are expected to enter into force sometime in 2008.
At the EU level, a provisional charge system for cross-border electricity trading came into effect in March
2002. The system provides a fund mechanism to cover costs resulting from cross-border trades. Until 2003,
money for the fund was raised from two sources: a charge on exports and socialized costs charged to all
electricity customers. As of January 1, 2004, a modified cross-border charge system has taken effect. Instead of
charging export fees for international electricity flows, transmission system operators must now pay into a fund
according to their net physical import and export flows. As before, the distribution of the funds depends on
transit volume, so, as a large transit country, Germany continues to be a net receiver of funds. The transitional
system will be continued until the end of 2009, with the relevant contracts already being signed. It is expected
that the succeeding system will be based on the above mentioned ITC Guidelines.
Energy Infrastructure and Security of Supply
In December 2003, the European Commission proposed a legislative package on energy infrastructure and
security of supply. In January 2006, the EU adopted Directive 2005/89/EC Concerning Measures to Safeguard
Security of Electricity Supply and Infrastructure Investment (the “Security of Supply Directive”), which requires
EU member states to ensure a high level of security of electricity supply by taking necessary measures to
facilitate a stable investment climate. The Security of Supply Directive stipulates that transmission system
operators set minimum operational rules and obligations for network security, which then may require approval
by the relevant authority. Member states must also prepare, in close cooperation with the transmission system
operators, a system adequacy report according to EU reporting requirements. Member states were required to
transpose the Security of Supply Directive into national law by February 24, 2008. The German Ministry of
Economics did not make any amendments as a result, since fundamental rules concerning security of electricity
supply are laid down in the German Energy Law of 2005 (operation of energy supply networks, system
responsibilities).
In addition, in November 2005 the EU adopted a regulation on conditions for access to gas transmission
networks, which covers access to all gas transmission networks in the EU and addresses a number of issues such
as access charges (which must reflect the actual costs incurred), third party access services, capacity allocation
mechanisms, congestion management, transparency requirements, balancing and imbalance charges, secondary
markets (introducing a “use-it-or-lose-it” principle), and information and confidentiality provisions. The
regulation also requires the establishment of a committee of national experts chaired by the European
Commission, which has the authority to revise the rules annexed to the regulation. The regulation came into
effect on July 1, 2006, except for provisions concerning amendment of the rules in the regulation annex, which
came into effect on January 1, 2007. The regulation directly affects E.ON Gastransport, which has to comply
with these binding rules in its function as a transmission system operator.
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Security of Energy Supply (Gas)
On April 26, 2004, the EU adopted a directive establishing measures to safeguard the security of the EU’s
gas supply (Directive 2004/67/EC Concerning Measures to Safeguard Security of Natural Gas Supply, or the
“Gas Supply Directive”). The Gas Supply Directive establishes a common framework within which member
states must define general, transparent and non-discriminatory security of supply policies compatible with the
requirements of a competitive internal gas market, and focuses on measures to be taken if severe difficulties arise
in the supply of natural gas. The key elements of the Gas Supply Directive are:
•
Member states must adopt adequate minimum security of supply standards, and
•
A “three-step procedure” will take effect in the event of a major supply disruption for a significant
period of time. Under the “three-step procedure,” the gas industry should take measures as a first
response to such a disruption, followed by national measures taken by member states. In the event of
inadequate measures at the national level, the Gas Coordination Group, consisting of representatives of
member states, the gas industry and relevant consumers under the chairmanship of the European
Commission would then decide on necessary measures.
The Gas Supply Directive was required to be implemented by each member state by May 19, 2006. This
directive has been implemented into German law through the Energy Law of 2005.
Regional Markets
Electricity. In June 2005, the European Regulator Gas and Electricity Group (“ERGEG”) published a
consultation paper on the creation of regional electricity markets and initiated a consultation procedure. The
paper identified four action areas: availability of transmission capacity, availability of information, cooperation
between network operators and incompatibility of wholesale market arrangements. In its conclusion paper dated
February 8, 2006, ERGEG confirmed its intention to pursue the action areas and has therefore set up an
“Electricity Regional Initiative.” The objective of the Regional Initiative is to make concrete improvements in the
development of a single electricity market in Europe by first integrating national markets into regional markets.
The Regional Initiative brings together regulators, the European Commission, member state governments,
companies and other relevant parties to focus on the way in which regional energy markets can develop. For each
of seven identified European electricity regions, a regional coordination committee has been set up that
coordinates the development of harmonized regional network and market rules. The Regional Initiative for the
time being focuses on congestion management and transparency of network and market data.
Gas. After publishing a “roadmap” for the development of EU gas markets in April 2006, which contained
the introduction of three regional gas markets in Europe, ERGEG drafted a detailed program for the regional
market initiative in the summer of 2006 which was discussed in a consultation process during 2007 and will
continue to be discussed throughout 2008. The roadmap contains the following measures for the improvement of
the current EU gas markets:
•
closer cooperation between national regulatory authorities;
•
strict control of unbundling fulfillment, especially in the case of activities in several member states;
•
ad hoc and transparent publication of non-confidential information;
•
improvement of third party access at access points;
•
an improved environment for cross-border trading; and
•
the creation of regional gas markets.
As part of the consultation process and the workstreams within three designated regional gas markets, North
West, South South East and South, all regional gas markets have identified and will continue to pursue the
following topics during 2008:
•
Interconnection and capacity;
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•
Transparency
•
Interoperability; and
•
Development of gas hubs.
Other issues that are being discussed are the regulatory gaps for cross-border cooperation between
regulators.
New European Energy Policy
On January 10, 2007, the European Commission published an “energy package” containing proposals how
to establish a new energy policy and strategy for a more integrated and competitive EU internal energy market,
for ensuring security of energy supply and to combat climate change. The package of proposals included a series
of ambitious targets, but does not yet have any legal impact. The targets were confirmed by the European
Council in March 2007.
•
One EU-wide energy market. In its policy and strategy package of January 2007, the European
Commission announced its strong preference for ownership unbundling, i.e. the separation of ownership
of the electricity and gas transmission networks and the other commercial activities of the utilities. As
an alternative that does not require ownership unbundling the Commission proposed the use of an
independent system operator to operate the electricity and gas transmission networks. Consequently the
European Commission on September 19, 2007 published a proposal for a third energy legislative
package amending the Second Electricity and Gas Directives as well as the regulations on cross-border
electricity trading and on conditions for access to natural gas transmission networks. The draft
amendments propose the introduction of ownership unbundling or independent system operators for
electricity and gas transmission system operators and the formation of European Networks of
Transmission System Operators (ENTSO) formally representing the European electricity / gas
transmission system operators. In addition, the powers of national regulators would be harmonized and
extended. Further, a new regulation on the cooperation of energy regulators has been proposed by the
European Commission which envisages the formation of a new agency for the cooperation of energy
regulators that aims at centralizing regulatory decisions to some extent. The directive and regulation
proposals are currently in the EU co-decision legislative procedure between the European Parliament
and the European Council. In particular, the issue of ownership unbundling is controversial. The
German government has clearly announced that it does not support ownership unbundling but that it will
analyze all possible options. France and Germany, supported by six other member states, have
developed and signed an alternative solution to ownership unbundling. The proposal — the so-called
“Third Option” was sent on January 29, 2008, to the Commission, the Council and the European
Parliament. The “Third Option” is a complex proposal for “Effective and Efficient Unbundling” which
is based on two pillars. The first is related to organization and governance of the undertaking so as to
guarantee effective independence of the transmission system operator. The second is related to grid
investments, market integration and connection of new power plants. Competences and rules are
defined, aiming to ensure sufficient and efficient investment into the grid. It is at this time impossible to
predict if the “Third Option” or any of the other proposals will be enacted into law. For details on
E.ON’s recent agreement with the Commission on unbundling, see “Risk Factors”.
•
Targets and Objectives for reducing Greenhouse gas emissions and promoting renewable energies. In
its energy and strategy package of January 2007 the Commission stipulated the objective of a 20 percent
cut in greenhouse gas emissions compared to 1990 levels by 2020 at the latest. Should other countries
initiate similar plans to combat climate change, the Commission has expressed the possibility of a 30
percent abatement target. For the sectors subjected to emissions trading until 2020 the European
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Commission aims at a CO2-reduction of 21 percent compared to 2005. In parallel, the EU’s objective for
energy generated from renewable sources has been set to account for 20 percent of total energy
consumption by 2020 and increasing the level of biofuels in transport fuel to 10 percent by 2020.
Further, the Commission’s objective concerning energy efficiency is to save 20 percent of total primary
energy consumption by 2020 compared to 1990 levels. Potential methods include a more efficient use of fuels in
vehicles for transport, tougher standards and better labeling for appliances, improved energy performance of the
EU’s existing buildings, and improved efficiency of heat and electricity generation, transmission and distribution.
For more information see “— Environmental Matters — Europe — The EU directive on energy end-use
efficiency and energy services.”
On this basis the European Commission proposed the so called “Green Package” on January 23, 2008, a
legislative package which contains i.e. directive proposals for the Emissions Trading Scheme post 2012 and the
promotion of renewable energies. For more information, see “— Environmental Matters — Europe.”
Germany: Electricity
Electricity Network Access
The First Electricity Directive was implemented in Germany with a framework for negotiated third party
access to high-, medium- and low-voltage networks agreed by the associations of all German utilities and of
industrial customers (Verbändevereinbarung, amended as Verbändevereinbarung II and Verbändevereinbarung
II+). Verbändevereinbarung II+ was valid until December 2003 and subsequently utilities still acted according to
its rules until the Energy Law of 2005 came into force. As of July 13, 2005, electricity network access is
regulated according to the Energy Law of 2005, as described in “— EU/Germany: General Aspects (Electricity
and Gas) — Revisions of the German Energy Law” above.
Electricity Network Charges
As described in “EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy
Law” above, the regulation of electricity network charges started in July 2005, with network charges calculated
according to a cost-based rate-of-return model.
First approval of the network charges by the BNetzA was originally due by May 1, 2006. Due to the
complex check of companies’ cost calculations, approval was delayed by several months and received by E.ON
Energie’s network operators between July and October, 2006. In 2006, approved network charges averaged a
13.7 percent reduction from E.ON Energie’s filed network charges. The approved network charges were applied
by the network operators immediately after receipt of the relevant approval. The BNetzA has announced that it
will require network operators to refund to network customers the difference between operators’ actual network
charges and their approved charges for the period between November 1, 2005 (the day after applications for
network charges approval were due) and the relevant approval date in 2006. Several German utilities have
challenged the BNetzA’s decisions in legal proceedings; a ruling of the competent court in a third party suit
brought by Vattenfall Europe Transmission has denied the BNetzA’s decision to require refunds — this is valid
as well for electricity as gas. A revision of the case is, however, still pending and E.ON will wait until the
legality of the refunds is decided before refunding any network charges. Network charges validity was originally
limited until December 31, 2007, triggering a second round of network charges calculation, which was based
upon network operations’ costs in 2006. Approved costs will be the basis for the forthcoming system of
incentive-based regulation. The expected approvals have been delayed with the transmission system operator
E.ON Netz being the first network operator to receive approval on February 29, 2008. Approved costs have
increased by 4,3 percent compared to the first round of cost regulation. However, this increase only partly
reflects the considerable rise of cost components that cannot be influenced by E.ON Netz (such as network
losses). The approval process with respect to the other network operators is expected to be completed for the
whole group in the next several months.
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Electricity Rate Regulation
Still in the first half of 2007, obligatory prices (general tariffs) at which local and regional distributors sold
electricity to standard-rate and smaller commercial customers were regulated by the economics ministries of
most of the German states (as provided in the BTOElt). The rates were set at a level to assure an adequate return
on investment on the basis of the costs and earnings of the electricity company. However, we believe that these
governmentally-set ceiling rates are not consistent with liberalization and competitive markets. The average price
charged by utilities for an average standard-rate customer in Germany with an assumed annual consumption of
3,500 kWh was, according to the German Association of the Energy and Water Industry (BDEW), 20.64 €cent
per kWh in 2007 (all taxes included), while E.ON Energie charged an average of 20.37 €cent per kWh (weighted
average). The average price quoted by the German Association for Energy Consumption (“VEA”) for industrial
customers was 10. 76 €cent per kWh, while the average price per kWh charged by E.ON Energie was 11.07
€cent per kWh, as quoted by VEA as of July 1, 2007 (net of tax). Pursuant to the Energy Law of 2005, obligatory
electricity rate regulation and therefore BTOElt were abandoned on July 1, 2007.
Germany: Gas
Gas Network Access
Until the Energy Law of 2005 took effect, E.ON Ruhrgas used the framework for third party gas network
access contained in an agreement between E.ON Ruhrgas and the Competition Directorate-General of the
European Commission with respect to a matter that had been pending before the Competition Directorate. The
agreement contained, among other commitments by E.ON Ruhrgas with respect to its transmission business such
as greater transparency and improved congestion management, an agreement to use an entry/exit system for gas
network access. The agreed entry/exit system was introduced by E.ON Gastransport on November 1, 2004. For
more information, see “— Pan-European Gas — Transmission and Storage.” As of July 13, 2005, gas network
access is regulated according to the Energy Law of 2005, as described in “— EU/Germany: General Aspects
(Electricity and Gas) — Revisions of the German Energy Law” above. Under the Energy Law of 2005, gas
network operators have to offer entry and exit capacities for the transmission of gas separately to system users
(entry/exit system). Network access has to be granted without fixing transport routes, which are dependent on the
specific transaction. All network operators are obliged to cooperate, in order to ensure that system users need
only one contract for entry capacities and one contract for exit capacities, including when gas transportation is
carried out via several conducted networks. In order to comply with this requirement, E.ON Gastransport
adjusted its entry/exit system with the introduction of the “ENTRIX 2” system on February 1, 2006.
In order to comply with this statutory obligation, the gas industry started to implement a network access
model at the end of 2005 in consultation with the BNetzA. The BGW and the Association of the Municipalities
(Verband der Kommunalen Unternehmen, or “VKU”) drafted an agreement regarding cooperation between
operators of gas supply networks located in Germany which contains principles for the cooperation of the
network operators and standard terms and conditions for access to networks. The agreement uses one network
access model with different market areas. Within each market area, which each include a number of network
subsections, shippers are entitled to choose the following variants for gas transportation: 1) transmission over
different networks from an entry point to an exit point at the end consumer or 2) transmission from an entry point
to an exit point within a network subsection (e.g. to exit via a “city gate”). E.ON Gastransport adjusted its
entry/exit system in view of the cooperation agreement in October 2006, the date that the new network access
model took effect.
Following the development of the gas industry cooperation agreement, a single gas trader (Nuon
Deutschland GmbH) and a German energy association (Bundesverband Neuer Energieanbieter, or “BNE”) filed
claims against three network operators (including E.ON Hanse) which challenged the use of the second variant
for gas transportation. In November 2006, the BNetzA decided that, according to their assessment, this variant
does not comply with the Energy Law of 2005, thus necessitating changes to the existing gas network operators’
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cooperation agreement. The E.ON Group decided to accept this decision after a detailed analysis of the
regulator’s decision and to implement the necessary changes into the existing cooperation agreement. BGW and
VKU have prepared a revised draft of the cooperation agreement with the necessary changes, to reflect the
decision of the BNetzA. During 2007, the cooperation agreement was accepted by the BNetzA and signed by the
respective parties. This cooperation agreement forces transmission system operators nationwide to offer
customers only one entry and one exit point in their market area (the “two-contract-model”), requiring
subsequently changes in all transportation and also sales contracts. E.ON Gastransport had, by October 2007,
implemented all changes necessary in order to comply with the BNetzA’s decision and the revised cooperation
agreement.
Gas Network Charges
As described in “EU/Germany: General Aspects (Electricity and Gas) — Revisions of the German Energy
Law” above, the regulation of gas network charges started in July 2005, with network charges calculated
according to a cost-based rate-of-return model. After a detailed examination of their application documents by
the BNetzA, approval was granted to E.ON Energie’s distribution network operators between September and
November 2006. In 2006, approved network charges of E.ON Energie’s regional distribution network operators
were reduced by approximately ten percent on average, based on a different interpretation of the new law by the
BNetzA. In addition, the filed network charges of Ferngas Nordbayern GmbH and Thüga in the Pan-European
Gas market unit were reduced by 19.0 and 17.2 percent, respectively. As described above in the case of
electricity network charges, the BNetzA has announced that the lower charges should be economically effective
from the day after applications were due, in this case February 1, 2006. Currently approved network charges will
be valid until March 31, 2008. For new network charges from April 1, 2008 all network operators — except
E.ON Gastransport, as stated below — issued new network charges applications by the end of September, 2007,
reflecting cost developments between 2004 and 2006. As in the case of electricity network charges, approved
costs will be the base for the following incentive-based regulation system, starting in 2009. Results of the
BNetzA examination of E.ON’s network operators’ applications, at this point in time, are hard to predict.
The Energy Law of 2005 provides an exemption from cost calculations for gas transmission networks if
actual or potential pipeline competition can be proven. In January 2006, E.ON Gastransport gave notice to the
BNetzA that it would calculate its network costs on a market-oriented basis (rather than submitting the charges
for BNetzA approval). As the BNetzA has not yet determined whether actual or potential pipeline competition
exists, E.ON Gastransport is not yet required to submit calculated gas network transmission charges to the
BNetzA as described above.
Gas Rates
Gas and heat rates are not regulated in Germany, but the GWB does apply. On this law, see “EU/Germany:
General Aspects (Electricity and Gas) — Further German legislation.”
For information about proceedings regarding gas price calculations, e.g. against E.ON Hanse, see “Risk
Factors.”
U.K.
Liberalization of the electricity and gas industries in the United Kingdom largely pre-dated the requirements
of the First and Second Electricity and Gas Directives described under “— EU/Germany: General Aspects
(Electricity and Gas)” above, but the U.K. regulatory regime is basically consistent with the terms of such
directives. E.ON UK is also subject to U.K. and EU legislation on competition.
The gas and electricity markets in England, Wales and Scotland are regulated by a single energy regulator,
the Gas and Electricity Markets Authority (the “Authority”), established in November 2000. The Authority is
assisted by Ofgem, which is governed by the Authority. The principal objective of the Authority is to protect the
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interests of consumers of gas and electricity, wherever appropriate, by the promotion of effective competition in
the electricity and gas industries. The Authority may grant licenses authorizing the generation, transmission,
distribution or supply of electricity and the transportation, shipping or supply of gas. The Energy Act 2004 also
gives the Authority power to license the operation of gas and electricity interconnectors. Any such license will
incorporate by reference as appropriate the standard conditions determined for that type of license, which may be
modified by the Authority. The license may also include other conditions that the Authority considers
appropriate. License conditions may be modified in accordance with their terms or under the provisions of the
Electricity Act 1989 (as amended) or the Gas Act 1986 (as amended), as appropriate. The Authority has power to
impose financial penalties on licensees and/or issue enforcement orders for breach of license conditions and other
relevant requirements.
The Authority also has within its designated areas of responsibility many of the powers of the Office of Fair
Trading to apply and enforce the prohibitions in the Competition Act 1998 in relation to anti-competitive
agreements or abuse of market dominance, including imposing financial penalties for breach. Since May 1, 2004,
following reform of the EC competition law regime, the Authority also has the power to apply Articles 81 and 82
of the EC Treaty, which deal with control of anti-competitive agreements and abuse of market dominance.
Within its designated areas, the Authority also exercises concurrently with the Office of Fair Trading certain
functions under the Enterprise Act 2002 relating to the power to make market investigation references to the
Competition Commission.
The U.K. government has introduced three bills to parliament in the 2007/8 parliamentary session which are
intended to support delivery of the government’s energy and environmental policy objectives. The Climate
Change Bill sets a target for the year 2050 for the reduction of greenhouse gas emissions, provides for a system
of carbon budgeting for the U.K. economy, and establishes a Committee on Climate Change to advise the
government. The Planning Bill introduces a new system for approving major infrastructure of national
importance, such as larger power stations and electricity transmission lines, with the objective of streamlining
decision-making and avoiding long public inquiries. The Energy Bill contains legislative provisions needed to
implement policies set out in the 2007 Energy White Paper and the 2008 White Paper on Nuclear Power. These
include provisions for a regulatory framework to enable investment in carbon capture and storage projects, for
changes to the Renewables Obligation to allow support for different technologies, and for operators of new
nuclear power stations to accumulate funds to meet the costs of decommissioning and their share of waste
management costs. It is too early to predict if any of these proposals will be implemented, either in their current
form or at all.
Electricity
Unless covered by a license exemption, all electricity generators operating a power station in England,
Wales or Scotland are required to have a generation license. The principal generation license within the E.ON
U.K. business is held by E.ON UK. Although generation licenses do not contain direct price controls, they
contain conditions which regulate various aspects of generators’ economic behavior.
The distribution licenses held by Central Networks East and Central Networks West (the two companies
operating under the brand Central Networks) authorize the licensee to distribute electricity for the purpose of
giving a supply to any premises in Great Britain. They provide for a distribution services area, equating to the
former authorized area of the former public electricity suppliers in the East Midlands and West Midlands areas,
respectively, in which the licensee has certain specific distribution services obligations. Under the Electricity Act
1989 (as amended), an electricity distributor has a duty, except in certain circumstances, to make a connection
between its distribution system and any premises for the purpose of enabling electricity to be conveyed to or
from the premises and to make a connection between its distribution system and any distribution system of
another authorized distributor, for the purpose of enabling electricity to be conveyed to or from that other system.
The license obligations extend to not distorting the competitive market for the provision of those
connections either through the distribution business’ own connection activities, through an affiliate or through an
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unrelated third party. Over the last few years a number of U.K. distributors, including both Central Networks
companies, have been investigated by Ofgem over concerns that they may have breached this aspect of their
licenses or competition law in this regard. On December 11, 2007 Central Networks received notification from
Ofgem that it believed both Central Networks East and West had breached their respective licenses and distorted
competition in providing new connections. However, Ofgem accepted that this breach was not commercially
driven and did not have an impact on the market. As a consequence, Ofgem decided that it was not appropriate to
impose a penalty in this instance.
The distribution licenses place price controls on distribution. The current distribution price controls are in
effect for a five-year period ending March 2010, and are expected to provide for overall stable prices for the
distribution of electricity over that period. The price controls are intended to provide companies with sufficient
revenues to allow them to finance their operating costs and capital investment. In addition to caps on revenue, the
price controls also include targets for network losses and overall quality of network performance based upon the
average number and duration of supply outages experienced by consumers. Companies can be either rewarded or
penalized for exceeding or failing these targets.
The supply license held by E.ON Energy Limited (formerly Powergen Retail) authorizes the licensee to
supply electricity to any premises in Great Britain. It provides for a supply services area, equating to the former
authorized area of Powergen Energy plc, as the former public electricity supplier in the East Midlands, in which
the licensee has certain specific supply services obligations. Ofgem relies on monitoring competition and, where
necessary, using its powers under the Competition Act 1998 to tackle abuse. In addition, Ofgem is pursuing a
range of measures under its Social Action Plan to help vulnerable and low-income customers. It is also
continuing to work with the industry to improve the process for customers when they switch suppliers.
The U.K. government indicated in the Energy White Paper published in May 2007 that it would consider
introducing legislation requiring suppliers to offer social programmes if there continued to be a wide disparity in
the voluntary initiatives offered by suppliers. Ofgem’s assessment of suppliers’ programmes showed that E.ON
UK’s programme was substantive, costing around 0.9GBP/account per year. The Energy Bill currently before
parliament does not contain any legislation on social programmes.
A separate supply license is held by E.ON UK, which does not extend to supply to domestic premises. E.ON
UK also continues to hold a second-tier supply license for Northern Ireland (to which the Utilities Act 2000
generally does not extend).
Following the acquisition of the U.K. retail energy business of the TXU Group (“TXU”) in October 2002,
E.ON UK also holds a number of additional electricity and gas supply licenses through certain of the companies
that were acquired as part of that deal. Customers supplied under these licenses have been migrated to the supply
licenses held by E.ON Energy Limited and E.ON UK.
In June 2005, E.ON UK acquired the electricity supply company of Economy Power Limited (“Economy
Power”). Migration of former Economy Power customers, which were supplied under a separate electricity
supply license, to the supply licenses held by E.ON Energy Limited and E.ON UK was completed in June 2006.
Under Section 33BC of the Gas Act 1986, Section 41A of the Electricity Act 1989 and Section 103 of the
Utilities Act 2000, electricity and gas suppliers are subject to a statutory obligation (known as the Energy
Efficiency Commitment (EEC)) which requires them to achieve targets for installing energy efficiency measures
in the household sector. The current obligation (known as the Electricity and Gas (Energy Efficiency
Obligations) Order 2004) covers the period from April 1, 2005 to March 31, 2008. A range of energy efficiency
measures qualify for the obligation, with E.ON UK expecting that about 60 percent of its expenditures will be on
home insulation. E.ON UK met its targets a few months ahead of schedule and at a slightly lower cost than
government’s forecast and expects that the cost to suppliers of this requirement will be about GBP0.9 /account
per year. The obligation for the period from April 1, 2008 to March 31, 2011 involves targets which are roughly
double those for the period ending March 31, 2008.
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Gas
Licenses to ship gas and to supply gas are held by a number of companies in the U.K. market unit.
E.ON UK operates gas pipelines that are subject to the Pipelines Act 1962 (as amended), including pipelines
at Killingholme, Cottam, Connah’s Quay, Enfield and Winnington. This legislation gives third parties rights to
apply to the Secretary of State for a direction requiring the pipeline owner to make spare capacity available to the
third party.
Nordic
The description under “— EU/Germany: General Aspects (Electricity and Gas)” above is applicable to
E.ON Sverige AB and its two Finnish subsidiaries, and these companies are also subject to EU and national
legislation on competition.
Electricity. The primary legislation applicable to the electricity industry in Sweden is the Swedish
Electricity Act (Ellag (1997:857), or the “Electricity Act”) that came into force on January 1, 1998, and the
statutes and provisions issued pursuant to the Electricity Act.
The Electricity Act promotes competition by creating opportunity for each customer to enter into an
agreement with the supplier of the customer’s choice. In order to further ensure competition in sales of
electricity, the Electricity Act also requires functional unbundling of the generation/sales and the transmission
and distribution businesses, as well as legal unbundling of these businesses so that transmission and distribution
operations are carried out by a separate legal entity. As a consequence, electricity customers in Sweden have
separate contracts with a retail supplier and an electricity distributor. In Sweden, retail prices are not regulated.
Transmission and distribution of electricity are considered to be natural monopolies and are subject to
regulation. The Energy Markets Inspectorate (“EMI”), formerly part of the Swedish Energy Agency and since
January 1, 2008 an independent authority, grants licenses to erect power lines and carry on distribution
operations. As the regulator for the Swedish electricity and gas markets, EMI has the authority to supervise the
monopoly transmission and distribution businesses in order to protect the interests of customers. EMI also
oversees third party access to the networks. It monitors network charges and other terms for the transmission and
distribution of electricity and is responsible for setting certain standards with respect to transmission and
distribution.
In Sweden, the high-voltage transmission grid is owned and operated by Svenska Kraftnät, the state-owned
national grid company. The mid- and low-voltage distribution networks are owned and operated by a large
number of both privately and publicly owned companies. A tariff, consisting of an annual capacity charge and an
hourly transmission energy charge, applies for access to the national transmission as well as the regional and
local distribution networks. Market participants pay for the right to feed in or take out electricity at just one point,
which gives the participant access to the entire grid system and enables it to trade with any of the other market
participants in the Nordic grid system. EMI also monitors quality of supply data for statistical reasons.
Changes in the Electricity Act regarding distribution regulation came into force in July 2002. The
amendments provide that network charges have to be reasonable compared to the distribution companies’
performance. The concept of performance has initially been defined by EMI, which annually constructs a
fictitious network for each utility in order to calculate the resources needed in the local network business. The
resulting value of the network is then compared to the utility’s actual revenues in order to assess the
reasonableness of the network charges. For this purpose EMI has created a regulation model called the “Network
Performance Assessment Model” (“NPAM”). At present, EMI is only assessing the performance of the local
networks but intends to include the regional networks in the near future.
The NPAM was used for the first time to evaluate network charges for 2003. Swedish electricity distribution
companies reported the required information to EMI, which examined the operation of the companies. EMI
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decided in December 2004 to prolong its inspection of a number of Swedish electricity distribution companies.
Within E.ON Sverige, 14 distribution areas were initially subject to the additional inspection, with inspection
satisfactorily concluded for 13 of these areas. For the remaining area, EMI initially decided that E.ON Sverige be
required to reduce its network charges for 2003 by SEK 19.7 million, by repaying customers a portion of the
network charges. E.ON Sverige has appealed the decision to the relevant administrative court. So far, EMI has
admitted an increase of the weighted average cost of capital (WACC) from 4.8 percent to 6.7 percent and
shortened depreciation-time for meters, which has reduced the obligation of repayment to SEK15.1 million. A
judgment in the court case is expected in the middle of 2008 at the earliest. With respect to 2004 network
charges, EMI decided in October 2005 to prolong its inspection of four distribution areas within E.ON Sverige.
EMI has not issued a final decision regarding 2004 network charges. With respect to 2005 and 2006 network
charges, EMI decided in December 2006 and December 2007, respectively, not to prolong its inspection of any
distribution areas within E.ON Sverige, which means that the 2005 and 2006 network charges cannot be subject
to any further actions by EMI.
In July 2005, several sections of the Electricity Act were amended in order to comply with the Second
Electricity Directive. Among other changes, the amendments require more detailed regulation concerning the
calculation of network charges; more information on the invoice and in advertising about the composition of
energy sources used in producing the delivered electricity; that distribution companies procure the electricity
required to cover their net losses in an open, non-discriminatory and market-oriented manner; and that
distribution companies establish a supervision plan which states what kind of actions will be taken in order to
prevent discriminatory behavior towards other operators in the market.
As a result of a severe storm that hit Sweden in January 2005, the Swedish government passed new
legislation concerning electricity distribution in December 2005. Under the new law (SFS 2005: 1110), which
was incorporated into the Electricity Act and which mainly came into force on January 1, 2006, a customer shall
be compensated for power outages that last more than 12 hours, with the compensation payment being equal to at
least 12.5 percent and up to 300 percent of the customer’s annual network charges, with compensation being
based on the length of the outage. With effect from January 1, 2011, the new legislation also stipulates that the
maximum allowable period of time for a power outage is 24 hours. If this time period is exceeded the provisions
concerning compensation payment will still be applied and if this occurs frequently, the network operator will
risk losing its license to operate the grid area.
In December 2007, a governmental commission (the Energy Network Commission) proposed a new
regulation pursuant to which the supervisory authority would approve the network companies’ transmission and
connection charges before they were allowed to take effect. According to the proposal, EMI would, prior to a
new supervisory period and for each network company, determine the overall revenues that the network company
would be allowed to gain from the network tariffs during the coming supervisory period (revenue frame). The
revenue frame would be calculated so that it covers reasonable costs for running the network operations and gave
a reasonable return on the capital needed in order to run the operations (capital base). The basic starting point in
the calculation of network companies’ capital bases would be the companies’ existing electricity networks, for
example in the form of cables, transformer stations, etc, and other assets that are used in network operations. The
Commission proposes that the first supervisory period should begin on January 1, 2012.
Gas. In order to comply with the requirements of the Second Gas Directive, a new Swedish Natural Gas Act
(Naturgaslag (2005:403) or the “Natural Gas Act”) was implemented on July 1, 2005. From this date, all
non-household customers were able to choose their gas supplier. Household customers have also been eligible
since July 1, 2007. In addition, the Natural Gas Act stipulates legal and functional unbundling of the
transmission, distribution, storage and regasification (LNG) businesses from the supply business and requires
separate accounting for the transmission, distribution, storage and regasification (LNG) businesses. The law also
requires non-discriminatory third party access to the gas networks based on published charges for eligible
customers. Further, distribution and transmission companies must also establish a supervision plan, which states
what kind of actions will be taken in order to prevent discriminatory behavior towards other operators in the
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market. As in the former Natural Gas Act, the new Natural Gas Act contains rules regarding the granting of
licenses to build and use natural gas pipelines and natural gas storage, as well as new rules regarding the granting
of licenses for LNG facilities.
The Natural Gas Act also requires EMI to pre-approve the criteria used by network operators to establish
network charges valid from 2006. EMI approved the model (the criteria for network charges) used by E.ON
Sverige in November 2005. In addition, the Natural Gas Act requires that the revenues from network charges be
reasonable compared to costs for capital and operations, and stipulates that the reasonableness of network
charges remains subject to inspection by EMI ex-post. If EMI finds that revenues from network charges are not
reasonable, it can obligate the operator to reduce network charges. A first test inspection was launched in the
spring of 2007 regarding revenues for the second half of 2005. This inspection was finished in December 2007
without any judgment being issued. According to EMI, the inspection was closed because of the difficulties in
getting correct basic data for the second half of 2005 since there was no obligation to have separate accounts for
the first half of 2005. The first full-year inspection will take place in 2008 regarding revenues for 2006.
Security of Energy Supply (Gas). The Gas Supply Directive has been implemented in the Swedish Natural
Gas Act. The amendments entered into force July 1, 2006 and impose a general obligation on the operators in the
natural gas market to plan and take necessary measures to ensure the supply of natural gas. The Natural Gas Act
does not contain any detailed regulation on how the operators shall perform their obligation. Instead, the Swedish
government has authorized the Swedish Independent System Operator (Affärsverket svenska kraftnät) to
determine in more detail which measures shall be taken in this respect. At this time it is unclear which
obligations can be imposed on the operators in Sweden.
Renewable Energy and Electricity Certificates. The Swedish energy policy is based on the assumption that
Sweden will obtain all its energy from renewable energy sources in the long term. The most important policy
instrument in promoting renewable electricity production is the electricity certificate system. The Swedish
electricity certificate system has been in operation since May 2003. The objective of the system, which is based
on the Swedish Act on Electricity Certificates (SFS 2003:113), was initially to increase the volume of electricity
produced from renewable energy sources by 10 TWh by 2010 as compared with the 2002 level.
During 2004 EMI gave the Ministry of Sustainable Development recommendations on the electricity
certificate system based on an analysis of the system. EMI recommended that the electricity certificate system be
made permanent and that long-term quota levels be set if necessary investments in renewable energy are to take
place. Due in part to this analysis, the Swedish government delivered proposals on an amendment of the Act on
Electricity Certificates to the Swedish Parliament. The proposed amendment contained suggestions that the
Swedish electricity certificate system should be extended until 2030 and that the objective of the system be
revised to increase the volume of electricity produced from renewable energy sources by 17 TWh by 2016 as
compared with the 2002 level. The proposals were adopted by the Swedish parliament in June 2006 and the
amendments entered into force on January 1, 2007. For more information about the current system, see
“— Nordic — Market Environment.”
In February 2008, a governmental commission (the Grid Connection Inquiry) proposed a new regulations to
promote the development of renewable electricity production. In the current system, plants with a capacity of
1.5 MW or lower are granted a reduction in network tariffs. The proposed new regulation would replace this rule
with a cap on the total network charges for renewable energy production at SEK 0.03 per kWh. The inquiry also
proposed the establishment of a grid investment fund to partly finance necessary and costly network investments
for connecting renewable energy production that fulfil the criteria for being allocated electricity certificates to the
network. The fund will be financed by end-customers through the network companies in accordance with
customers’ underlying electricity consumption (per kWh).
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U.S. Midwest
Retail Electric Rate Regulation
The KPSC has regulatory jurisdiction over the rates and service of LG&E and KU and over the issuance of
certain of their securities. The Virginia State Corporation Commission also has parallel regulatory jurisdiction
with respect to certain of KU’s operations. The KPSC, in the case of LG&E and KU, and the Virginia State
Corporation Commission, in the case of KU, regulate the retail rates and services of LG&E or KU and, via
periodic public rate cases and other proceedings, establish tariffs governing the rates LG&E and KU may charge
customers. Because KU owns and operates a small amount of electric utility property in Tennessee and serves
five customers there, KU is also subject to the jurisdiction of the Tennessee Regulatory Authority.
LG&E and KU are each a “public utility” as defined in the Federal Power Act. Each is subject to the
jurisdiction of the Department of Energy and the FERC with respect to the matters covered in the Federal Power
Act, including the wholesale sale of electric energy in interstate commerce. In addition, the FERC and certain
states share jurisdiction over the issuance by public utilities of short-term securities.
In June 2004, the KPSC issued an order approving increases in the base electric and gas rates of LG&E and
the base electric rates of KU. In the KPSC’s order, LG&E was granted increases in annual base electric rates of
approximately $43.4 million or 7.7 percent and in annual base gas rates of approximately $11.9 million or
3.4 percent. KU was granted an increase in annual base electric rates of approximately $46.1 million or 6.8
percent. The rate increases took effect in July 2004. In March 2006, the KPSC issued a final order in the rate case
proceedings which resolved a final calculational issue in LG&E’s and KU’s favor consistent with the original
July 2004 rate increase order. For information about 2007 developments regarding re-regulation involving a
hybrid model of rate regulation, see “— U.S. Midwest — Market Environment.”
The electric rates of LG&E and KU in Kentucky contain fuel adjustment clauses whereby increases and
decreases in the cost of fuel for electric generation are reflected in the rates charged to all retail electric
customers. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments, and at
two-year intervals to review past operations of the fuel clause and transfer the then-current fuel adjustment
charge or credit to the base charges. At present, the KPSC also requires that electric utilities, including LG&E
and KU, publicly file certain documents relating to fuel procurement and the purchase of power and energy from
other utilities.
In 1992, the Kentucky General Assembly enacted a statute which provides an alternative procedure to
increasing base rates by allowing utilities to recover the costs of environmental compliance by means of a
surcharge rather than by opening a general rate case. Pursuant to this statute, LG&E’s and KU’s electric rates in
Kentucky contain an environmental cost recovery surcharge which recovers costs incurred by LG&E or KU that
are required to comply with the U.S. Clean Air Act Amendments of 1990 and other environmental regulations
which apply to coal combustion wastes and by-products from facilities utilized for the production of energy from
coal. The magnitude of the surcharge fluctuates with the level of approved environmental compliance costs
incurred during each period. At six-month intervals, the KPSC reviews the operation of each utility’s
environmental surcharge, and, after review, may disallow any surcharge amounts found not to be just and
reasonable. In addition, every two years the KPSC reviews and evaluates the past operation of the surcharge, and,
after review, may disallow improper expenses and, to the extent appropriate, incorporate surcharge amounts
found to be just and reasonable into the utility’s existing base rates.
Retail Gas Rate Regulation
LG&E’s gas rates in Kentucky contain a gas supply charge, whereby increases or decreases in the cost of gas
supply are reflected in LG&E’s rates, subject to approval of the KPSC. The gas supply charge procedure prescribed
by order of the KPSC provides for quarterly rate adjustments to reflect the expected cost of gas supply in that
quarter. In addition, the gas supply charge contains a mechanism whereby any over- or under-recoveries of gas
supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor.
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Transmission Developments
In September 2006, LG&E and KU withdrew from the MISO transmission organization. In LG&E’s and
KU’s view, the costs of MISO membership outweighed the benefits, particularly in light of the financial impact
of MISO’s implementation of new day-ahead and real-time energy markets in April 2005. In October 2006,
LG&E and KU paid MISO $33 million in satisfaction of a contractual aggregate exit fee. Pursuant to agreement,
LG&E, KU and MISO have filed an application with the FERC to approve adjustments to certain components of
this calculated amount, including a potential aggregate refund to LG&E and KU of $6.4 million over eight years.
LG&E and KU estimate that the exit fee will be more than offset by savings resulting from withdrawal from
MISO. Orders of the KPSC approving the exit from MISO have authorized the establishment of a regulatory
asset for the exit fee, subject to adjustment for possible future MISO credits, and a regulatory liability for certain
revenues associated with former MISO charges. Historically, LG&E and KU have received approval to recover
regulatory assets and liabilities in future rate proceedings, although this cannot be assured. Pursuant to FERC
requirements, LG&E and KU have contracted with independent third parties to manage applicable operational
aspects of their transmission systems following the MISO exit, including functions relating to reliability
coordinator and independent transmission system operator roles. The SPP now functions as the transmission
system operator and the TVA now functions as the transmission reliability coordinator, respectively, for LG&E
and KU.
LG&E, KU and other E.ON U.S. subsidiaries sell excess power pursuant to FERC-granted cost-based and
market-based rate authorities. In connection with recent FERC market-based rate and market power regulatory
developments, the E.ON U.S. entities operate under approved tariffs whereby they may make applicable
wholesale power sales within their own control areas (and one adjacent control area) subject to a price cap set at
a cost-based price. The tariffs further allow for sales at market-based rates at the boundary of such control areas,
subject to certain restrictions. Industry-wide FERC proceedings continue with respect to market-based rate
matters, and E.ON U.S.’s market-based rate authority is subject to such future developments.
The charges relating to transmission and wholesale power market structures and prices following LG&E’s
and KU’s exit from MISO are not completely estimable and may have variable effects on energy and
transmission purchases and sales and on related costs and revenues. Additional changes may have an effect on
LG&E’s and KU’s ability to access the transmission system for wholesale or native load power activities. LG&E
and KU believe that, over time, the benefits and savings from their exit of MISO will outweigh the costs and
expenses.
A number of regional or industry-wide general FERC proceedings regarding transmission market structure
changes are in varying stages of development. In the ordinary course of business, LG&E and KU, either directly
or via industry groups, participate in many of these proceedings.
Energy Policy Act of 2005 and Repeal of PUHCA
The Energy Policy Act of 2005 (“EPAct 2005”) was enacted in August 2005. Among other matters, the
comprehensive legislation contains provisions mandating improved electric reliability standards and
performance; providing certain economic and other incentives relating to transmission, pollution control and
renewable generation assets; increasing funding for clean coal generation incentives; repealing PUHCA; and
establishing a new Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 reduces or
eliminates many prior federal regulatory constraints applicable to public utility holding companies in such areas
as mergers and acquisitions, non-energy-related investments, financial and capital structures, utility system
integration, affiliate services, and reporting and record-keeping requirements. LG&E and KU currently believe
they have the necessary FERC authorizations and approvals to conduct their operations under the EPAct 2005
and PUHCA 2005 as presently conducted, including financing approvals, and, to the extent required, will apply
for additional authorizations as applicable.
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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. In February 2006, the KPSC issued a staff report noting no substantive issues and closed the
integrated resource planning proceedings. The company will make its next filing in April 2008.
Pursuant to Kentucky law, the KPSC has established the service boundaries for LG&E, KU and other utility
companies, other than municipal corporations, within which each such supplier has the exclusive right to render
retail electric service.
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DIRECTORS AND SENIOR MANAGEMENT
General
In accordance with the German Stock Corporation Act, E.ON has a Supervisory Board and a Board of
Management. The two Boards are separate and no individual may simultaneously be a member of both Boards.
The Board of Management is responsible for managing the day-to-day business of E.ON in accordance with
the Stock Corporation Act and E.ON’s Articles of Association. The Board of Management is authorized to
represent E.ON and to enter into binding agreements with third parties on behalf of it.
The principal function of the Supervisory Board is to supervise the Board of Management. It is also
responsible for appointing and removing the members of the Board of Management. The Supervisory Board may
not make management decisions, but may determine that certain types of transactions require its prior consent.
In carrying out their duties, the individual Board members must exercise the standard of care of a diligent
and prudent businessperson. In complying with such standard of care, the Boards must take into account a broad
range of considerations including the interests of E.ON and its shareholders, employees and creditors. In
addition, the members of the Board of Management are personally liable for certain violations of the Stock
Corporation Act by the Company.
Corporate Governance
German stock corporations are governed by three separate bodies: the annual general meeting of
shareholders, the supervisory board and the board of management. Their roles are defined by German law and by
the corporation’s articles of association, and may be described generally as follows:
•
The annual general meeting of shareholders ratifies the actions of the corporation’s supervisory board
and board of management. It decides, among other things, on the amount of the annual dividend, the
appointment of an independent auditor and certain significant corporate transactions. In corporations
with more than 2,000 employees, shareholders and employees elect or appoint an equal number of
representatives to the supervisory board. The annual general meeting must be held within the first eight
months of each fiscal year.
•
The supervisory board appoints and removes the members of the board of management and oversees the
management of the corporation. Although prior approval of the supervisory board may be required in
connection with certain significant matters, the law prohibits the supervisory board from making
management decisions.
•
The board of management manages the corporation’s business and represents it in dealings with third
parties. The board of management submits regular reports to the supervisory board about the
corporation’s operations and business strategies, and prepares special reports upon request. A person
may not serve on the board of management and the supervisory board of a corporation at the same time.
Cooperation between the Board of Management and the Supervisory Board. The E.ON Board of
Management manages the business of the Company, with all its members bearing joint responsibility for its
decisions, in accordance with German law. The Board of Management establishes the Company’s objectives, sets
its fundamental strategic direction, and is responsible for corporate policy and group organization.
The Board of Management regularly reports to the Supervisory Board on a timely and comprehensive basis
on all issues of corporate planning, business development, risk assessment and risk management.
Conflicts of Interest. In order to ensure that the Supervisory Board’s advice and oversight functions are
conducted on an independent basis, no more than two former members of the Board of Management may be
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members of the Supervisory Board. The Supervisory Board is required to report any conflicts of interest to the
annual shareholders’ meeting and to describe how the conflicts have been handled. Any material conflict of
interest of a non-temporary nature will result in the termination of the member’s appointment to the Supervisory
Board.
Members of the Board of Management are also required to promptly report conflicts of interest to the
Executive Committee of the Supervisory Board and to the full Board of Management.
The Supervisory Board Committees. The Supervisory Board has 20 members and, in accordance with the
German Co-determination Act (Mitbestimmungsgesetz), is composed of an equal number of shareholder and
employee representatives. It supervises the management of the Company and advises the Board of Management.
The Supervisory Board has formed committees from among its members.
The Executive Committee consists of four members. It prepares meetings of the Supervisory Board and
advises the Board of Management on matters of general policy relating to the strategic development of the
Company. In urgent cases (i.e., if waiting for the prior approval of the Supervisory Board would materially
prejudice the Company), the Executive Committee decides on business transactions requiring prior approval by
the Supervisory Board. The Executive Committee also performs the functions of a remuneration committee.
The Audit Committee consists of four members who have special knowledge in the field of accounting or
business administration. The Audit Committee deals in particular with issues relating to the Company’s
accounting policies and risk management, issues regarding the independence of the Company’s external auditors,
the establishment of auditing priorities and agreements on auditors’ fees, including E.ON’s policy for the
approval of all audit and permissible non-audit services performed by the Company’s independent auditors. The
Audit Committee also prepares the Supervisory Board’s decision on the approval of the annual financial
statements of E.ON AG and the acceptance of the annual consolidated financial statements.
The Finance and Investment Committee consists of four members. It advises the Board of Management on
all issues of Group financing and investment planning. It decides on behalf of the Supervisory Board on the
approval of the acquisition and disposition of companies, company participations and parts of companies, as well
as on finance activities whose value exceeds 1 percent of the Group’s equity, as listed in the latest consolidated
balance sheet. If the value of any such transactions or activities exceeds 2.5 percent of this equity, the Finance
and Investment Committee will prepare the Supervisory Board’s decision on such matters.
E.ON has instituted the following measures to improve the transparency of its corporate governance and
financial reporting:
•
In addition to E.ON’s general Code of Conduct for all employees, the Company has developed a special
Code of Ethics for members of the Board of Management and senior financial officers and published the
text on its corporate website at www.eon.com. Material appearing on the website is not incorporated by
reference in this document. This code obliges these managers to make full, appropriate, accurate, timely
and understandable disclosure of information both in the documents E.ON submits to the regulatory
authorities and in its other corporate publications.
Supervisory Board (Aufsichtsrat)
The present Supervisory Board of E.ON consists of twenty members, ten of whom were elected by the
shareholders by a simple majority of the votes cast at a shareholder meeting in accordance with the provisions of
the Stock Corporation Act, and ten of whom were elected by the employees in accordance with the German
Co-determination Act (Mitbestimmungsgesetz).
A member of the Supervisory Board elected by the shareholders may be removed by the shareholders by a
majority of the votes cast at a meeting of shareholders. A member of the Supervisory Board elected by the
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employees may be removed by three-quarters of the votes cast by the relevant class of employees. The
Supervisory Board appoints a Chairman and a Deputy Chairman of the Supervisory Board from amongst its
members. At least half the total required number of members of the Supervisory Board must be present or
participate in the decision making to constitute a quorum. Unless otherwise provided for by law, resolutions are
passed by a simple majority of the votes cast. In the event of a tie, another vote is held and the Chairman (who is,
in practice, a representative of the shareholders because the representatives of the shareholders have the right to
elect the Chairman if two-thirds of the total required number of members of the Supervisory Board fail to agree
on a candidate) then casts the tie-breaking vote.
The members of the Supervisory Board are each elected for the same fixed term of approximately five
years. The term expires at the end of the annual general shareholders’ meeting after the fourth fiscal year
following the year in which the Supervisory Board was elected. Reelection is possible. The remuneration of the
members of the Supervisory Board is determined by E.ON’s Articles of Association.
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Because all members of the Supervisory Board are elected at the same time, their terms expire
simultaneously. The term of a substitute member of the Supervisory Board elected or appointed by a court to fill
a vacancy ends at the time when the term of the original member would have ended. The incumbent members of
E.ON’s Supervisory Board, their respective ages and their principal occupation and experience, each as of
December 31, 2007, as well as the year in which they were first elected or appointed to the Supervisory Board
are as follows:
Name and Position Held
Age
Principal Occupation
Ulrich Hartmann(1)(2)*(3)*(4) . . . . . . . . . . . . . . . . .
Chairman of the Supervisory Board
69
Retired Co-Chief Executive Officer of
E.ON AG; formerly Chairman of the Board
of Management and Chief Executive Officer
of VEBA AG
Year First
Elected
2003
Supervisory Board Memberships/
Directorships:
Deutsche Bank AG, Deutsche Lufthansa AG,
IKB Deutsche Industriebank AG (Chairman),
Münchener Rückversicherungs-Gesellschaft
AG, Henkel KGaA
Hubertus Schmoldt(2)(3)(6) . . . . . . . . . . . . . . . . . .
Deputy Chairman of the Supervisory Board
62
Chairman of the Board of Management of
Industriegewerkschaft Bergbau, Chemie,
Energie
1996
Supervisory Board Memberships/
Directorships:
Bayer AG, DOW Olefinverbund GmbH,
Deutsche BP AG, RAG Aktiengesellschaft,
Evonik Industries AG
Dr. Karl-Hermann Baumann(1)* . . . . . . . . . . . . .
Member of the Supervisory Board
72
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, Bayer Schering Pharma AG
Sven Bergelin(6)(7) . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
44
Director, National Energy Working Group,
Unified Services Sector Union (ver.di)
2007
Supervisory Board Memberships/
Directorships:
E.ON Avacon AG, E.ON Kernkraft GmbH
Dr. Rolf-E. Breuer . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
70
Formerly Chairman of the Supervisory Board
of Deutsche Bank AG; formerly Spokesman
of the Board of Management of Deutsche
Bank AG
Supervisory Board Memberships/
Directorships:
Landwirtschaftliche Rentenbank(5)
183
1997
Name and Position Held
Age
Principal Occupation
Gabriele Gratz(1)(6) . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
59
Chairwoman of the Works Council of
E.ON Ruhrgas AG
Year First
Elected
2005
Supervisory Board Memberships/
Directorships:
E.ON Ruhrgas AG
Wolf-Rüdiger Hinrichsen(2)(3)(6) . . . . . . . . . . . . .
Member of the Supervisory Board
52
Vice-Chairman of the Group Workers’
Council of E.ON AG
1998
Ulrich Hocker . . . . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
57
General Manager of the German Investor
Protection Association
1998
Supervisory Board Memberships/
Directorships:
Feri Finance AG, Arcandor AG,
ThyssenKrupp Stainless AG, Deutsche
Telekom AG, Gartmore SICAV(5), Phoenix
Mecano AG(5) (Chairman)
Eva Kirchhof(6) . . . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
50
Diploma-Physicist, E.ON Sales and Trading
GmbH
2002
Prof. Dr. Ulrich Lehner(3)(4) . . . . . . . . . . . . . . . .
Member of the Supervisory Board
61
President and Chief Executive Officer,
Henkel KGaA
2003
Supervisory Board Memberships/
Directorships:
Dr. Ing. h.c.F. Porsche AG, Porsche
Automobil Holding SE, HSBC Trinkaus &
Burkhardt AG, Novartis AG
Dr. Klaus Liesen . . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
76
Honorary Chairman of the Supervisory
Board of E.ON Ruhrgas AG and of
Volkswagen AG; formerly Chairman of the
Supervisory Board of E.ON Ruhrgas AG
1991
Erhard Ott(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
54
Member of the Board of Management,
Unified Services Sector Union (ver.di)
2005
Supervisory Board Memberships/
Directorships:
E.ON Energie AG
Hans Prüfer(6) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
58
Chairman of the Group Works Council,
E.ON AG
2006
Klaus Dieter Raschke(1)(6) . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
54
Chairman of the Combined Works Council,
E.ON Energie AG
2002
Supervisory Board Memberships/
Directorships:
E.ON Energie AG, E.ON Kernkraft GmbH
184
Name and Position Held
Age
Principal Occupation
Dr. Henning Schulte-Noelle(2)(4) . . . . . . . . . . . . .
Member of the Supervisory Board
65
Chairman of the Supervisory Board of
Allianz SE; formerly Chairman of the Board
of Management of Allianz SE
Year First
Elected
1993
Supervisory Board Memberships/
Directorships:
Siemens AG, ThyssenKrupp AG
Dr. Theo Siegert(7) . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
60
Managing Director de Haen-Carstanjen &
Söhne
2007
Supervisory Board Memberships/
Directorships:
Deutsche Bank AG, ERGO AG, Merck
KGaA, E. Merck OHG, DKSH Holding Ltd.,
Hülsken Holding GmbH & Co. KG
Prof. Dr. Wilhelm Simson . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
69
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), Freudenberg KG
(5), Jungbunzlauer Holding AG(5), E. Merck
OHG(5), Hochtief AG
Gerhard Skupke(6) . . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
58
Chairman of the Central Works Council,
E.ON edis AG
2003
Supervisory Board Memberships/
Directorships:
E.ON edis AG
Dr. Georg Freiherr von Waldenfels . . . . . . . . . .
Member of the Supervisory Board
63
Former Minister of Finance of the State of
Bavaria; Attorney
2003
Supervisory Board Memberships/
Directorships:
CAPEO Consulting AG, Georgsmarienhütte
Holding GmbH, Rothenbaum Sport GmbH
Hans Wollitzer(6)(7) . . . . . . . . . . . . . . . . . . . . . . .
Member of the Supervisory Board
59
Chairman of the Central Works Council,
E.ON Energie AG
2007
Supervisory Board Memberships/
Directorships:
E.ON Energie AG, E.ON Bayern AG
*
(1)
(2)
(3)
(4)
Chairman of the respective Supervisory Board committee.
Member of E.ON AG’s Audit Committee.
Member of E.ON AG’s Executive Committee, which covers the functions of a remuneration committee.
Member of E.ON AG’s Finance and Investment Committee.
Member of E.ON AG’s Nomination Committee.
185
(5) Membership in comparable domestic or foreign supervisory body of a commercial enterprise.
(6) Elected by the employees.
(7) Seppel Kraus was a member of E.ON AG’s Supervisory Board until July 31, 2007. He was elected by the
employees. On August 1, 2007, Sven Bergelin, Chairman of the Central Works Council of E.ON Energie
AG, was publicly appointed as his successor. Dr. Gerhard Cromme was a member of E.ON AG’s
Supervisory Board until June 30, 2007. He was elected by the shareholders. On July 4, 2007, Dr. Theo
Siegert was publicly appointed as his successor. Ulrich Otte was a member of E.ON AG’s Supervisory
Board until December 31, 2006. He was elected by the employees and a member of E.ON AG’s Audit
Committee. On January 4, 2007, Hans Wollitzer, Chairman of the Central Works Council of E.ON Energie
AG, was publicly appointed as his successor. On March 6, 2007, Gabriele Gratz was elected as a new
member of E.ON AG’s Audit Committee, replacing Ulrich Otte. On July 1, 2007, Prof. Dr. Ulrich Lehner
was elected as a new member of E.ON AG’s Finance and Investment Committee, replacing Dr. Gerhard
Cromme, and also joined E.ON AG’s Nomination Committee.
The current members of the Supervisory Board are subject to reelection in 2008.
Board Of Management (Vorstand)
As of December 31, 2007, the Board of Management of E.ON consisted of six members (the total number is
determined by the Supervisory Board) who are appointed by the Supervisory Board in accordance with the Stock
Corporation Act.
Pursuant to E.ON’s Articles of Association, any two members of the Board of Management, or one member
of the Board of Management and the holder of a special power of attorney (Prokura), may bind E.ON. According
to E.ON’s Articles of Association, Prokura is granted by the Board of Management.
The Board of Management must report regularly to the Supervisory Board, in particular on proposed
business policy and strategy, on profitability, on the current business of E.ON and on business transactions that
may affect the profitability or liquidity of E.ON, as well as on any exceptional matters which may arise from
time to time. The Supervisory Board is also entitled to request special reports at any time.
The members of the Board of Management are appointed by the Supervisory Board for a maximum term of
five years. They may be re-appointed or have their term extended for additional five-year terms, subject to
certain limitations depending upon the age of the member. Under certain circumstances, such as a serious breach
of duty or a bona fide vote of no confidence by the shareholders at a shareholders’ meeting, a member of the
Board of Management may be removed by the Supervisory Board prior to the expiration of such term.
In 2006, E.ON introduced a new Board structure to prepare for an even stronger market focus and for the
Group’s future growth. In October 2006, the Supervisory Board of E.ON AG decided that the future Board of
Management will include not only the Chief Executive Officer (CEO), the Chief Financial Officer (CFO) and the
Chief Human Resources Officer but also a Chief Operating Officer (COO) and a Board member in charge of
Corporate Development/New Markets. The new Board of Management structure was effective as of April 1,
2007.
186
The members of the Board of Management, their respective ages and their positions and experience, each as
of December 31, 2007, as well as the year in which they were first appointed to the Board and the years in which
their terms expire, respectively, are as follows:
Name and Title
Age
Business Activities and Experience
Dr. Wulf H. Bernotat . . . . . . . . . . . . . . .
Chairman of the Board of Management
59
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
Year First
Appointed
Year Current
Term Expires
2003
2010
2003
2008
Supervisory Board Memberships/
Directorships:
E.ON Energie AG(1) (Chairman),
E.ON Ruhrgas AG(1) (Chairman),
Allianz SE, Metro AG, Bertelsmann
AG, E.ON Nordic AB(2)(3)
(Chairman), E.ON UK plc(2)(3)
(Chairman), E.ON US Investments
Corp.(2)(3) (Chairman), E.ON Sverige
AB(2)(3) (Chairman)
Dr. Burckhard Bergmann(4) . . . . . . . . . .
Member of the Board of Management
64
Upstream Business, Market
Management, Group Regulatory
Management; Chairman of the Board
of Management and Chief Executive
Officer of E.ON Ruhrgas AG
Supervisory Board Memberships/
Directorships:
Thüga AG(1) (Chairman), Allianz
Lebensversicherungs-AG, MAN
Ferrostaal AG, Jaeger
Beteiligungsgesellschaft mbH & Co.
KG (2) (Chairman),
Accumulatorenwerke Hoppecke Carl
Zoellner & Sohn GmbH(2), OAO
Gazprom(2), E.ON Ruhrgas E & P
GmbH(2)(3) (Chairman), North Stream
AG(2), E.ON Gastransport AG & Co.
KG(2)(3) (Chairman), E.ON UK
plc(2)(3), ZAO Gerosgaz(2)(3)
(Chairman; in alternation with a
representative of the foreign partner)
187
Name and Title
Age
Business Activities and Experience
Christoph Dänzer-Vanotti . . . . . . . . . . . .
Member of the Board of Management
52
Chief Human Resources Officer;
Labor Relations, Personnel,
Infrastructure and Services,
Procurement, Organization; formerly
Member of the Board of Management
of E.ON Ruhrgas AG
Year First
Appointed
Year Current
Term Expires
2006
2009
2006
2009
2006
2009
2004
2008
Supervisory Board Memberships/
Directorships:
E.ON Nordic AB(2)(3),
E.ON Sverige AB(2)(3)
Lutz Feldmann . . . . . . . . . . . . . . . . . . . .
Member of the Board of Management
50
Corporate Development/New
Markets, M&A, Legal Affairs;
formerly Group Vice President
Marketing of BP p.l.c.
Supervisory Board Memberships/
Directorships:
E.ON Energie AG(1)
Dr. Marcus Schenck . . . . . . . . . . . . . . . .
Member of the Board of Management
41
Chief Financial Officer; Finance,
Accounting, Taxes, IT; formerly
Managing Director and Partner of
Goldman, Sachs & Co. oHG
Supervisory Board Memberships/
Directorships:
E.ON Ruhrgas AG(1), E.ON IS
GmbH(3), NFK Finanzcontor
GmbH(3), E.ON Risk Consulting
GmbH(3), E.ON Audit Services
GmbH(3)
Dr. Johannes Teyssen(5) . . . . . . . . . . . . .
Member of the Board of Management
47
Chief Operating Officer, Downstream
Business, Market Management,
Generation, Marketing, Group
Regulatory Management
Supervisory Board Memberships/
Directorships:
E.ON Energie AG(1), E.ON Ruhrgas
AG(1), Salzgitter AG, E.ON Nordic
AB(2)(3), E.ON Sverige AB(2)(3), E.ON
UK plc.(2)(3)
(1) Group mandate.
(2) Membership in comparable domestic or foreign supervisory body of a commercial enterprise.
(3) Other Group mandate (membership in comparable domestic or foreign supervisory body of a commercial
enterprise).
(4) On February 29, 2008, Dr. Burckhard Bergmann retired from the Board.
(5) Dr. Johannes Teyssen became Chief Operating Officer as of April 1, 2007.
On April 1, 2007, Dr. Hans Michael Gaul retired from the Board of Management.
The members of the Supervisory Board and Board of Management hold, in aggregate, less than 1 percent of
E.ON’s outstanding Ordinary Shares.
188
DESCRIPTION OF THE NOTES
The $2,000,000,000 5.80% senior notes due 2018 (the “2018 Notes”) and the $1,000,000,000 6.65% senior
notes due 2038 (the “2038 Notes” and, together with the 2018 Notes, the “Notes”) will be issued under a fiscal
and paying agency agreement (“the Fiscal and Paying Agency Agreement”) to be dated as of April 22, 2008
between E.ON International Finance B.V. (the “Issuer”), E.ON AG (the “Guarantor”) and HSBC Bank USA,
N.A. as fiscal agent, principal paying agent, transfer agent and registrar (the “Fiscal Agent”). The following
summaries of certain provisions of the Notes and the Fiscal and Paying Agency Agreement do not purport to be
complete and are subject to, and are qualified in their entirety by reference to, all the provisions of the Notes and
the Fiscal and Paying Agency Agreement, including the definitions of certain terms contained therein.
General
The 2018 Notes will be initially limited to $2,000,000,000 aggregate principal amount and will mature on
April 30, 2018. The 2038 Notes will be initially limited to $1,000,000,000 aggregate principal amount and will
mature on April 30, 2038. The Notes will be the direct, unconditional, unsecured and unsubordinated general
obligations of the Issuer. The Notes will rank pari passu among themselves, without any preference of one over
the other by reason of priority of date of issue or otherwise, and at least equally with all other unsecured and
unsubordinated general obligations of the Issuer from time to time outstanding. The Notes will bear interest at the
rate per annum shown on the front cover of this offering memorandum from April 22, 2008, payable
semiannually in arrears on October 30 and April 30 of each year, commencing on October 30, 2008, to the
Holders of record on the October 15 and April 15, as the case may be, immediately preceding such interest
payment date, whether or not such day is a Business Day. Interest will be calculated on the basis of a 360-day
year consisting of twelve 30-day months. The Notes will be repaid at maturity at a price of 100% of the principal
amount thereof. The Notes may be redeemed at any time prior to maturity in the circumstances described under
“— Optional Redemption” and “— Optional Tax Redemption.” The Notes will be issued in denominations of
$1,000 and integral multiples of $1,000 in excess thereof. The Notes do not provide for any sinking fund.
The term “Business Day” means any day other than a day on which commercial banks or foreign exchange
markets are permitted or required to be closed in New York City, London, Frankfurt am Main or Amsterdam. If
the date of maturity of interest on or principal of the Notes or the date fixed for redemption of any Note is not a
Business Day, then payment of interest or principal need not be made on such date, but may be made on the next
succeeding Business Day with the same force and effect as if made on the date of maturity or the date fixed for
redemption, and no interest shall accrue for the period after such date.
Guarantees
Each Note will benefit from an unconditional and irrevocable guarantee (each a “Guarantee” and,
collectively, the “Guarantees”) by the Guarantor. Under the Guarantees, the Guarantor will guarantee to each
Holder the due and punctual payment of any principal, accrued and unpaid interest (and all Additional Amounts,
if any) due under the Notes in accordance with the Fiscal and Paying Agency Agreement, and any Additional
Amounts in respect of such Guarantees. The Guarantees will be the direct, unconditional, unsecured and
unsubordinated general obligations of the Guarantor. The Guarantees will rank pari passu among themselves,
without any preference of one over the other by reason of priority of date of issue or otherwise, and at least
equally with all other unsecured and unsubordinated general obligations of the Guarantor from time to time
outstanding.
Additional Notes
The Notes will be issued in the initial aggregate principal amount set forth above. The Issuer may, from time
to time, without notice to or the consent of the Holders, create and issue, pursuant to the Fiscal and Paying
Agency Agreement and in accordance with applicable laws and regulations, additional notes (the “Additional
Notes”) maturing on the same maturity date as the other Notes of that series (the 2018 Notes or the 2038
189
Notes) and having the same terms and conditions under the Fiscal and Paying Agency Agreement (including with
respect to the Guarantor and the Guarantees) as the previously outstanding Notes of that series in all respects (or
in all respects except for the issue date and the amount and the date of the first payment of interest thereon) so
that such Additional Notes shall be consolidated and form a single series with the previously outstanding Notes
of that series. Additional Notes, if any, will be issued under a separate offering memorandum or a supplement to
this offering memorandum.
Optional Redemption
The Issuer may, at its option, redeem the Notes as a whole or in part at any time upon not less than 30 nor
more than 60 days’ prior notice, at a redemption price equal to the greater of:
•
100% of the aggregate principal amount of the Notes to be redeemed; and
•
as determined by the Independent Investment Banker, the sum of the present values of the remaining
scheduled payments of principal and interest on the Notes to be redeemed (not including any portion of
such payments of interest accrued to the date of redemption) discounted to the redemption date on a
semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate
plus 35 basis points;
plus, in each case described above, accrued and unpaid interest on the principal amount being redeemed to
(but excluding) such redemption date.
“Treasury Rate” means, with respect to any redemption date:
•
the yield, under the heading which represents the average for the immediately preceding week,
appearing in the most recently published statistical release designated “H.15(519)” or any successor
publication which is published weekly by the Board of Governors of the Federal Reserve System and
which establishes yields on actively traded U.S. treasury securities adjusted to constant maturity under
the caption “Treasury constant maturities — Nominal”, for the maturity corresponding to the
Comparable Treasury Issue (if no maturity is within three months before or after the remaining term of
the Notes, yields for the two published maturities most closely corresponding to the Comparable
Treasury Issue will be determined and the Treasury Rate will be interpolated or extrapolated from such
yields on a straight line basis, rounding to the nearest month); or
•
if such release (or any successor release) is not published during the week preceding the calculation date
or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity
of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue
(expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such
redemption date.
The Treasury Rate will be calculated on the third Business Day preceding such redemption date.
“Comparable Treasury Issue” means the U.S. Treasury security (not inflation-indexed) selected by an
Independent Investment Banker as having a maturity comparable to the remaining term of the Notes to be
redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in
pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Notes.
“Comparable Treasury Price” means (i) the average of five Reference Treasury Dealer Quotations for such
redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (ii) if the
Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average
of all such quotations.
“Independent Investment Banker” means Banc of America Securities LLC, Deutsche Bank Securities Inc.,
Goldman, Sachs & Co. or J.P. Morgan Securities Inc., as specified by the Issuer, or, if these firms are unwilling
or unable to select the Comparable Treasury Issue, an independent investment banking institution of national
standing in the United States appointed by the Issuer.
190
“Reference Treasury Dealer means (i) Banc of America Securities LLC, Deutsche Bank Securities Inc.,
Goldman, Sachs & Co. and J.P. Morgan Securities Inc. and their respective successors, provided, however, that if
any of the foregoing shall cease to be a primary U.S. government securities dealer in The City of New York (a
“Primary Treasury Dealer”), the Issuer will substitute therefor another Primary Treasury Dealer and (ii) any three
other Primary Treasury Dealers selected by the Issuer after consultation with the Independent Investment Banker.
“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any
redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices
for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in
writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third Business Day
preceding such redemption date.
Unless the Issuer (and/or the Guarantor) defaults on payment of the redemption price, from and after the
redemption date interest will cease to accrue on the Notes or portions thereof called for redemption. On the
redemption date, the Issuer will deposit with the Fiscal Agent, or with one or more paying agents (or, if the Issuer
is acting as its own paying agent, set aside, segregate and hold in trust as provided in the Fiscal and Paying
Agency Agreement) money sufficient to pay the redemption price of and accrued interest on the Notes to be
redeemed on such date. If fewer than all of the Notes are to be redeemed, the Fiscal Agent will select, not more
than 60 days prior to the redemption date, the particular Notes or portions thereof for redemption from the
outstanding Notes not previously called for redemption, on a pro rata basis or by such method as the Fiscal Agent
deems fair and appropriate.
Optional Tax Redemption
The Notes may be redeemed at any time, at the Issuer’s (or, if applicable, the Guarantor’s) option, as a
whole, but not in part, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to
100% of the principal amount of the Notes then outstanding plus accrued and unpaid interest on the principal
amount being redeemed (and all Additional Amounts, if any) to (but excluding) the redemption date, if (i) as a
result of any change in, or amendment to, the laws, treaties, regulations or rulings of a Relevant Taxing
Jurisdiction or in the interpretation, application or administration of any such laws, treaties, regulations or rulings
(including a holding, judgment or order by a court of competent jurisdiction) which becomes effective on or after
the issue date (any such change or amendment, a “Change in Tax Law”), the Issuer or (if a payment were then
due under the Guarantee, the Guarantor) would be required to pay Additional Amounts and (ii) such obligation
cannot be avoided by the Issuer (or the Guarantor) taking reasonable measures available to it. Additional
amounts are payable by the Issuer under the circumstances described below under “—Additional amounts”.
Prior to the publication or, where relevant, mailing of any notice of redemption pursuant to the foregoing,
the Issuer or the Guarantor will deliver to the Fiscal Agent an opinion of independent tax counsel of recognized
standing to the effect that the Issuer or the Guarantor is or would be obligated to pay such Additional Amounts as
a result of a Change in Tax Law.
No notice of redemption may be given earlier than 90 days prior to the earliest date on which the Issuer or
the Guarantor would be obligated to pay Additional Amounts if a payment in respect of the Notes were then due.
The foregoing provisions shall apply mutatis mutandis to any successor person, after such successor person
becomes a party to the Fiscal and Paying Agency Agreement.
Holders’ Option to Repayment upon a Change in Control
In the event that (i) a Change of Control (as defined below) occurs, and, within the Change of Control
Period (as defined below), a Ratings Downgrade (as defined below) in respect of that Change of Control occurs
or is announced (an “Early Redemption Event”):
(a) any Holder may, by submitting a redemption notice (the “Early Redemption Notice”), demand from the
Issuer repayment as of the Effective Date (as defined under subparagraph (b)(2) below) of any or all of its
Notes which have not otherwise been declared due for early redemption, at their principal amount plus
191
interest accrued until (but excluding) the Effective Date (and all Additional Amounts, if any). Each Early
Redemption Notice must be received by the Fiscal Agent no less than 30 days prior to the Effective Date;
and
(b) the Issuer will (1) immediately after becoming aware of the Early Redemption Event, provide written notice
thereof to the Holders, and (2) determine and provide written notice of the effective date for the purposes of
early repayment (the “Effective Date”). The Effective Date must be a Business Day not less than 60 and not
more than 90 days after the giving of the notice regarding the Early Redemption Event pursuant to
subparagraph (b)(1).
Any Early Redemption Notice shall be made in writing in English and shall be delivered by hand or by
registered mail to the Fiscal Agent not less than ten (10) days prior to the Effective Date at its specified office.
The Early Redemption Notice must be accompanied by evidence showing that the relevant Holder is the Holder
of the relevant Note(s) at the time the Early Redemption Notice is delivered. Such evidence may be provided in
the form of a certificate issued by any custodian or in any other suitable manner. Early Redemption Notices shall
be irrevocable.
A “Change of Control“ shall occur if any person or group, acting in concert, gains control over the
Guarantor. “Control” for these purposes means any direct or indirect legal or beneficial ownership or any direct
or indirect legal or beneficial entitlement (as described in Section 22 of the German Securities Trading Act
(Wertpapierhandelsgesetz)) of, in the aggregate, more than 50% of the voting shares of the Guarantor.
The “Change of Control Period“ shall commence on the date of the Change of Control announcement, but
not later than on the date of the Change of Control, and shall end 180 days after the Change of Control. “Change
of Control Announcement” for these purposes means any public announcement or statement by the Guarantor or
any actual or potential bidder relating to a Change of Control.
A “Ratings Downgrade” shall occur if a solicited credit rating for the Guarantor’s long-term unsecured debt
falls below investment grade or all Rating Agencies (as defined below) cease to assign (other than temporarily) a
credit rating to the Guarantor. A credit rating below investment grade shall mean, in relation to Standard &
Poor’s Rating Services, a rating of BB+ or below and, in relation to Moody’s Investor Services Inc., a rating of
Ba1 or below and, where another rating agency has been designated by the Guarantor, a comparable rating.
“Rating Agencies“ shall mean each of Standard & Poor’s Ratings Services, a Division of The McGraw Hill
Companies, Inc., or Moody’s Investors Services Inc., or any other rating agency designated by the Guarantor.
Modifications and Amendment
The Issuer, the Guarantor and the Fiscal Agent may, with the consent of the Holders of not less than a
majority in aggregate principal amount of the Notes then outstanding, evidenced as provided in the Fiscal and
Paying Agency Agreement, execute agreements adding any provisions to or changing in any manner or
eliminating any of the provisions of the Fiscal and Paying Agency Agreement or of any supplemental agreement
or modifying in any manner the rights of the Holders under the Notes or the Guarantees; provided that no such
agreement shall (a) change the maturity of the principal of any Note, or reduce the principal amount thereof, or
reduce the rate or extend the time of payment of any installment of interest thereon, or change the place or
currency of payment of principal of, or interest on, any Note, or change the Issuer’s or the Guarantor’s obligation
to pay Additional Amounts, impair or affect the right of any Holder to institute suit for the enforcement of any
such payment on or after the due date thereof (or in the case of redemption, on or after the redemption date) or
change in any manner adverse to the interests of the Holders the terms and provisions of the Guarantees in
respect of the due and punctual payment of principal amount of the Notes then outstanding plus accrued and
unpaid interest (and all Additional Amounts, if any) without the consent of the Holder of each Note so affected;
or (b) reduce the aforesaid percentage of Notes, the consent of the Holders of which is required for any such
agreement, without the consent of the Holders of the Notes then outstanding.
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The Issuer, the Guarantor and the Fiscal Agent may, without the consent of the Holders, from time to time
and at any time, enter into a fiscal and paying agency agreement or fiscal and paying agency agreements
supplemental thereto for one or more of the following purposes:
• to convey, transfer, assign, mortgage or pledge to the Fiscal Agent or another person as security for the
Notes any property or assets;
• to evidence the succession of another person to the Issuer or the Guarantor, or successive successions,
and the assumption by the successor person of the covenants, agreements and obligations of the Issuer
or the Guarantor, pursuant to the Fiscal and Paying Agency Agreement;
• to evidence and provide for the acceptance of appointment of a successor or successors to the Fiscal
Agent in any of its capacities;
•
•
•
•
to add to the covenants of the Issuer or the Guarantor, such further covenants, restrictions, conditions or
provisions as the Issuer or the Guarantor, as the case may be, shall reasonably consider to be for the
protection of the Holders, and to make the occurrence, or the occurrence and continuance, of a default in
any such additional covenants, restrictions, conditions or provisions an Event of Default under the Notes
permitting the enforcement of all or any of the several remedies provided in the applicable fiscal and
paying agency agreement; provided that, in respect of any such additional covenant, restriction,
condition or provision, such supplemental fiscal and paying agency agreement may provide for a
particular period of grace after default (which may be shorter or longer than that allowed in the case of
other defaults) or may provide for an immediate enforcement upon such an Event of Default or may
limit the right of Holders of a majority in aggregate principal amount of the Notes to waive such an
Event of Default;
to modify the restrictions on, and procedures for, resale and other transfers of the Notes pursuant to law,
regulation or practice relating to the resale or transfer of restricted securities generally;
to cure any ambiguity or to correct or supplement any provision contained in the Fiscal and Paying
Agency Agreement, the Notes or the Guarantees, or in any supplemental agreement, which may be
defective or inconsistent with any other provision contained therein or in any supplemental agreement or
to make such other provision in regard to matters or questions arising under the Fiscal and Paying
Agency Agreement or under any supplemental agreement as the Issuer may deem necessary or desirable
and which will not adversely affect the interests of the Holders to which such provision relates in any
material respect; and
to “reopen” the Notes of any series and create and issue additional Notes having identical terms and
conditions as the Notes of such series (or in all respects except for the issue date, issue price and first
interest payment date) so that the additional Notes are consolidated and form a single series with the
outstanding Notes.
Negative Pledge
So long as any of the Notes remains outstanding neither the Issuer nor the Guarantor will create or permit to
subsist any mortgage, charge, pledge, lien or other encumbrance upon any or all of its present or future assets to
secure for the benefit of the holders of any present or future Bond Issue the repayment of such present or future
Bond Issue without at the same time, or prior thereto, securing such Notes or the Guarantees, as the case may be,
equally and rateably therewith. “Bond Issue” means any indebtedness of the Issuer or the Guarantor which is, in
the form of, or is represented by, any bond, security, certificate or other instrument which is or is capable of
being listed, quoted or traded on any stock exchange or in any securities market (including any over-the-counter
market) and any guarantee or other indemnity in respect of such indebtedness.
Events of Default
The occurrence and continuance of one or more of the following events will constitute an “Event of
Default” under the Fiscal and Paying Agency Agreement and the Notes:
(a) payment default — the Issuer fails to pay principal or interest or Additional Amounts within 30 days from
the relevant due date; or
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(b) breach of other obligations — the Issuer defaults in the performance or observance of any of its other
obligations under or in respect of the Notes or the Fiscal and Paying Agency Agreement and such default
remains unremedied for 90 days after there has been given a written notice to the Issuer by the Fiscal Agent
or to the Issuer and the Fiscal Agent by the Holders of at least 25% in principal amount of the outstanding
Notes affected thereby, specifying such default or breach and requiring it to be remedied and stating that
such notice is a “Notice of Default” under the Notes; or
(c) cross-default — any obligation for the payment or repayment of money borrowed having an aggregate
outstanding principal amount of at least €50,000,000 (or its equivalent in any other currency) of the Issuer
or the Guarantor is not paid within 30 days after the due date or (as the case may be) within any originally
applicable longer grace period relating to such obligation or becomes due and payable prior to its stated
maturity by reason of default and is not paid within 30 days, or any guarantee or indemnity of any obligation
for the payment or repayment of money borrowed having an aggregate outstanding principal amount of at
least €50,000,000 (or its equivalent in any other currency) given by the Issuer or the Guarantor is not
honored within 30 days after the due date unless, in either such case, proceedings are brought by the Issuer
or the Guarantor, in a court of competent jurisdiction, to bona fide challenge its obligation to make payment
or repayment of any such amount; or
(d) financial distress — the Issuer or the Guarantor announces its inability to meet its financial obligations or
ceases its payments; or
(e) bankruptcy or insolvency — a court opens bankruptcy or other insolvency proceedings against the Issuer or
the Guarantor, or the Issuer or the Guarantor applies for or institutes such proceedings or offers or makes an
arrangement (allgemeine Schuldenbereinigung) for the benefit of its creditors generally, or the Issuer applies
for a “surseance van betaling” (within the meaning of the Statute of Bankruptcy of The Netherlands), or a
third party applies for insolvency proceedings against the Guarantor and such proceedings are not
discharged or stayed within 60 days, or
(f)
liquidation — the Issuer or the Guarantor goes into liquidation unless this is done in connection with a
merger or other form of combination with another person and such person assumes all obligations
contracted by the Issuer or the Guarantor, as the case may be, under the Notes or the Guarantees; or
(g) impossibility due to government action — any governmental order, decree or enactment shall be made in or
by The Netherlands or in or by Germany whereby the Issuer or the Guarantor is prevented from observing
and performing in full its obligations as set forth in the terms and conditions of the Notes and the
Guarantees, respectively, and this situation is not cured within 90 days, or
(h) invalidity of the Guarantees — the Guarantees cease to be valid and legally binding for any reason
whatsoever.
If an Event of Default occurs and is continuing, then in each and every case, unless the principal of all of the
Notes shall already have become due and payable (in which case no action is required for the acceleration of the
Notes), the Holders of not less than 25% in aggregate principal amount of Notes then outstanding, by written
notice to the Issuer and the Fiscal Agent as provided in the Fiscal and Paying Agency Agreement, may declare
the entire principal of all the Notes, and the interest accrued thereon, to be due and payable immediately. Under
certain circumstances, the Holders of a majority in aggregate principal amount of the Notes then outstanding
may, by written notice to the Issuer and the Fiscal Agent as provided in the Fiscal and Paying Agency
Agreement, waive all defaults and rescind and annul such declaration and its consequences, but no such waiver
or rescission and annulment shall extend to or shall affect any subsequent default or shall impair any right
consequent thereon.
Substitution of Issuer; Consolidation, Merger and Sale of Assets
In all cases subject to the provisions described above under “— Holders’ Option to Repayment upon a
Change in Control,” (i) the Issuer or the Guarantor, without the consent of the Holders of any of the Notes, may
consolidate with, or merge into, or sell, transfer, lease or convey all or substantially all of their respective assets
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to, any corporation and (ii) the Issuer may at any time substitute for the Issuer either the Guarantor or any
Affiliate (as defined below) of the Guarantor as principal debtor under the Notes; provided that:
(a) any successor company (other than an Affiliate of the Guarantor) shall expressly assume the Issuer’s or the
Guarantor’s respective obligations under the Notes or the Guarantees, as the case may be, and the Fiscal and
Paying Agency Agreement;
(b) the Issuer is not in default of any payments due under the Notes; and
(c) written notice of such transaction shall be promptly provided to the Holders.
For purposes of the foregoing, “Affiliate” shall mean any affiliated company (verbundenes Unternehmen)
within the meaning of Section 15 German Stock Corporation Act (Aktiengesetz).
Upon the effectiveness of any substitution, all of the foregoing provisions will apply mutatis mutandis, and
references elsewhere herein to the Issuer or the Guarantor will, where the context so requires, be deemed to be or
include references, to any successor company.
For as long as any Notes are outstanding, if E.ON International Finance B.V. ceases to have the benefit of
exemptive relief from Dutch banking licence requirements available to it under the Dutch Financial Markets
Supervision Act (Wet op het financieel toezicht, including its subordinate regulations and decrees, the “FMSA”),
E.ON International Finance B.V. will immediately be substituted in accordance with the foregoing conditions
with a successor company, which is not subject to Dutch banking regulations or which has the benefit of the
appropriate exemptive relief.
Discharge and Defeasance
Discharge of Fiscal and Paying Agency Agreement
The Fiscal and Paying Agency Agreement provides that the Issuer and the Guarantor will be discharged
from any and all obligations in respect of the Fiscal and Paying Agency Agreement (except for certain
obligations to register the transfer of or exchange Notes, replace stolen, lost or mutilated Notes, make payments
of principal and interest and maintain paying agencies) if:
• the Issuer has paid or caused to be paid in full the principal of and interest on all Notes outstanding
thereunder;
• the Issuer shall have delivered to the Fiscal Agent for cancellation all Notes outstanding theretofore
authenticated; or
• all Notes not theretofore delivered to the Fiscal Agent for cancellation (i) have become due and payable;
(ii) will become due and payable in accordance with their terms within one year or (iii) are to be, or
have been, called for redemption as described under “— Optional Redemption” or “— Optional Tax
Redemption” within one year under arrangements satisfactory to the Fiscal Agent for the giving of
notice of redemption, and, in any such case, the Issuer shall have irrevocably deposited with the Fiscal
Agent as trust funds in irrevocable trust, specifically pledged as security for, and dedicated solely to, the
benefit of the Holders of such Notes, (a) cash in U.S. dollars in an amount, or (b) U.S. Government
Obligations (as defined below) which through the payment of interest thereon and principal thereof in
accordance with their terms will provide not later than the due date of any payment, cash in U.S. dollars
in an amount, or (c) any combination of (a) and (b), sufficient to pay all the principal of, and interest
(and Additional Amounts, if any) on, all such Notes not theretofore delivered to the Fiscal Agent for
cancellation on the dates such payments are due in accordance with the terms of the Notes and all other
amounts payable under the Fiscal and Paying Agency Agreement by the Issuer.
“U.S. Government Obligations” means securities which are (i) direct obligations of the U.S. government or
(ii) obligations of a person controlled or supervised by and acting as an agency or instrumentality of the U.S.
government, the payment of which is unconditionally guaranteed by the U.S. government, which, in either case,
are full faith and credit obligations of the U.S. government payable in U.S. dollars and are not callable or
redeemable at the option of the issuer thereof and shall also include a depositary receipt issued by a bank or trust
company as custodian with respect to any such U.S. Government Obligation or a specific payment of interest on
or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a
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depositary receipt; provided that (except as required by law) such custodian is not authorized to make any
deduction from the amount payable to the holder of such depositary receipt from any amount received by the
custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the
U.S. Government Obligation evidenced by such depositary receipt.
Covenant Defeasance
The Fiscal and Paying Agency Agreement also provides that the Issuer and the Guarantor need not comply
with certain covenants of the Fiscal and Paying Agency Agreement (including those described under “—
Negative Pledge”), and the Guarantor shall be released from its obligations under the Guarantees, if:
•
the Issuer (or the Guarantor) irrevocably deposits with the Fiscal Agent as trust funds in irrevocable
trust, specifically pledged as security for, and dedicated solely to, the benefit of the Holders of such
Notes, (i) cash in U.S. dollars in an amount, or (ii) U.S. Government Obligations which through the
payment of interest thereon and principal thereof in accordance with their terms will provide not later
than the due date of any payment cash in U.S. dollars in an amount, or (iii) any combination of (i) and
(ii), sufficient to pay all the principal of, and interest on, the Notes then outstanding on the dates such
payments are due in accordance with the terms of the Notes;
•
certain Events of Default, or events which with notice or lapse of time or both would become such an
Event of Default, shall not have occurred and be continuing on the date of such deposit;
•
the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an opinion of tax counsel of
recognized standing with respect to U.S. federal income tax matters to the effect that the beneficial
owners of the Notes will not recognize income, gain or loss for U.S. federal income tax purposes as a
result of the exercise of such Covenant Defeasance and will be subject to U.S. federal income tax on the
same amounts, in the same manner and at the same times as would be the case if such Covenant
Defeasance had not occurred;
•
the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an opinion of tax counsel of
recognized standing in its jurisdiction of incorporation to the effect that such deposit and related
Covenant Defeasance will not cause the Holders of Notes, other than Holders who are or who are
deemed to be residents of such jurisdiction of incorporation or use or hold or are deemed to use or hold
their Notes in carrying on a business in such jurisdiction of incorporation, to recognize income, gain or
loss for income tax purposes in such jurisdiction of incorporation, and to the effect that payments out of
the trust fund will be free and exempt from any and all withholding and other income taxes of whatever
nature of such jurisdiction of incorporation or political subdivision thereof or therein having power to
tax, except in the case of Notes beneficially owned (i) by a person who is or is deemed to be a resident
of such jurisdiction of incorporation or (ii) by a person who uses or holds or is deemed to use or hold
such Notes in carrying on a business in such jurisdiction of incorporation; and
•
the Issuer, or the Guarantor, as the case may be, delivers to the Fiscal Agent an officers’ certificate and
an opinion of legal counsel of recognized standing, each stating that all conditions precedent provided
for relating to such Covenant Defeasance have been complied with.
The effecting of these arrangements is also known as “Covenant Defeasance”.
Additional Amounts
The Issuer (and/or the Guarantor) will make all payments in respect of the Notes without withholding or
deduction for or on account of any present or future taxes or duties of whatever nature imposed or levied by way
of withholding or deduction at source by or on behalf of any jurisdiction in which the Issuer or Guarantor is
incorporated, organized, or otherwise tax resident or any political subdivision or any authority thereof or therein
having power to tax (the “Relevant Taxing Jurisdiction”) unless such withholding or deduction is required by
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law. In such event, the Issuer or, as the case may be, the Guarantor will pay to the Holders such additional
amounts (the “Additional Amounts”) as shall be necessary in order that the net amounts received by the Holders,
after such withholding or deduction, shall equal the respective amounts of principal and interest which would
otherwise have been receivable in the absence of such withholding or deduction; except that no such Additional
Amounts shall be payable on account of any taxes or duties which:
(a) are payable by any person acting as custodian bank or collecting agent on behalf of a Holder, or otherwise in
any manner which does not constitute a deduction or withholding by the Issuer from payment of principal or
interest made by it, or
(b) are payable by reason of the Holder or beneficial owner having, or having had, some personal or business
connection with such Relevant Taxing Jurisdiction and not merely by reason of the fact that payments in
respect of the Notes or the Guarantees are, or for purposes of taxation are deemed to be, derived from
sources in, or are secured in the Relevant Taxing Jurisdiction, or
(c) are imposed or withheld by reason of the failure of the Holder or beneficial owner to provide certification,
information, documents or other evidence concerning the nationality, residence, or identity of the Holder
and beneficial owner or to make any valid or timely declaration or similar claim or satisfy any other
reporting requirements relating to such matters, whether required or imposed by statute, treaty, regulation or
administrative practice, as a precondition to exemption from, or a reduction in the rate of withholding or
deduction of such taxes, or
(d) consist of any estate, inheritance, gift, sales, excise, transfer, personal property or similar taxes, or
(e) are imposed on or with respect to any payment by the Issuer or Guarantor to the registered Holder if such
Holder is a fiduciary or partnership or any person other than the sole beneficial owner of such payment to
the extent that taxes would not have been imposed on such payment had such registered Holder been the
sole beneficial owner of such Note, or
(f)
are deducted or withheld pursuant to (i) any European Union directive or regulation concerning the taxation
of interest income, or (ii) any international treaty or understanding relating to such taxation and to which the
Relevant Taxing Jurisdiction or the European Union is a party, or (iii) any provision of law implementing,
or complying with, or introduced to conform with, such directive, regulation, treaty or understanding, or
(g) are payable by reason of a change in law or practice that becomes effective more than 30 days after the
relevant payment of principal or interest becomes due, or is duly provided for and written notice thereof is
provided to the Holders, whichever occurs later, or
(h) are payable because any Note was presented to a particular paying agent for payment if the Note could have
been presented to another paying agent without any such withholding or deduction, or
(i)
are payable for any combination of (a) through (h) above.
References to principal or interest in respect of the Notes shall be deemed to include any Additional
Amounts, which may be payable as set forth in the Fiscal and Paying Agency Agreement.
Indemnification of Judgment Currency
To the fullest extent permitted by applicable law, the Issuer and the Guarantor will indemnify each Holder
against any loss incurred by such Holder as a result of any judgment or order being given or made for any
amount due under any Note or Guarantee and such judgment or order being expressed and paid in a currency (the
“Judgment Currency”), which is other than U.S. dollars and as a result of any variation as between (i) the rate of
exchange at which the U.S. dollar is converted into the Judgment Currency for the purposes of such judgment or
order and (ii) the spot rate of exchange in The City of New York at which the Holder on the date of payment of
such judgment is able to purchase U.S. dollars with the amount of the Judgment Currency actually received by
such Holder. This indemnification will constitute a separate and independent obligation of the Issuer or the
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Guarantor, as the case may be, and will continue in full force and effect notwithstanding any such judgment or
order as aforesaid. The term “spot rate of exchange” includes any premiums and costs of exchange payable in
connection with the purchase of, or conversion into, U.S. dollars.
Governing Law; Submission to Jurisdiction
The Fiscal and Paying Agency Agreement, the Notes and the Guarantees will be governed by and construed
in accordance with the laws of the State of New York.
The Issuer and the Guarantor have irrevocably submitted to the non-exclusive jurisdiction of the courts of
any U.S. state or federal court in the Borough of Manhattan in The City of New York, New York with respect to
any legal suit, action or proceeding arising out of or based upon the Fiscal and Paying Agency Agreement, the
Notes or the Guarantees.
Regarding the Fiscal Agent, Paying Agent, Transfer Agent and Registrar
In acting under the Fiscal and Paying Agency Agreement, and in connection with the Notes and the
Guarantees, the Fiscal Agent, paying agent, any transfer agent and registrar, and any additional or successor
fiscal agent, transfer agents, paying agents or registrars, are acting solely as agents of the Issuer and the
Guarantor and do not assume any obligation towards or relationship of agency or trust for or with the owners or
Holders, except that any funds held by any paying agent for payment of principal of or interest on the Notes shall
be held in trust by it for the persons entitled thereto and applied as set forth in the Fiscal and Paying Agency
Agreement and in the Notes, but need not be segregated from other funds held by it except as required by law.
For a description of the duties and the immunities and rights of any Fiscal Agent, paying agent, transfer agent or
registrar under the Fiscal and Paying Agency Agreement, reference is made to the Fiscal and Paying Agency
Agreement, and the obligations of any Fiscal Agent, paying agent, transfer agent and registrar to the Holder are
subject to such immunities and rights.
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BOOK-ENTRY; DELIVERY AND FORM
Summary of Provisions Relating to Notes in Global Form
The certificates representing the Notes (and the Guarantees) will be issued in fully registered form without
interest coupons. The Notes will be represented by Book-Entry Interests (as defined below) and are being offered
and sold only (i) to Qualified Institutional Buyers, or QIBs, in reliance on Rule 144A under the Securities Act
(the “Rule 144A Notes”) or (ii) to persons other than U.S. persons (within the meaning of Regulation S under the
Securities Act) in offshore transactions in reliance on Regulation S (the “Regulation S Notes”). The Regulation S
Notes will initially be represented by one or more permanent Regulation S global notes in definitive, fully
registered form without interest coupons (the “Regulation S Global Notes”), and will be deposited with the Fiscal
Agent as custodian for, and registered in the name of a nominee of, DTC for the accounts of its participants,
including Euroclear and Clearstream. Prior to the 40th day after the later of the commencement of the offering of
the Notes and the date of the original issue of the Notes, any resale or other transfer of beneficial interests in a
Regulation S Global Note (“Regulation S Book-Entry Interests”) or a Rule 144A Global Note as defined below
(“Rule 144A Book-Entry Interests” and, together with the Regulation S Book-Entry Interests, the “Book-Entry
Interests”) to U.S. persons shall not be permitted unless such resale or transfer is made pursuant to Rule 144A or
Regulation S and in accordance with the certification requirements described below.
The Rule 144A Notes will be represented by one or more permanent Rule 144A global notes in definitive,
fully registered form without interest coupons (the Rule 144A Global Notes and, together with the Regulation S
Global Notes, the “Global Notes”), with such appropriate insertions, omissions, substitutions and other variations
as are required or permitted by the Fiscal and Paying Agency Agreement and such legends as may be applicable
thereto, and will be deposited with the Fiscal Agent as custodian for, and registered in the name of DTC or a
nominee of DTC duly executed by the Issuer and authenticated by the Fiscal Agent as provided in the Fiscal and
Paying Agency Agreement. Rule 144A Book-Entry Interests may be transferred to a person who takes delivery in
the form of Regulation S Book-Entry Interests only upon receipt by the Fiscal Agent of written certifications
from the transferor (in the form or forms provided in the Fiscal and Paying Agency Agreement) to the effect that
such transfer is being made to a person other than a U.S. person in an offshore transaction in reliance on
Regulation S under the Securities Act and pursuant to the transfer restrictions related to a Rule 144A Global Note
as described in this offering memorandum. Regulation S Book-Entry Interests may be transferred to a person
who takes delivery in the form of Rule 144A Book-Entry Interests only if such transfer occurs at least 40 days
after the later of the commencement of the offering of the Notes and the closing date and is made pursuant to
Rule 144A and, in addition, only upon receipt by the Fiscal Agent of written certifications from the transferor (in
the form or forms provided in the Fiscal and Paying Agency Agreement) to the effect that such transfer is being
made to a person who the transferor reasonably believes is a QIB within the meaning of Rule 144A in a
transaction meeting the requirements of Rule 144A and in accordance with all applicable securities laws of the
states of the United States and other jurisdictions.
Each Global Note (and any Notes issued in exchange therefor) will be subject to certain restrictions on
transfer set forth therein described under “Transfer Restrictions.” Except in the limited circumstances described
below under “— Summary of Provisions Relating to Certificated Notes”, owners of Book-Entry Interests will not
be entitled to receive physical delivery of certificated Notes.
Ownership of Book-Entry Interests will be limited to persons who have accounts with DTC, or participants,
or persons who hold interests through participants. Ownership of Book-Entry Interests will be shown on, and the
transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect
to interests of participants) and the records of participants (with respect to interests of persons other than
participants). Qualified institutional buyers may hold their Rule 144A Book-Entry Interests directly through DTC
if they are participants in such system, or indirectly through organizations which are participants in such system.
Investors may hold their Regulation S Book-Entry Interests directly through Euroclear or Clearstream, if
they are participants in such systems, or indirectly through organizations that are participants in such systems.
Euroclear and Clearstream will hold Regulations S Book-Entry Interests on behalf of their participants through
DTC.
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So long as DTC, or its nominee, is the registered owner or holder of a Global Note, DTC or such nominee,
as the case may be, will be considered the sole owner or holder of the Notes represented by such Global Note for
all purposes under the Fiscal and Paying Agency Agreement and the Notes. No beneficial owner of a Book-Entry
Interest will be able to transfer that interest except in accordance with DTC’s applicable procedures, in addition
to those provided for under the fiscal and paying agency agreement and, if applicable, those of Euroclear and
Clearstream.
Conveyance of notices and other communications by DTC to its participants, by those participants to its
indirect participants, and by participants and indirect participants to beneficial owners of Book-Entry Interests
will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in
effect from time to time.
The Fiscal Agent will send any notices in respect of the Notes held in book-entry form to DTC or its
nominee.
Neither DTC nor its nominee will consent or vote with respect to the Notes unless authorized by a
participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to
the Issuer as soon as possible after the record date. The omnibus proxy assigns DTC’s or its nominee’s
consenting or voting rights to those participants to whose account the Notes are credited on the record date.
Payments of the principal of, and interest on, a Global Note will be made to DTC or its nominee, as the case
may be, as the registered owner thereof. Neither the Issuer, the Guarantor nor the Fiscal Agent will have any
responsibility or liability for any aspect of the records relating to or payments made on account of Book-Entry
Interests or for maintaining, supervising or reviewing any records relating to such Book-Entry Interests.
The Issuer expects that DTC or its nominee, upon receipt of any payment of principal or interest in respect
of a Global Note, will credit participants’ accounts with payments in amounts proportionate to their respective
Book-Entry Interests in the principal amount of such Global Note as shown on the records of DTC or its
nominee. The Issuer also expects that payments by participants to owners of Book-Entry Interests in such Global
Note held through such participants will be governed by standing instructions and customary practices, as is now
the case with securities held for the accounts of customers registered in the names of nominees for such
customers. Such payments will be the responsibility of such participants.
Transfers between participants in DTC will be effected in the ordinary way in accordance with DTC rules
and will be settled in same-day funds. Transfers between participants in Euroclear and Clearstream will be
effected in the ordinary way in accordance with their respective rules and operating procedures.
Cross-market transfers between persons holding directly or indirectly through DTC, on the one hand, and
directly or indirectly through Euroclear or Clearstream participants, on the other, will be effected in DTC in
accordance with DTC rules on behalf of the relevant European international clearing system by the relevant
European depositary; however, those cross-market transactions will require delivery of instructions to the
relevant European international clearing system by the counterparty in that system in accordance with its rules
and procedures and within its established deadlines (European time). The relevant European international
clearing system will, if the transaction meets its settlement requirements, deliver instructions to the relevant
European depositary to take action to effect final settlement on its behalf by delivering or receiving securities in
DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement
applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the European
depositaries.
Because of time zone differences, credits of securities received in Euroclear or Clearstream as a result of a
transaction with a person that does not hold the Notes through Euroclear or Clearstream will be made during
subsequent securities settlement processing and dated the first day Euroclear or Clearstream, as the case may be,
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is open for business following the DTC settlement date. Those credits or any transactions in those securities
settled during that processing will be reported to the relevant Euroclear or Clearstream participants on that
business day. Cash received in Euroclear or Clearstream as a result of sales of securities by or through a
Euroclear participant or a Clearstream participant to a DTC participant will be received with value on the DTC
settlement date, but will be available in the relevant Euroclear or Clearstream cash account only as of the first
day Euroclear or Clearstream, as the case may be, is open for business following settlement in DTC.
The Issuer expects that DTC will take any action permitted to be taken by a holder of Notes (including the
presentation of Notes for exchange as described below) only at the direction of one or more participants to whose
account the DTC interests in a Global Note are credited and only in respect of such portion of the aggregate
principal amount of Notes as to which such participant or participants has or have given such direction. However,
if there is an event of default under the Notes, DTC will exchange the applicable Global Note for certificated
Notes, which it will distribute to its participants and which may be legended as set forth under the heading
“Transfer Restrictions.”
DTC
DTC advises that it is a limited purpose trust company organized under The New York Banking Law, a
“banking organization” within the meaning of The New York Banking Law, a member of the Federal Reserve
System, a “clearing corporation” within the meaning of The New York Uniform Commercial Code and a
“clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds
securities for its participants and facilitates the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need
for physical movement of securities certificates. Direct participants include securities brokers and dealers, banks,
trust companies, clearing corporations and certain other organizations. Indirect access to the DTC system is
available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial
relationship with a participant, either directly or indirectly, or indirect participants.
Euroclear
Euroclear holds securities and book-entry interests in securities for participating organizations and facilitates
the clearance and settlement of securities transactions between Euroclear participants, and between Euroclear
participants and participants of certain other securities intermediaries through electronic book-entry changes in
accounts of such participants or other securities intermediaries. Euroclear provides Euroclear participants, among
other things, with safekeeping, administration, clearance and settlement, securities lending and borrowing, and
related services. Euroclear participants are investment banks, securities brokers and dealers, banks, central banks,
supranationals, custodians, investment managers, corporations, trust companies and certain other organizations.
Certain of the Initial Purchasers, or other financial entities involved in this offering, may be Euroclear
participants. Non-participants in the Euroclear system may hold and transfer book-entry interests in the Notes
through accounts with a participant in the Euroclear system or any other securities intermediary that holds a
book-entry interest in the securities through one or more securities intermediaries standing between such other
securities intermediary and Euroclear.
Investors electing to acquire Notes in the offering through an account with Euroclear or some other
securities intermediary must follow the settlement procedures of such intermediary with respect to the settlement
of new issues of securities. Notes to be acquired against payment through an account with Euroclear will be
credited to the securities clearance accounts of the respective Euroclear participants in the securities processing
cycle for the first day Euroclear is open for business following the settlement date for value as of the settlement
date.
Investors electing to acquire, hold or transfer Notes through an account with Euroclear or some other
securities intermediary must follow the settlement procedures of such intermediary with respect to the settlement
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of secondary market transactions in securities. Euroclear will not monitor or enforce any transfer restrictions with
respect to the Notes. Investors that acquire, hold and transfer interests in the Notes by book-entry through
accounts with Euroclear or any other securities intermediary are subject to the laws and contractual provisions
governing their relationship with their intermediary, as well as the laws and contractual provisions governing the
relationship between such intermediary and each other intermediary, if any, standing between themselves and the
individual Notes.
Euroclear has advised that, under Belgian law, investors that are credited with securities on the records of
Euroclear have a co-property right in the fungible pool of interests in securities on deposit with Euroclear in an
amount equal to the amount of interests in securities credited to their accounts. In the event of the insolvency of
Euroclear, Euroclear participants would have a right under Belgian law to the return of the amount and type of
interests in securities credited to their accounts with Euroclear. If Euroclear did not have a sufficient amount of
interests in securities on deposit of a particular type to cover the claims of all participants credited with such
interests in securities on Euroclear’s records, all participants having an amount of interests in securities of such
type credited to their accounts with Euroclear would have the right under Belgian law to the return of their pro
rata share of the amount of interests in securities actually on deposit. Under Belgian law, Euroclear is required to
pass on the benefits of ownership in any interests in Notes on deposit with it (such as dividends, voting rights and
other entitlements) to any person credited with such interests in securities on its records. Distributions with
respect to the Notes held beneficially through Euroclear will be credited to the cash accounts of Euroclear
participants in accordance with the Euroclear terms and conditions.
Clearstream
Clearstream advises that it is incorporated under the laws of Luxembourg and licensed as a bank and
professional depositary. Clearstream holds securities for its participating organizations and facilitates the
clearance and settlement of securities transactions among its participants through electronic book-entry changes
in accounts of its participants, thereby eliminating the need for physical movement of certificates. Clearstream
provides to its participants, among other things, services for safekeeping, administration, clearance and
settlement of internationally traded securities and securities lending and borrowing. Clearstream interfaces with
domestic markets in several countries. Clearstream has established an electronic bridge with the Euroclear
operator to facilitate the settlement of trades between Clearstream and Euroclear. As a registered bank in
Luxembourg, Clearstream is subject to regulation by the Luxembourg Commission for the Supervision of the
Financial Sector. As a professional depository, Clearstream is subject to regulation by the Luxembourg Monetary
Institute. Clearstream participants are recognized financial institutions around the world, including underwriters,
securities brokers and dealers, banks, trust companies and clearing corporations. In the United States,
Clearstream participants are limited to securities brokers and dealers and banks, and may include the Initial
Purchasers, or other financial entities involved in, this offering. Other institutions that maintain a custodial
relationship with a Clearstream participant may obtain indirect access to Clearstream. Clearstream is an indirect
participant in DTC. Distributions with respect to Notes held beneficially through Clearstream will be credited to
cash accounts of Clearstream participants in accordance with its rules and procedures.
Although DTC, Euroclear and Clearstream are expected to follow the foregoing procedures in order to
facilitate transfers of interests in a global note among participants of DTC, Euroclear and Clearstream, they are
under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued
at any time. Neither the Issuer nor the fiscal agent will have any responsibility for the performance by DTC,
Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations
under the rules and procedures governing their respective operations.
The information in this section concerning DTC, Euroclear and Clearstream and DTC’s book-entry system
has been obtained from sources that the Issuer believes to be reliable, but the Issuer takes no responsibility for the
accuracy thereof.
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Summary of Provisions Relating to Certificated Notes
If DTC is at any time unwilling or unable to continue as a depositary for the Global Notes and a successor
depositary is not appointed by the Issuer within 90 days, or if there shall have occurred and be continuing an
event of default with respect to the Notes, the Issuer will issue certificated Notes, with Guarantees endorsed
thereon by the Guarantor, in exchange for the Global Notes. Certificated notes delivered in exchange for BookEntry Interests will be registered in the names, and issued in denominations of $1,000 and integral multiples of
$1,000 in excess thereof, requested by or on behalf of DTC or the successor depositary (in accordance with its
customary procedures). Holders of Book-Entry Interests may receive certificated Notes, which may bear the
legend referred to under “Transfer Restrictions”, in accordance with DTC’s rules and procedures in addition to
those provided for under the Fiscal and Paying Agency Agreement.
Except in the limited circumstances described above, owners of Book-Entry Interests will not be entitled to
receive physical delivery of individual definitive certificates. The Notes are not issuable in bearer form.
Subject to any applicable transfer restrictions, the holder of a certificated note bearing the legend referred to
under “Transfer Restrictions” may transfer or exchange such Notes in whole or in part by surrendering them to
the Fiscal Agent. Prior to any proposed transfer of Notes in certificated form, the holder may be required to
provide certifications and other documentation to the Fiscal Agent as described above. In the case of a transfer of
only part of a note, the original principal amount of both the part transferred and the balance not transferred must
be in authorized denominations, and new Notes will be issued to the transferor and transferee, respectively, by
the Fiscal Agent. Upon the transfer, exchange or replacement of certificated Notes not bearing the legend
described above, the Fiscal Agent will deliver certificated Notes that do not bear such legend.
Upon the transfer, exchange or replacement of certificated Notes bearing the legend described above, or
upon a specific request for removal of the legend from such certificated note, the Fiscal Agent will deliver only
certificated Notes bearing such legend or will refuse to remove such legend, as the case may be, unless there is
delivered to the Issuer such satisfactory evidence, which may include an opinion of legal counsel of recognized
standing, as may be reasonably required by the Issuer that neither the legend nor the restrictions on transfer set
forth therein are required to ensure compliance with the provisions of the Securities Act.
Payment of principal and interest in respect of the certificated Notes shall be payable at the office or agency
of the Issuer in the City of New York which shall initially be at the corporate trust office of the Fiscal Agent,
which is located at 452 Fifth Avenue, New York, NY 10018, provided that at the option of the Issuer with prior
notice to the paying agent, payment may be made by wire transfer, direct deposit or check mailed to the address
of the holder entitled thereto as such address appears in the note register.
If the Issuer decides to maintain a paying agent with respect to the Notes in a member state of the European
Union, it will ensure such paying agent is in a member state of the European Union that is not obligated to
withhold or deduct tax pursuant to European Council Directive 2003/48/EC or any other directive implementing
the conclusions of ECOFIN Council meeting of November 26-27, 2000 on the taxation of savings income, or any
law implementing or complying with, or introduced in order to conform to, such Directive or such other
directive.
The certificated Notes, at the option of the Holder and subject to the restrictions contained in the Notes and
in the Fiscal and Paying Agency Agreement, may be exchanged or transferred, upon surrender for exchange or
presentation for registration of transfer at the office of the Fiscal Agent. Any certificated note surrendered for
exchange or presented for registration of transfer shall be duly endorsed, or be accompanied by a written
instrument of transfer in form satisfactory to the Fiscal Agent, duly endorsed by the Holder thereof or his
attorney duly authorized in writing. Notes issued upon such transfer will be executed by the Issuer and
authenticated by the Fiscal Agent, registered in the name of the designated transferee or transferees and delivered
at the office of the Fiscal Agent or mailed, at the request, risk and expense of, and to the address requested by,
the designated transferee or transferees.
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TAXATION
Taxation in Germany
The following is a general discussion of certain German tax consequences of the acquisition, ownership and
disposition of the Notes. This discussion does not purport to be a comprehensive description of all tax
consequences that may be relevant to an investor’s decision to invest in the Notes. In particular, this discussion
does not consider any specific tax consequences that may apply due to facts or circumstances of a particular
investor. The discussion is based on the laws of Germany as currently in force and applied on the date of this
Offering Memorandum. Such laws are subject to changes, possibly with retroactive effect. The discussion is not
intended to be, nor should it be construed to be, legal or tax advice.
Prospective investors in the Notes are urged to consult their own tax advisors as to the tax consequences of
the acquisition, ownership or disposition of the Notes, including the effect of any state or local taxes, under the
tax laws of Germany and any other relevant jurisdiction.
The German tax laws concerning the taxation of capital investment income in the hands of individual
investors holding the Notes as private assets will change significantly generally with effect as of 2009. These
changes are described below under the caption “— Company Tax Reform Act 2008”. For individual investors
holding the Notes as private assets, the tax consequences described below under the captions “— German
Holders” and “— Non German Holders” will only be applicable in 2008, and, under certain circumstances, to the
disposition or redemption of Notes that have been acquired in 2008.
German Holders
Taxation of Interest Income
Under German tax law, as currently in effect, payments of interest on the Notes including payments for
interest that accrued up to a disposition of a Note and is credited separately (“Accrued Interest”; Stückzinsen), to
persons who are residents of Germany (e.g., persons whose residence, habitual abode, statutory seat or place of
management is located in Germany, a “German Holder”) are subject to German individual income tax at
progressive individual tax rates or corporate income tax (in each case plus solidarity surcharge thereon which is
currently levied at a rate of 5.5%). Interest income derived from the Notes may also be subject to trade tax on
income if the Notes are held as part of a German business establishment for trade tax purposes.
Individual investors are entitled to an annual lump-sum deduction for expenses related to investment income
(Werbungskosten-Pauschbetrag) of €51 (€102 for married couples filing jointly) in computing their income from
capital investment (including income earned from the Notes) as well as an annual saver’s exemption (SparerFreibetrag) of €750 (€1,500 for married couples filing jointly) with respect to such investment income.
Withholding Tax on Interest Income
If the Notes are kept or administered in a custodial account maintained by a German Holder with a German
resident bank or a German resident financial services institution, also including a German branch of a foreign
bank or a foreign financial services institution but excluding a foreign branch of a German bank or a German
financial services institution (“German Disbursing Agent”), a 30% withholding tax on interest payments
(Zinsabschlag), plus a 5.5% solidarity surcharge thereon, will be withheld by such German Disbursing Agent on
payments of interest, resulting in a total withholding tax charge of 31.65% on the gross amount of interest paid. If
a German Holder sells Notes during a current interest period, Accrued Interest received in connection therewith
will also be subject to withholding tax at a rate of 30% and 5.5% solidarity surcharge thereon. Accrued Interest
paid by a German Holder upon the purchase of the Notes may be offset against the amount of interest income
received by such German Holder and, under certain circumstances, may reduce the amount subject to
withholding tax. If the Notes are presented for payment at the offices of a German Disbursing Agent (over-thecounter-transaction; Tafelgeschäft), withholding tax will be imposed at a rate of 35%, plus a 5.5% solidarity
surcharge thereon, resulting in a total withholding tax charge of 36.925%.
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Withholding tax and solidarity surcharge thereon might be credited as prepayments against the German
Holder’s final tax liability for German individual income or corporate income tax purposes and the respective
solidarity surcharge, or, if in excess of such liability, refunded upon application.
No tax is withheld by the Disbursing Agent if the holder is an individual who has filed a withholding
exemption certificate (Freistellungsauftrag) with the Disbursing Agent and the respective Notes are not part of a
German trade or business property or generate income from the letting and leasing of property. However, this
exemption applies only to the extent that the aggregate interest income derived from the Notes together with an
individual’s other investment income administered by the Disbursing Agent does not exceed the respective
applicable maximum annual exemption amount (up to €801 for individuals and €1,602 for married couples filing
jointly). Further, no withholding obligation exists, if the holder of the Notes submits a certificate of nonassessment (Nichtveranlagungsbescheinigung) issued by the local tax office to the Disbursing Agent.
Disposition or Redemption of the Notes
Capital gains resulting from the disposition or redemption of Notes (or, as the case may be, from the
payment at maturity of the Notes) realized by individual German Holders holding the Notes as private assets
(“German Private Investors”) are generally taxable if the capital gain is realized within one year after the
acquisition of the Notes. Capital losses realized by German Private Investors from the disposition or redemption
of the Notes may only be offset against taxable capital gains resulting from the disposition or redemption of
Notes or from other private transactions (private Veräußerungsgeschäfte) within the same fiscal year and, subject
to certain limitations, in the preceding year or in subsequent years.
If the German Private Investor’s aggregate capital gain from taxable private transactions amounts to less
than €512 in one calendar year the capital gains are not subject to German income tax.
Capital gains derived by German Private Investors from the disposition or redemption of Notes are not
subject to German income tax if the Notes are sold or redeemed more than one year after their acquisition,
provided that the Notes do not qualify as Financial Innovations, as described under the following caption
“Special Rules for Financial Innovations.” Currency gains derived by German Private Investors are only taxable
if the disposition or redemption of the Notes is realized within one year after their acquisition.
Irrespective of a holding period, any capital gain resulting from the disposition or redemption of Notes (or,
as the case may be, from the payment at maturity of the Notes) are subject to individual income or corporate
income tax, including trade tax, if such Notes are held as business assets of a German Holder.
Special Rules for Financial Innovations
To the extent Notes are classified as financial innovations (“Financial Innovations”; Finanzinnovationen),
special provisions apply to the disposition or redemption, or upon maturity, of the Notes by German Private
Investors. In particular, debt instruments may be classified as Financial Innovations if they provide for a floating,
variable or contingent interest rate, an issue discount or certain optional redemption rights.
In case Notes are classified as Financial Innovations, capital gains arising upon the disposition or redemption,
or upon maturity, of Notes realized by a German Private Investor (including capital gains so derived by a secondary
or subsequent purchaser who is a German Private Investor) are fully or partially subject to income tax, regardless of
the one-year holding period described above under the caption “Disposition or Redemption of the Notes”. If a yield
to maturity (Emissionsrendite) cannot be established, the difference between the proceeds from the disposition or
redemption and the purchase price of the Notes (market yield; Marktrendite), is deemed interest income. In case a
yield to maturity can be established, only the part of the capital gain attributable to such yield to maturity during the
period the respective German Private Investor held the new note is subject to income tax.
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Upon the disposition or redemption, or upon maturity, of Notes that are classified as Financial Innovations,
the difference between the purchase price and the proceeds from the disposition is subject to 30% withholding
tax (plus a solidarity surcharge of 5.5% thereon) if the Notes are kept or administered in a custodial account by
the same German Disbursing Agent since the acquisition of the Notes. If the Notes have not been so kept in a
custodial account by the same German Disbursing Agent, withholding tax at the same rate will be imposed on
30% of the proceeds received upon the disposition or redemption, or upon the maturity, of the Notes.
As described above such withholding tax might be credited or refunded upon application.
Non-German Holders
Income derived from the Notes by persons who are not tax residents of Germany (“Non-German Holder”) is
in general exempt from German individual income or corporate income taxation, and no withholding tax must be
withheld (even if the Notes are kept with a German Disbursing Agent), provided (i) the Notes are not held as
business assets (Betriebsvermögen) of a German permanent establishment of the Non-German Holder or a fixed
base or as a business asset for which a permanent representative has been appointed in Germany, (ii) the Notes
are not presented for payment at the offices of a German Disbursing Agent in an over-the-counter-transaction,
(iii) the income derived from the Notes does not otherwise constitute German source income (such as income
from the letting and leasing of certain German situs property) and (iv) in the event that the Notes are kept or
administered in a custodial account maintained with a German Disbursing Agent, the Holder of the Notes
complies with the applicable procedural rules under German law and provides evidence of the fact that the
Holder of the Notes is not subject to taxation in Germany.
If the income is subject to German taxation (e.g., if the Notes are held as business assets of a German
permanent establishment of a Non-German Holder), such Holder is subject to a tax treatment similar to that
described above under the caption “— German Holders.”
If the Notes are involved in an over-the-counter-transaction, as described above, income derived therefrom
will be subject to withholding tax of 35% plus a 5.5% solidarity surcharge thereon.
Company Tax Reform Act 2008
The “Company Tax Reform Act 2008” (Federal Law Gazette I 2007, 1912) provides for various substantial
changes in the taxation of individual investors in respect of capital investment income. In the following certain
important changes are described which could become relevant for German Holders and Non-German Holders.
The new provisions under the Company Tax Reform Act 2008 regarding the taxation of interest income and
capital gains (see the description under the caption — “Taxation of Interest Income and Capital Gains” below)
and the withholding tax (see the description under the caption — “Withholding Tax on Interest Income and
Capital Gains” below) will apply to interest on the Notes, including Accrued Interest, received by a German
Private Investor after December 31, 2008. Capital gains derived by a German Private Investor from a disposition
or redemption of the Notes will be subject to the new provisions after December 31, 2008 if (i) the Notes have
been acquired after December 31, 2008 or (ii) qualify as Financial Innovations.
German Holders
Taxation of Interest Income and Capital Gains
Payments of interest on the Notes, including Accrued Interest, to German Private Investors will be subject to
German income tax generally at a flat rate of 25% (plus solidarity surcharge thereon, which is currently levied at
a rate of 5.5%, resulting in a total rate of 26.375%). Irrespective of the holding period or the qualification of the
Notes as Financial Innovations, capital gains derived by German Private Investors from the disposition or
redemption of the Notes (or, as the case may be, from the payment at maturity of the Notes) generally will be
subject to German income tax at the same flat rate (plus solidarity surcharge thereon). The taxable capital gain
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will be the difference between the proceeds received upon the disposition or redemption, or upon the maturity, of
the Notes (after the deduction of the actual expenses directly related to the sale) and the acquisition costs. Losses
from the redemption or disposition of Notes realized after December 31, 2008 may generally be offset only
against profits from other capital gains or other capital income in the same or, subject to various limitations,
subsequent fiscal years.
The deduction for actual expenses related to the income is replaced by a saver’s lump-sum deduction
(Sparer-Pauschbetrag) of €801 (€1,602 for married couples filing jointly). Where the Notes are issued in a
currency other than Euro, both the proceeds derived from disposition or redemption and the acquisition costs,
will be converted into Euro taking into account the relevant conversion rates as of the date of acquisition and
disposition or redemption, respectively.
Withholding Tax on Interest Income and Capital Gains
The rate at which withholding tax will be levied on interest payments on the Notes, including Accrued
Interest, if the Notes are kept or administered in a custodial account maintained by a German Holder with a
German Disbursing Agent (which term also includes, as of 2009, a German securities trading firm
(Wertpapierhandelsunternehmen) or a German securities trading bank (Wertpapierhandelsbank)), will be
reduced to 25% plus a 5.5% solidarity surcharge thereon, resulting in a total withholding tax charge of 26.375%.
Withholding tax at such rate will generally also be levied on capital gains irrespective of whether or not the
Notes are classified as Financial Innovations. The same withholding tax rate applies to an over-the-countertransaction. In addition, under the new provisions, church tax may be levied by way of withholding upon
application by a German Private Investor. In the event that (i) the Notes have not been so kept in a custodial
account by the same German Disbursing Agent since their acquisition and (ii) the relevant acquisition costs could
not be established by the relevant German Holder by way of certification from the previous German Disbursing
Agent or from a foreign bank or foreign financial services institution within the European Economic Area or a
foreign branch of a German bank or financial services institution within the European Economic Area,
withholding tax at the same rate will be imposed on 30% of the proceeds received upon the disposition or
redemption, or upon the maturity, of the Notes.
The withholding tax will generally be a final tax for German Private Investors, i.e., the income tax liability
is generally satisfied through the withholding and interest payments or capital gains which have been subject to
the withholding tax are not to be included in the annual income tax return (Abgeltungssteuer). However, upon
election and filing of an annual income tax return, the German Private Investors’ income derived from interest
payments, including Accrued Interest, and capital gains from the disposition or redemption of the Notes can be
taxed at regular individual tax rates if this results in a lower income tax burden. The tax withheld at source will
then be credited against the individual income tax liability assessed or, if in excess of such liability, refunded.
Non-German Holders
Non-German Holders of the Notes will in general not be subject to German taxation with their interest or
capital gains from the Notes and no tax will in general be withheld by German Disbursing Agents under the
conditions described under the previous caption “— Non-German Holders”.
If interest or capital gains from the Notes will be subject to taxation in Germany and the Notes are kept or
administered by a German Disbursing Agent (or involved in an over-the-counter-transaction), withholding tax at
the reduced rate of 25% (plus solidarity surcharge thereon, which is currently levied at a rate of 5.5%, resulting in
a total withholding tax charge of 26.375%) will be levied on interest and capital gains from the Notes. Such
withholding tax can be credited against the German individual or corporate income tax liability of a Non-German
Holder or, if in excess of such liability, refunded.
Substitution of the Issuer
The Guarantor or certain of its subsidiaries may, subject to certain restrictions, assume the obligations of the
Issuer under the Notes without the consent of the holders. Such an assumption may be treated as a taxable
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disposition for German income tax purposes and could lead to a gain equal to the difference between the fair
market value as of the date of the assumption and the relevant acquisition cost of the Notes, which would be
subject to the same rules applicable to a disposition of the Notes (discussed above). Holders should consult their
own tax advisors regarding the German tax consequences of such an assumption.
Inheritance and Gift Tax, Other Taxes
No inheritance or gift tax with respect to any Notes will arise under the laws of Germany, if, in the case of
inheritance tax, both the decedent and the beneficiary, and, in the case of gift tax, both the donor and the donee,
are tax non-residents and are not deemed to be tax residents of Germany at the time of the transfer and such
Notes are not attributable to a permanent establishment or to a business property for which a permanent
representative has been appointed in Germany. In the case of a decedent, donor or heir who is a German national,
this only applies if such person has been a non-resident of Germany for more than five consecutive years.
No stamp, issue, registration or similar taxes or duties will be payable in Germany in connection with the
issuance, delivery or execution of the Notes. Under certain circumstances, an entrepreneur may opt to have
value-added tax levied on a transaction involving the disposition of the Notes, when such transaction is executed
for the enterprise of another entrepreneur. Currently, net asset tax (Vermögensteuer) is not levied in Germany.
EU Savings Directive
The Council of the European Union (the “Council”) on June 3, 2003 adopted a directive regarding the
taxation of savings income (2003/48/EC, the “Directive”). Under the Directive, Member States will be required
to provide to the tax authorities of another Member State information about payments of interest (or other similar
income) paid by a person within its jurisdiction to an individual resident in that other Member State except that,
from the date of implementation of the Directive, Belgium, Luxembourg and Austria have instead offered to
operate a withholding system for a transitional period in relation to such payments (the ending of such
transitional period in particular being dependent upon the conclusion of agreements relating to information
exchange with certain other countries). The Directive has come into effect on July 1, 2005.
A number of non-EU countries, and certain dependent or associated territories of certain Member States,
have agreed to adopt similar measures (either provisions of information or transitional withholding) in relation to
payments made by a person within its jurisdiction to an individual resident in a Member State. In addition, the
Member States have entered into reciprocal provision of information or transitional withholding arrangements
with certain of those dependent or associated territories in relation to payments made by a person in a Member
State to an individual resident in one of those territories.
United States Federal Income Tax Considerations
TO ENSURE COMPLIANCE WITH TREASURY DEPARTMENT CIRCULAR 230, INVESTORS
ARE HEREBY NOTIFIED THAT: (A) ANY DISCUSSION OF UNITED STATES FEDERAL TAX
ISSUES IN THIS OFFERING MEMORANDUM (INCLUDING ANY ATTACHMENTS) IS NOT
INTENDED OR WRITTEN TO BE USED, AND CANNOT BE USED, BY INVESTORS FOR THE
PURPOSE OF AVOIDING PENALTIES THAT MAY BE IMPOSED ON INVESTORS UNDER THE
INTERNAL REVENUE CODE; (B) SUCH DISCUSSION HAS BEEN WRITTEN IN CONNECTION
WITH THE PROMOTION OR MARKETING OF THE TRANSACTIONS OR MATTERS
ADDRESSED HEREIN; AND (C) INVESTORS SHOULD SEEK ADVICE BASED ON THEIR
PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR.
The following discussion is a general summary of certain U.S. federal income tax consequences of the
purchase, ownership and disposition of Notes to a U.S. holder (as defined below) that holds its Notes as a capital
asset (generally, property held for investment) and that purchases the Notes in the initial offering and at the
“issue price” (as defined below). This summary is based on the Internal Revenue Code of 1986, as amended,
Treasury regulations promulgated thereunder, rulings, judicial decisions and administrative pronouncements, all
as in effect on the date hereof, and all of which are subject to change or changes in interpretation, possibly with
retroactive effect.
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This summary does not address all aspects of U.S. federal income taxation that may apply to holders that are
subject to special tax rules, including U.S. expatriates, insurance companies, tax-exempt entities, banks, financial
institutions, persons subject to the alternative minimum tax, dealers in securities or currencies, regulated
investment companies, traders in securities that mark to market, persons holding their Notes as part of a straddle,
hedging transaction or conversion transaction, or persons whose functional currency is not the U.S. dollar. These
holders may be subject to U.S. federal income tax consequences different from those set forth below. If a
partnership (including for this purpose any entity treated as a partnership for U.S. federal income tax purposes)
holds Notes, the tax treatment of a partner generally will depend upon the status of the partner and the activities
of the partnership. A partner in a partnership that holds Notes is urged to consult its tax advisor regarding the
specific tax consequences of the purchase, ownership and disposition of the Notes.
For purposes of this discussion, the term “U.S. holder” means a beneficial owner of Notes who is (a) a
citizen or individual resident of the United States for U.S. federal income tax purposes, (b) a corporation (or
other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the
laws of the United States or any state thereof (including the District of Columbia), (c) an estate the income of
which is subject to U.S. federal income taxation regardless of its source, or (d) a trust if a court within the United
States can exercise primary supervision over the administration of the trust and one or more U.S. persons are
authorized to control all substantial decisions of the trust.
The “issue price” of a Note is equal to the first price at which a substantial amount of the Notes is sold for
money other than to bond houses, brokers or similar persons or organizations acting in the capacity of
underwriters, placement agents or wholesalers.
U.S. holders should consult their tax advisors regarding the specific Dutch, German and U.S. federal,
state and local tax consequences of purchasing, owning and disposing of Notes in light of their particular
circumstances as well as any consequences arising under the laws of any other relevant taxing jurisdiction.
Payments of Interest
It is anticipated that the Notes will not be issued with original issue discount for U.S. federal income tax
purposes. In this case, payments of interest on a Note generally will be taxable to a U.S. holder as ordinary
interest income at the time such payments are received or are accrued in accordance with the U.S. holder’s
method of accounting for U.S. tax purposes.
Interest paid on a Note generally will constitute foreign-source income. For purposes of computing
allowable foreign tax credits for U.S. tax purposes, interest generally will be treated as “passive category”
income, or, in the case of certain U.S. holders, “general category” income. The rules relating to foreign tax
credits are complex and U.S. holders should consult their own tax advisors regarding the application of the
foreign tax credit limitations to their particular situation.
Sale or Other Disposition
Upon the sale or other disposition of a Note, a U.S. holder generally will recognize capital gain or loss in an
amount equal to the difference between the amount realized (other than amounts attributable to accrued and
unpaid interest, which will be taxable as ordinary interest income in accordance with the U.S. holder’s method of
tax accounting) and the U.S. holder’s adjusted tax basis in the Note (generally its cost less any principal
payments previously received). Any gain or loss recognized upon the sale or other disposition of a Note by a U.S.
holder generally will be U.S.-source capital gain or loss, and will be treated as long-term capital gain or loss if
the Note has been held for more than one year at the time of the sale or other disposition. Capital gains
recognized by an individual U.S. holder generally are subject to U.S. federal income taxation at preferential rates
if certain minimum holding periods are met. The deductibility of capital losses for all taxpayers is subject to
significant limitations.
209
Substitution of the Issuer
The Guarantor or certain of its subsidiaries may, subject to certain restrictions, assume the obligations of the
Issuer under the Notes without the consent of the holders. Such an assumption may in some circumstances be
treated as a taxable exchange for U.S. federal income tax purposes. Holders should consult their own tax advisors
regarding the U.S. federal, state, and local tax consequences of such an assumption.
U.S. Information Reporting and Backup Withholding
Payments of interest on and proceeds from the sale or other disposition of the Notes may be subject to
information reporting to the Internal Revenue Service and backup withholding at a current rate of 28%. Certain
exempt recipients (such as corporations) are not subject to these information reporting requirements. Backup
withholding will not apply to a holder who furnishes a correct taxpayer identification number or certificate of
foreign status and makes any other required certification, or who is otherwise exempt from backup withholding.
U.S. persons who are required to establish their exempt status generally must provide IRS Form W 9 (Request
for Taxpayer Identification Number and Certification). Non-U.S. holders generally will not be subject to U.S.
information reporting or backup withholding. However, these holders may be required to provide certification of
non-U.S. person status (generally on IRS Form W-8BEN) in connection with payments received in the United
States or through certain U.S.-related financial intermediaries.
Backup withholding is not an additional tax. Amounts withheld as backup withholding may be credited
against a holder’s U.S. federal income tax liability. A holder may obtain a refund of any excess amounts withheld
under the backup withholding rules by timely filing the appropriate claim for refund with the Internal Revenue
Service and furnishing any required information.
Netherlands Tax Considerations
The following summary of certain Dutch taxation matters is based on the laws and practice in force as of the
date of this offering memorandum and is subject to any changes in law and the interpretation and application
thereof, which changes could be made with retroactive effect. The following summary does not purport to be a
comprehensive description of all the tax considerations that may be relevant to a decision to acquire, hold or
dispose of the Notes, and does not purport to deal with the tax consequences applicable to all categories of
investors, some of which (such as dealers in Notes) may be subject to special rules.
This summary does not address the Dutch tax consequences for a holder of a Note who holds a substantial
interest (“aanmerkelijk belang”) in the issuer. Generally speaking, a person holds a substantial interest in an
entity, if he or she, alone or together with his or her partner (statutory defined term) or certain other related
persons, directly or indirectly, holds (i) an interest of five per cent. or more of the total issued capital of the
entity, or of five per cent. or more of the issued capital of a certain class of shares of the entity, (ii) rights to
acquire, directly or indirectly, such interest or (iii) certain profit sharing rights in the entity.
Save as otherwise indicated, this summary only addresses the position of investors who do not have any
connection with the Netherlands other than the holding of the Notes.
Investors are advised to consult their professional advisers as to the tax consequences of purchase,
ownership and disposition of the Notes.
For the purpose of this summary, it is assumed that E.ON International Finance B.V. is resident or deemed
to be resident of The Netherlands for taxation purposes.
Withholding tax
All payments by E.ON International Finance B.V. of interest and principal under the Notes can be made free
of withholding or deduction for any taxes of whatsoever nature imposed, levied, withheld or assessed by The
Netherlands or any political subdivision or taxing authority thereof or therein, unless the Notes qualify as debt as
referred to in article 10, paragraph 1, sub d of the Dutch Corporate Tax Act 1969 (Wet op de
vennootschapsbelasting 1969).
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Taxes on Income and Capital Gains
A holder of a Note who derives income from a Note or who realises a gain on the disposal or redemption of
a Note will not be subject to Dutch taxation on such income or capital gain unless:
(a) the holder is, or is deemed to be, resident in The Netherlands, or, where the holder is an individual, such
holder has elected to be treated as a resident of The Netherlands; or
(b) such income or gain is attributable to an enterprise or part thereof which is either effectively managed in
The Netherlands or carried on through a permanent establishment (vaste inrichting) or a permanent
representative (vaste vertegenwoordiger) in The Netherlands; or
(c) the holder has, directly or indirectly, a substantial interest (aanmerkelijk belang) in E.ON International
Finance B.V. as defined in the Dutch Income Tax Act 2001 (Wet inkomstenbelasting 2001) and, if the
holder is not an individual, such interest does not form part of the arrests of an enterprise; or
(d) the holder is an individual and such income or gain qualifies as income from activities that exceed normal
active portfolio management in The Netherlands.
Gift, Estate or Inheritance Taxes
Dutch gift, estate or inheritance taxes will not be levied on the occasion of the transfer of a Note by way of
gift by, or on the death of, a holder, unless:
(a) the holder is, or is deemed to be, resident in The Netherlands for the purpose of the relevant provisions; or
(b) the transfer is construed as an inheritance or as a gift made by, or on behalf of, a person who, at the time of
the gift or death, is, or is deemed to be, resident in The Netherlands for the purpose of the relevant
provisions; or
(c) such Note is attributable to an enterprise or part thereof, which is either effectively managed in The
Netherlands or carried on through a permanent establishment or a permanent representative in The
Netherlands.
Value Added Tax
There is no Dutch value added tax payable in respect of payments in consideration for the issue of the Notes
or in respect of the payment of interest or principal under the Notes or the transfer of the Notes.
Other Taxes and Duties
There is no Dutch registration tax, stamp duty or any other similar tax or duty payable in The Netherlands in
respect of or in connection with the execution, delivery and/or enforcement by legal proceedings (including any
foreign judgment in the courts of The Netherlands) of the Notes or the performance of the obligations of the
E.ON International Finance B.V. under the Notes.
Residence
A holder of a Note will not be treated as a resident of The Netherlands by reason only of the holding of a
Note or the execution, performance, delivery and/or enforcement of the Notes.
211
PLAN OF DISTRIBUTION
The Issuer intends to offer the Notes through the Initial Purchasers. Banc of America Securities LLC,
Deutsche Bank Securities Inc., Goldman, Sachs & Co. and J.P. Morgan Securities Inc. are acting as
representatives for the Initial Purchasers named below. Subject to the terms and conditions contained in a
purchase agreement dated April 15, 2008 between the Issuer, the Guarantor and the Initial Purchasers (the
“Purchase Agreement”), the Issuer has agreed to sell to the Initial Purchasers, and the Initial Purchasers have
severally agreed to purchase from the Issuer, the principal amount of each series of Notes listed opposite their
names below:
Initial Purchasers
Principal Amount
Banc of America Securities LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deutsche Bank Securities Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goldman, Sachs & Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
J.P. Morgan Securities Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Greenwich Capital Markets, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lehman Brothers Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merrill Lynch, Pierce, Fenner & Smith
Incorporated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
2018 Notes
450,000,000
450,000,000
450,000,000
450,000,000
66,666,000
66,667,000
$ 66,666,000
$2,000,000,000
$
$
$
$
$
$
2038 Notes
225,000,000
225,000,000
225,000,000
225,000,000
50,000,000
50,000,000
—
$1,000,000,000
The Initial Purchasers have agreed, severally and not jointly, to purchase all of the Notes of a series being
sold pursuant to the Purchase Agreement if any of such Notes are purchased. If an Initial Purchaser defaults, the
Purchase Agreement provides that the purchase commitments of the non-defaulting Initial Purchasers may be
increased or the Purchase Agreement may be terminated.
The Initial Purchasers have advised the Issuer that they (or certain of their affiliates acting as selling agents)
propose initially to offer the Notes for resale at the prices listed on the cover page of this offering memorandum
within the United States to Qualified Institutional Buyers as defined in, and in reliance upon Rule 144A and
outside the United States to non-U.S. persons in transactions exempt from registration under Regulation S. See
“Transfer Restrictions.” After the initial offering of the Notes, the offering price and other selling terms may
from time to time be varied by the Initial Purchasers.
The Issuer and the Guarantor have agreed to indemnify the Initial Purchasers against certain liabilities,
including certain liabilities under the Securities Act.
The Initial Purchasers are offering the Notes, subject to prior sale, when, as and if issued to and accepted by
them, subject to approval of legal matters by their counsel, including the validity of the Notes, and other
conditions contained in the Purchase Agreement, such as the receipt by the Initial Purchasers of officer’s
certificates and legal opinions. The Initial Purchasers reserve the right to withdraw, cancel or modify offers to
investors and to reject orders in whole or in part. After the Notes are released for sale, the Initial Purchasers may
change the offering prices and other selling terms without notice.
Each series of the Notes will be a new issue of securities with no established trading market and will not be
listed on any exchange. We cannot assure you that the prices at which the Notes will be sold in the market after
this offering will not be lower than the initial offering prices listed on the cover page of this offering
memorandum. The Initial Purchasers are not obligated to make a market in any series of the Notes and
accordingly, no assurance can be given as to the liquidity of, or trading markets for, the Notes. In connection with
the offering, Banc of America Securities LLC (or any person acting for it), acting for the benefit of the Initial
Purchasers, may purchase and sell Notes in the open market. These transactions may include over-allotment,
syndicate covering transactions and stabilizing transactions. Over-allotment involves sales of Notes of any series
in excess of the principal amount of such Notes to be purchased in the offering, which creates a short position.
Syndicate covering transactions involve purchases of the Notes in the open market after the distribution has been
completed in order to cover short positions created. Stabilizing transactions consist of certain bids or purchases
of Notes made for the purpose of pegging, fixing or maintaining the prices of the Notes.
212
Banc of America Securities LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co. or J.P. Morgan
Securities Inc. (or any person acting for either of them), acting for the benefit of the Initial Purchasers, may
impose penalty bids. Penalty bids permit Banc of America Securities LLC, Deutsche Bank Securities Inc.,
Goldman, Sachs & Co. or J.P. Morgan Securities Inc. (or any person acting for either of them) to reclaim selling
concessions from a syndicate member when it, in covering short positions or making stabilizing purchases,
repurchases Notes originally sold by that syndicate member.
Any of these activities may cause the prices of the Notes to be higher than the price that otherwise would
exist in the open market in the absence of such transactions. These transactions may be effected in any
over-the-counter market, and, if commenced, may be discontinued at any time.
We expect that delivery of the Notes will be made against payment therefor on or about the closing date
specified on the cover page of this offering memorandum (the “Settlement Date”), which will be the fifth New
York business day following the date of pricing of the Notes of this offering (this settlement cycle being referred
to as “T+5”). Under Rule 15c6-1 of the Securities Exchange Act of 1934, trades in the secondary market
generally are required to settle in three New York business days, unless the parties to any such trade expressly
agree otherwise. Accordingly, purchasers who wish to trade Notes prior to the third business day preceding the
Settlement Date will be required, by virtue of the fact that the Notes initially will settle in T+5, to specify an
alternative settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of Notes who
wish to trade Notes prior to the third business day preceding the Settlement Date should consult their own
advisor.
Selling Restrictions
General
No action has been or will be taken in any jurisdiction that would permit a public offering of the Notes, or
the possession, circulation or distribution of this offering memorandum, or any amendment or supplement to this
offering memorandum, or any other offering or publicity material relating to the Notes, in any country or
jurisdiction where, or in any circumstances in which, action for that purpose is required. Accordingly, the Notes
may not be offered or sold, directly or indirectly, and neither this offering memorandum nor any other offering
material or advertisements in connection with the Notes may be distributed or published, in or from any country
or jurisdiction except under circumstances that will result in compliance with applicable laws and regulations.
Each Initial Purchaser has agreed that it will, to the best of its knowledge, comply with all relevant laws,
regulations and directives in each jurisdiction in which it purchases, offers, sells or delivers Notes or has in its
possession or distributes this offering memorandum and none of the Issuer, the Guarantor or any other initial
purchaser shall have any responsibility therefor.
United States
The Initial Purchasers propose to offer the Notes for resale in transactions not requiring registration under
the Securities Act or applicable state securities laws, including sales pursuant to Rule 144A. The Initial
Purchasers will not offer or sell the Notes except:
•
to persons they reasonably believe to be Qualified Institutional Buyers; or
•
pursuant to offers and sales to non-U.S. persons that occur in offshore transactions outside the United
States within the meaning of Regulation S.
In addition, until 40 days after the later of the commencement of this offering and the closing date of this
offering, an offer or sale of the Notes within the United States by a dealer (whether or not participating in this
offering) may violate the registration requirements of the Securities Act if such offer or sale is made otherwise
than in accordance with Rule 144A or another available exemption from the registration requirements thereof.
Notes sold pursuant to Regulation S may not be offered or resold in the United States or to U.S. persons (as
defined in Regulation S), except under an exemption from the registration requirements of the Securities Act or
under a registration statement declared effective under the Securities Act.
213
European Economic Area
In relation to each member state of the European Economic Area which has implemented the Prospectus
Directive (each, a “Relevant Member State”), each Initial Purchaser has represented and agreed that with effect
from and including the date on which the Prospectus Directive is implemented in that Relevant Member State
(the “Relevant Implementation Date”), it has not made and will not make an offer of Notes to the public in that
Relevant Member State, except that it may, with effect from and including the Relevant Implementation Date,
make an offer of Notes to the public in that Relevant Member State:
•
to legal entities which are authorized or regulated to operate in the financial markets or, if not so
authorized or regulated, whose corporate purpose is solely to invest in securities;
•
to any legal entity which has two or more of: (i) an average of at least 250 employees during the last
financial year; (ii) a total balance sheet of more than €43,000,000; and (iii) an annual net turnover of
more than €50,000,000, as shown in its last annual or consolidated accounts;
•
to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus
Directive) subject to obtaining the prior consent of the Initial Purchasers for any such offer; or
•
in any other circumstances falling within Article 3(2) of the Prospectus Directive,
provided that no such offer of Notes shall require the Issuer or any of the Initial Purchasers to publish a
prospectus pursuant to Article 3 of the Prospectus Directive.
For the purposes of this provision, the expression an “offer of Notes to the public” in relation to any Notes
in any Relevant Member State means the communication in any form and by any means of sufficient information
on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe
to the Notes, as the same may be varied in that Relevant Member State by any measure implementing the
Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive
2003/71/EC and includes any relevant implementing measure in each Relevant Member State.
United Kingdom
Each Initial Purchaser has represented and agreed that:
•
it has only communicated or caused to be communicated and will only communicate or cause to be
communicated any invitation or inducement to engage in investment activity (within the meaning of
section 21 of the Financial Services and Markets Act 2000, or the FSMA) received by it in connection
with the issue or sale of any Notes in circumstances in which section 21(1) of the FSMA does not apply
to the Issuer or the Guarantor; and
•
it has complied and will comply with all applicable provisions of the FSMA with respect to anything
done by it in relation to the Notes in, from or otherwise involving the United Kingdom.
Hong Kong
Each Initial Purchaser has represented and agreed that:
•
it has not offered or sold and will not offer or sell in Hong Kong, by means of any document, any Notes
other than (i) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571)
of Hong Kong and any rules made under that ordinance; or (ii) in other circumstances which do not
result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32) of Hong
Kong or which do not constitute an offer to the public within the meaning of that ordinance; and
•
it has not issued or had in its possession for the purposes of issue, and will not issue or have in its
possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation
or document relating to the Notes, which is directed at, or the contents of which are likely to be accessed
or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong
Kong) other than with respect to Notes which are or are intended to be disposed of only to persons
214
outside Hong Kong or only to “professional investors” as defined in the Securities and Futures
Ordinance and any rules made under that ordinance.
Japan
The Notes have not been and will not be registered under the Securities and Exchange Law of Japan (the
“Securities and Exchange Law”) and each Initial Purchaser has agreed that it will not offer or sell any Notes,
directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means
any personresident in Japan, including any corporation or other entity organized under the laws of Japan), or to
others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an
exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange
Law and any other applicable laws, regulations and ministerial guidelines of Japan.
Singapore
This offering memorandum has not been registered as a prospectus with the Monetary Authority of
Singapore. Accordingly, this offering memorandum and any other document or material in connection with the
offer or sale, or invitation for subscription or purchase, of the Notes may not be circulated or distributed, nor may
the notes be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly
or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities
and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person, or any person pursuant to
Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise
pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.
Where the Notes are subscribed or purchased under Section 275 by a relevant person which is: (a) a
corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire
share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust
(where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is
an accredited investor, shares, debentures and units of shares and debentures of that corporation or the
beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that
trust has acquired the notes under Section 275 except: (1) to an institutional investor under Section 274 of the
SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions,
specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of
law.
Other Relationships
Some of the Initial Purchasers and their affiliates have engaged in, and may in the future engage in,
investment banking and other commercial dealings in the ordinary course of business with the Guarantor and its
subsidiaries and affiliates, including the Issuer.
215
TRANSFER RESTRICTIONS
Offers and Sales
The Notes have not been and will not be registered under the Securities Act and may not be offered or sold
in the United States except pursuant to an effective registration statement or in a transaction not subject to the
registration requirements under the Securities Act or in accordance with an applicable exemption from the
registration requirements thereof. Accordingly, the Notes are being offered and sold hereunder only:
•
inside the United States or to U.S. persons (as defined under Regulation S), to Qualified Institutional
Buyers (“QIBs” and each, a “QIB”) pursuant to Rule 144A; and
•
outside the United States to non-U.S. persons, or for the account or benefit of non-U.S. persons, in
offshore transactions in reliance upon Regulation S.
Any offer or sale of the Notes in the United States in reliance on Rule 144A or another exemption from the
registration requirements of the Securities Act will be made by broker-dealers who are registered as such under
the Exchange Act.
Until the expiration of 40 days after the later of the commencement of the offering of the Notes and the
original issue or sale date of the Notes, an offer or sale of the Notes within the United States by a dealer may
violate the registration requirements of the Securities Act if such offer or sale is made otherwise than pursuant to
an exemption from registration under the Securities Act.
Rule 144A Global Notes
Each purchaser of Notes within the United States will be deemed by its acceptance of the Notes to have
represented and agreed on its behalf and on behalf of any investor accounts for which it is purchasing the Notes,
that neither the Issuer nor the Guarantor or the Initial Purchasers, nor any person acting on their behalf, has made
any representation to it with respect to the offering or sale of any Notes, other than the information contained in
this offering memorandum, which offering memorandum has been delivered to it and upon which it is solely
relying in making its investment decision with respect to the Notes, has had access to such financial and other
information concerning E.ON and the Notes as it has deemed necessary in connection with its decision to
purchase any of the Notes, and that:
(i) the purchaser is not an affiliate of E.ON or a person acting on behalf of E.ON or on behalf of such
affiliate; and it is not in the business of buying and selling securities or, if it is in such business, it did not
acquire the Notes from E.ON or an affiliate thereof in the initial distribution of the Notes;
(ii) the purchaser acknowledges that the Notes have not been and will not be registered under the
Securities Act or with any securities regulatory authority of any state of the United States and are subject to
significant restrictions on transfer;
(iii) the purchaser (i) is a QIB, (ii) is aware that the sale to it is being made in reliance on Rule 144A or
another exemption from, or in a transaction not subject to, the registration requirements of the Securities
Act, and (iii) is acquiring such Notes for its own account or for the account of a QIB, in each case for
investment and not with a view to, or for offer or sale in connection with, any resale or distribution of the
Notes in violation of the Securities Act or any state securities laws;
(iv) the subscriber or purchaser is aware that the Notes are being offered in the United States in a
transaction not involving any public offering in the United States within the meaning of the Securities Act;
(v) if, prior to the date that is one year after the later of the date (the “Resale Restriction Termination
Date”) of the commencement of sales of the Notes and the last date on which the Notes were acquired from
the Issuer or any of the Issuer’s affiliates in the offering the purchaser decides to offer, resell, pledge or
otherwise transfer such Notes, such Notes may be offered, sold, pledged or otherwise transferred only (i) to
216
a person whom the beneficial owner and/or any person acting on its behalf reasonably believes is a QIB in a
transaction meeting the requirements of Rule 144A, (ii) in accordance with Regulation S, (iii) in accordance
with Rule 144 (if available), (iv) in accordance with an effective registration statement under the Securities
Act, or (v) pursuant to any other available exemption from the registration requirements of the Securities
Act in each case in accordance with any applicable securities laws of any state of the United States or any
other jurisdiction and agrees to give any subsequent purchaser of such Notes notice of any restrictions on the
transfer thereof;
(vi) the Notes have not been offered to it by means of any general solicitation or general advertising;
(vii) the Notes are “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act
and no representation is made as to the availability of the exemption provided by Rule 144 under the
Securities Act for resales of any such Notes;
(viii) The Notes, unless otherwise determined by the Issuer in accordance with applicable law, will bear
a legend to the following effect:
THE NOTES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE UNITED
STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY STATE
SECURITIES LAWS. OWNERSHIP INTERESTS IN THE NOTES MAY NOT BE OFFERED, SOLD,
PLEDGED OR OTHERWISE TRANSFERRED (I) WITHIN THE UNITED STATES TO, OR FOR THE
ACCOUNT OR BENEFIT OF, PERSONS OTHER THAN “QUALIFIED INSTITUTIONAL BUYERS”
(AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN TRANSACTIONS EXEMPT FROM
THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND (II) OUTSIDE THE
UNITED STATES OTHER THAN TO PERSONS WHO ARE NOT U.S. PERSONS IN OFFSHORE
TRANSACTIONS EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES
ACT PURSUANT TO RULE 903 OR RULE 904 OF REGULATION S THEREOF. EACH PERSON
ACQUIRING AN OWNERSHIP INTEREST IN THE NOTES EVIDENCED HEREBY (1) SHALL BE
DEEMED TO REPRESENT AND WARRANT THAT IT IS EITHER (A) A “QUALIFIED
INSTITUTIONAL BUYER” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) OR (B) IS
NOT A U.S. PERSON (AS DEFINED IN REGULATION S) AND IS OUTSIDE THE UNITED STATES;
(2) AGREES THAT IT WILL NOT RESELL OR OTHERWISE TRANSFER THE NOTE EVIDENCED
HEREBY EXCEPT IN ACCORDANCE WITH THE FOREGOING RESTRICTIONS, AND IN ANY
CASE IN COMPLIANCE WITH ALL APPLICABLE SECURITIES LAWS OF ANY STATE OF THE
UNITED STATES AND ANY OTHER APPLICABLE JURISDICTION; (3) PRIOR TO SUCH
TRANSFER, AGREES THAT IT WILL FURNISH TO HSBC BANK USA, N.A., AS REGISTRAR (OR A
SUCCESSOR REGISTRAR, AS APPLICABLE), SUCH CERTIFICATIONS, LEGAL OPINIONS OR
OTHER INFORMATION AS THE REGISTRAR MAY REASONABLY REQUIRE TO CONFIRM THAT
SUCH TRANSFER IS BEING MADE PURSUANT TO AN EXEMPTION FROM, OR IN A
TRANSACTION NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES
ACT AND (4) AGREES THAT IT WILL DELIVER TO EACH PERSON TO WHOM THE NOTE
EVIDENCED HEREBY IS TRANSFERRED A NOTICE SUBSTANTIALLY TO THE EFFECT OF THIS
LEGEND. AS USED HEREIN, THE TERMS “UNITED STATES”, “U.S. PERSON” AND “OFFSHORE
TRANSACTION” HAVE THE MEANINGS GIVEN TO THEM BY REGULATION S UNDER THE
SECURITIES ACT; and
(ix) the Company shall not recognize any offer, sale, pledge or other transfer of the Notes made other
than in compliance with the above-stated restrictions.
Terms defined in Rule 144A shall have the same meaning when used in the foregoing sections (i)-(ix).
Each purchaser acknowledges that the Issuer, the Guarantor and the Initial Purchasers will rely upon the
truth and accuracy of the foregoing acknowledgements, representations and agreements, and agrees that if any of
the acknowledgements, representations or warranties deemed to have been made by such purchaser by its
purchase of Notes are no longer accurate, it shall promptly notify the Issuer, the Guarantor and the Initial
Purchasers; if they are acquiring any Notes offered hereby as a fiduciary or agent for one or more investor
217
accounts, each purchaser represents that they have sole investment discretion with respect to each such account
and full power to make the foregoing acknowledgements, representations and agreements on behalf of each such
account.
Each purchaser of the Notes will be deemed by its acceptance of the Notes to have represented and agreed
that it is purchasing the Notes for its own account, or for one or more investor accounts for which it is acting as a
fiduciary or agent, in each case for investment, and not with a view to, or for offer or sale in connection with, any
distribution thereof in violation of the Securities Act or any state securities laws, subject to any requirement of
law that the disposition of its property or the property of such investor account or accounts be at all times within
its or their control and subject to its or their ability to resell such Notes pursuant to Rule 144A, Regulation S or
any other exemption from registration available under the Securities Act.
The Issuer and the Guarantor recognize that none of DTC, Euroclear nor Clearstream in any way undertakes
to, and none of DTC, Euroclear nor Clearstream have any responsibility to, monitor or ascertain the compliance
of any transactions in the Notes with any exemptions from registration under the Securities Act or any other state
or federal securities law.
Regulation S Global Notes
Each purchaser of Notes outside the United States pursuant to Regulation S will be deemed by its
acceptance of the Notes to have represented and agreed, on its behalf and on behalf of any investor accounts for
which it is purchasing the Notes, that neither the Issuer nor the Guarantor or the Initial Purchasers, nor any
person acting on their behalf, has made any representation to it with respect to the offering or sale of any Notes,
other than the information contained in this offering memorandum, which offering memorandum has been
delivered to it and upon which it is solely relying in making its investment decision with respect to the Notes, has
had access to such financial and other information concerning the E.ON and the Notes as it has deemed necessary
in connection with its decision to purchase any of the Notes, and that:
(i) the purchaser understands and acknowledges that the Notes have not been and will not be registered
under the Securities Act, or with any securities regulatory authority of any state of the United States, and
may not be offered, sold or otherwise transferred except in compliance with the registration requirements of
the Securities Act or any other applicable securities law, pursuant to an exemption therefrom or in any
transaction not subject thereto;
(ii) the purchaser, and the person, if any, for whose account or benefit the purchaser is acquiring the
Notes, is not a U.S. person and is acquiring the Notes in an “offshore transaction” meeting the requirements
of Regulation S and was located outside the United States at the time the buy order for the Shares was
originated and continues to be outside of the United States and has not purchased the Notes for the account
or benefit of any U.S. person or entered into any arrangement for the transfer of the Notes to any U.S. erson;
(iii) the purchaser is aware of the restrictions on the offer and sale of the Notes pursuant to Regulation
S described in this offering memorandum and agrees to give any subsequent purchaser of such Notes notice
of any restrictions on the transfer thereof;
(iv) the Notes have not been offered to it by means of any “directed selling efforts” as defined in
Regulation S; and
(v) E.ON shall not recognize any offer, sale, pledge or other transfer of the Notes made other than in
compliance with the above-stated restrictions.
Terms defined in Regulation S shall have the same meaning when used in the foregoing sections (i)-(v).
218
Unless we determine otherwise in compliance with applicable law, the Regulation S notes will bear the
following restrictive legend and may not be transferred otherwise than in accordance with the transfer restrictions
set forth in such legend:
THE NOTES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE UNITED
STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY STATE
SECURITIES LAWS. OWNERSHIP INTERESTS IN THE NOTES MAY NOT BE OFFERED, SOLD,
PLEDGED OR OTHERWISE TRANSFERRED (I) WITHIN THE UNITED STATES TO, OR FOR THE
ACCOUNT OR BENEFIT OF, PERSONS OTHER THAN “QUALIFIED INSTITUTIONAL BUYERS” (AS
DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN TRANSACTIONS EXEMPT FROM THE
REGISTRATION REQUIREMENTS OF THE SECURITIES ACT, PROVIDED THAT SUCH TRANSFER
DOES NOT OCCUR PRIOR TO 40 DAYS AFTER THE LATER OF THE ANNOUNCEMENT OF THE
OFFERING OF THE NOTES AND THE ISSUE DATE FOR THE NOTES OR (II) OUTSIDE THE UNITED
STATES OTHER THAN TO PERSONS WHO ARE NOT U.S. PERSONS IN OFFSHORE TRANSACTIONS
EXEMPT FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT PURSUANT TO
RULE 903 OR RULE 904 OF REGULATION S THEREOF. EACH PERSON ACQUIRING AN OWNERSHIP
INTEREST IN THE NOTES EVIDENCED HEREBY AS PART OF THE INITIAL DISTRIBUTION SHALL
BE DEEMED TO REPRESENT AND WARRANT THAT IT IS (A) NOT A U.S. PERSON AND
(B) ACQUIRING THE NOTES IN AN “OFFSHORE TRANSACTION” AS DEFINED IN RULE 902(H)
UNDER THE SECURITIES ACT OUTSIDE THE UNITED STATES. EACH PERSON ACQUIRING AN
OWNERSHIP INTEREST IN THE NOTES EVIDENCED HEREBY (1) AGREES THAT IT WILL NOT
RESELL OR OTHERWISE TRANSFER THE NOTES EVIDENCED HEREBY EXCEPT IN ACCORDANCE
WITH THE FOREGOING RESTRICTIONS IN I AND II ABOVE, AND IN ANY CASE IN COMPLIANCE
WITH ALL APPLICABLE JURISDICTION AND (2) AGREES, PRIOR TO SUCH TRANSFER, TO
FURNISH TO HSBC BANK USA, N.A., AS REGISTRAR (OR A SUCCESSOR REGISTRAR, AS
APPLICABLE), SUCH CERTIFICATIONS, LEGAL OPINIONS OR OTHER INFORMATION AS THE
REGISTRAR MAY REASONABLY REQUIRE TO CONFIRM THAT SUCH TRANSFER IS BEING MADE
PURSUANT TO AN EXEMPTION FROM, OR IN A TRANSACTION NOT SUBJECT TO, THE
REGISTRATION REQUIREMENTS OF THE SECURITIES ACT. AS USED HEREIN, THE TERMS
“UNITED STATES”, “U.S. PERSON” AND “OFFSHORE TRANSACTION” HAVE THE MEANINGS
GIVEN TO THEM BY REGULATION S UNDER THE SECURITIES ACT.
219
LEGAL MATTERS
Certain legal matters in connection with the offering of the Notes will be passed upon for us by Shearman &
Sterling LLP, German and U.S. counsel to us and the Issuer, and by Clifford Chance LLP, Dutch counsel to us
and the Issuer. Certain legal matters will be passed upon for the Initial Purchasers by Cleary Gottlieb Steen &
Hamilton LLP, U.S. and German counsel to the Initial Purchasers.
220
INDEPENDENT ACCOUNTANTS
The consolidated financial statements of E.ON AG and its subsidiaries as of December 31, 2007 prepared in
accordance with IFRS as adopted by the European Union, which are included herein, have been audited by
PricewaterhouseCoopers Aktiengesellschaft Wirtschaftsprüfungsgesellschaft (“PwC”), independent accountants,
as stated in their report appearing herein.
The consolidated financial statements of E.ON AG and the subsidiaries as of December 31, 2006 and 2005 and
for each of the three years in the period ended December 31, 2006, prepared in accordance with U.S. GAAP
incorporated by reference in this offering memorandum have been audited by PricewaterhouseCoopers
Aktiengesellschaft Wirtschaftsprufungsgesellschaft, independent registered public accounting firm, as stated in their
report.
The audit report of PwC for E.ON AG as of December 31, 2007 refers to a group management report that
has not been included in the offering memorandum. The examination of and the audit report upon such group
management report are required under German generally accepted auditing standards. This examination was not
made in accordance with generally accepted auditing or attestation standards in the United States. Accordingly,
PwC does not express any opinion on this information or on the consolidated financial statements prepared in
accordance with IFRS as adopted by the European Union included in this offering memorandum, in each case in
accordance with U.S. generally accepted auditing standards or U.S. attestation standards.
221
LIMITATIONS ON ENFORCEMENT OF U.S. LAWS AGAINST THE GUARANTOR,
THE ISSUER, THEIR MANAGEMENT, AND OTHERS
The Guarantor is a stock corporation (Aktiengesellschaft) organized under the laws of Germany, and the
Issuer is a wholly-owned subsidiary of the Guarantor organized under the laws of The Netherlands. None of the
members of the managing board (Vorstand) and the supervisory board (Aufsichtsrat) of the Guarantor and its
independent auditors named in this offering memorandum and none of the members of the board of managing
directors (bestuur) of the Issuer are residents of the U.S. All or a substantial portion of the assets of these
individuals and of the Guarantor and the Issuer are located outside the U.S. As a result, it may not be possible for
you to effect service of process within the U.S. upon these individuals or upon the Guarantor or the Issuer or to
enforce judgments obtained in U.S. courts based on the civil liability provisions of the U.S. securities laws
against these individuals, the Guarantor or the Issuer outside the U.S. Awards of punitive damages in actions
brought in the U.S. or elsewhere may be unenforceable in Germany and also in The Netherlands. In addition,
actions brought in a German court against the Guarantor or the members of its managing board to enforce
liabilities based on U.S. federal securities laws may be subject to certain restrictions; in particular, a German
court may not award punitive damages.
The U.S. and Germany currently do not have a treaty providing for recognition and enforcement of
judgments (other than arbitration awards) in civil and commercial matters. Therefore, a final judgment for the
payment of money rendered by any federal or state court in the U.S. based on civil liability, whether or not
predicated solely upon U.S. federal or state securities laws, would not be automatically enforceable in Germany
also. A final judgment by a U.S. federal or state court, however, may be recognized and enforced in Germany in
an action before a court of competent jurisdiction in accordance with the proceedings set forth by the German
Code of Civil Procedure (Zivilprozessordnung). In such an action, a German court will generally not
reinvestigate the merits of the original matter decided by a U.S. court, except as noted below. The recognition
and enforcement of the U.S. judgment by a German court is conditional upon a number of factors, including the
following:
•
the judgment being final under U.S. law;
•
the U.S. courts having had jurisdiction over the original proceeding in accordance with German law;
•
the defendant having had the chance to defend herself or himself against an unduly or untimely served
complaint;
•
the judgment of the U.S. court being compatible with the judgment rendered by a German court or a
prior judgment of a foreign court to be recognized;
•
the procedure underlying the judgment of the U.S. court being compatible with a procedure in Germany
that has been pending prior thereto;
•
the results of a recognition of the judgment of the U.S. court being compatible with the substantial
principles of German law, in particular with the civil liberties (Grundrechte) guaranteed by virtue of the
German Constitution (Grundgesetz); and
•
the guarantee of reciprocity.
Subject to the foregoing, purchasers of securities may be able to enforce judgments in civil and commercial
matters obtained from U.S. federal or state courts in Germany. We cannot, however, assure you that attempts to
enforce judgments in Germany will be successful.
The U.S. and The Netherlands currently do not have a treaty providing for recognition and enforcement of
judgments (other than arbitration awards) in civil and commercial matters. Therefore, a final judgment for the
payment of money rendered by any federal or state court in the U.S. based on civil liability, whether or not
predicated solely upon U.S. federal or state securities laws, would not be automatically enforceable in The
222
Netherlands and new proceedings on the merits must be initiated before a competent Dutch court. However, if
the party in whose favor such final judgment is rendered brings a new suit in a competent court in The
Netherlands such party may submit to a Dutch court the final judgment that has been rendered in the U.S. and
such court will have discretion to attach such weight to its judgment as it deems appropriate. According to
current practice, however, based upon case law, Dutch courts will generally render a judgment in accordance
with the U.S. judgment, if and to the extent that the following conditions are met:
•
the U.S. court rendering the judgment had jurisdiction over the subject matter of the litigation on
internationally acceptable grounds (e.g., if the parties have agreed, for example in a written contract, to
submit their disputes to the foreign court) and has conducted the proceedings in accordance with
generally accepted principles of fair trials (e.g., after proper service of process, giving the defendant
sufficient time to prepare for the litigation);
•
the U.S. judgment is final and definite; and
•
such recognition is not in conflict with an existing Dutch judgment or with Dutch public policy (i.e. a
fundamental principle of Dutch law).
223
GENERAL INFORMATION ABOUT THE ISSUER
The Issuer was incorporated in Amsterdam on November 14, 1983 under the name, VEBA International
Finance B.V., under the laws of The Netherlands as a private limited liability company (besloten vennootschap met
beperkte aansprakelijkheid) with an unlimited corporate duration. VEBA International Finance B.V. was renamed
E.ON International Finance B.V. on September 26, 2000. It has its statutory seat in Amsterdam. Its registered office
is at Capelseweg 400, 3068 AX Rotterdam, The Netherlands (telephone: +31 10 289 50 89), where it is registered in
the commercial register of the Chamber of Commerce and Industry under number 33174429.
Business Overview
The principal activity of the Issuer is the financing of E.ON Group entities.
Ownership
The Issuer is a direct wholly-owned subsidiary of E.ON AG.
Trend Information
There has been no material adverse change in the prospects of the Issuer since the date of its last published
audited financial statements (December 31, 2007). No developments are currently foreseen that are reasonably
likely to have a material effect on the Issuer’s prospects.
Administrative, Management and Supervisory Bodies
Managing Board
At present, the managing board consists of the following members:
•
Marcus Andreas Stefan Bokelmann, Rotterdam, Managing Director of E.ON Benelux Holding B.V.
•
Johannes Casparus Petrus Schoenmakers, Schiedam, General Council of E.ON Benelux Holding B. V.
•
Jan Trapman, Sliedrecht, Manager Treasury Controlling of E.ON Benelux N. V.
Supervisory Board
At present, the supervisory board consists of the following members:
•
Dr. Verena Volpert, Germany, Senior Vice President Finance of E.ON AG
•
Graham Wood, London, UK
•
David Beynon, London, UK, Tax advisor of E.ON AG
The members of the managing and the supervisory boards can be contacted at the Issuer’s business address:
Capelseweg 400, 3068 AX Rotterdam, The Netherlands.
None of the above members of the managing board and the supervisory board have declared any potential
conflict of interest between any duties to the Issuer and their private interests or other duties.
Board Practices
The Issuer has not instituted a separate audit committee.
The Issuer, as a privately held company, is not subject to public corporate governance standards.
Legal and arbitration proceedings
As of the date of this offering memorandum, the Issuer is, not nor has it been during the past two fiscal
years, engaged in any governmental, legal or arbitration proceedings which may have or have had during such
period a significant effect on its or the E.ON Group’s financial position or profitability, nor as far as the Issuer is
aware, are any such governmental, legal or arbitration proceedings pending or threatened.
224
INDEX TO FINANCIAL STATEMENTS
Page
Independent Auditors Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-2
Consolidated Statements of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-3
Consolidated Balance Sheets—Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-4
Consolidated Balance Sheets—Equity and Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-5
Consolidated statements of Recognized Income and Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-6
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-7
Statements of Changes in Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-8
Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-10
F-1
The auditor’s report issued in accordance with Section 322 German Commercial Code and in German
language relates to the IFRS Consolidated Financial Statements of E.ON AG for the 2007 fiscal year which
follow, as well as to the group management report of E.ON AG prepared in the German language for the 2007
fiscal year. The group management report is not reprinted in this offering memorandum.
INDEPENDENT AUDITOR’S REPORT
We have audited the Consolidated Financial Statements prepared by E.ON AG, Düsseldorf, Germany,
comprising the balance sheet, the income statement, the statement of recognized income and expenses, the cash
flow statement and the notes to the financial statements, together with the Group Management Report, which has
been combined with the management report for E.ON AG, for the fiscal year from January 1 through
December 31, 2007. The preparation of the Consolidated Financial Statements and of the Combined
Management Report in accordance with the IFRS applicable to financial reporting as adopted by the EU and in
accordance with the additional requirements pursuant to Article 315a (1) of the German Commercial Code
(HGB) is the responsibility of the Company’s Board of Management. Our responsibility is to express an opinion
on the Consolidated Financial Statements and on the Combined Management Report based on our audit.
We conducted our audit of the Consolidated Financial Statements in accordance with Article 317 HGB and
the German generally accepted standards for the audit of financial statements promulgated by the Institut der
Wirtschaftsprüfer (Institute of Public Auditors in Germany) (IDW), with additional consideration given to the
International Standards on Auditing (ISA). Those standards require that we plan and perform the audit in such a
way as to ensure that misstatements materially affecting the presentation of the net assets, financial position and
results of operations in the Consolidated Financial Statements in accordance with the applicable financial
reporting framework and in the Group Management Report are detected with reasonable assurance. Knowledge
of the business activities and the economic and legal environment of the Group and expectations as to possible
misstatements are taken into account in the determination of audit procedures. The effectiveness of the
accounting-related internal control system and the evidence supporting the disclosures in the Consolidated
Financial Statements and the Group Management Report are examined primarily on a test basis within the
framework of the audit. The audit includes assessing the annual financial statements of those entities included in
consolidation, the determination of entities to be included in consolidation, the accounting and consolidation
principles used and significant estimates made by the Board of Management, as well as evaluating the overall
presentation of the Consolidated Financial Statements and Group Management Report. We believe that our audit
provides a reasonable basis for our opinion.
Our audit has not led to any reservations.
In our opinion, based on the findings of our audit, the Consolidated Financial Statements are in compliance
with the IFRS applicable to financial reporting as adopted by the EU and with the additional requirements
pursuant to Article 315a (1) HGB, and give a true and fair view of the net assets, financial position and results of
operations of the Group in accordance with these requirements. The Combined Group Management Report is
consistent with the Consolidated Financial Statements and, as a whole, provides an appropriate view of the
Group’s position and appropriately presents the opportunities and risks of future development.
Düsseldorf, February 20, 2008
PricewaterhouseCoopers Aktiengesellschaft
Wirtschaftsprüfungsgesellschaft
Dr. Norbert Vogelpoth
Wirtschaftsprüfer
(German Public Auditor)
Dr. Norbert Schwieters
Wirtschaftsprüfer
(German Public Auditor)
F-2
E.ON AG AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
€ in millions
Notes
Sales including electricity and energy taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electricity and energy taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in inventories (finished goods and work in progress) . . . . . . . . . . . . . . . . . . .
Own work capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Personnel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, amortization and impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/Loss (–) from companies accounted for under the equity method . . . . . . . . . .
Income/Loss (–) from continuing operations before financial results and income
taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from other securities, interest and similar income . . . . . . . . . . . . . . . . . .
Interest and similar expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
70,761
(2,030)
(5)
(6)
(7)
(8)
(11)
(7)
2006
67,653
(3,562)
68,731 64,091
22
8
517
395
7,776
7,914
(50,223) (46,708)
(4,597) (4,529)
(3,194) (3,670)
(9,724) (11,907)
1,147
748
(33)
(9)
10,455
(772)
179
1,035
(1,986)
6,342
(995)
50
1,169
(2,214)
(10)
(2,289)
(40)
Income/Loss (–) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/Loss (–) from discontinued operations, net . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
(4)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,394
5,307
330
775
7,724
7,204
520
6,082
5,586
496
10.55
0.51
7.31
1.16
11.06
8.47
in €
Earnings per share (attributable to shareholders of E.ON AG)—basic and
diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
from net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-3
(13)
E.ON AG AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS—ASSETS
December 31
€ in millions
Notes
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Companies accounted for under the equity method . . . . . . . . . . . . . . . . . .
Other financial assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-current securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial receivables and other financial assets . . . . . . . . . . . . . . . . . . . . .
Operating receivables and other operating assets . . . . . . . . . . . . . . . . . . . .
Income tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(14a)
(14a)
(14b)
(15)
(15)
2007
2006
January 1
2006
16,761
4,284
48,552
8,411
21,478
14,583
6,895
2,449
680
2,034
1,155
15,320
3,894
42,484
7,770
20,679
13,533
7,146
2,631
373
2,090
1,247
15,494
4,207
41,067
9,507
16,544
10,073
6,471
3,268
1,736
1
2,108
105,804
96,488
93,932
3,811
1,515
17,973
539
7,075
3,888
300
2,887
577
4,199
1,477
18,057
554
6,189
4,448
587
1,154
611
2,587
1,090
17,088
874
9,901
5,455
98
4,348
682
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31,490
31,087
32,222
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,294
127,575
126,154
(17)
(17)
(10)
Non-current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial receivables and other financial assets . . . . . . . . . . . . . . . . . . . . .
Trade receivables and other operating assets . . . . . . . . . . . . . . . . . . . . . . . .
Income tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquid funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Securities and fixed-term deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-4
(16)
(17)
(17)
(18)
(4)
E.ON AG AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS—EQUITY AND LIABILITIES
December 31
€ in millions
Notes
Capital stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification related to put options on treasury shares . . . . . . . . . . . . . .
2007
2006
January 1
2006
(19)
(20)
(21)
(22)
(19)
(19)
1,734
11,825
26,828
10,656
(616)
(1,053)
1,799
11,760
24,350
11,033
(230)
—
1,799
11,749
22,910
8,150
(256)
—
Equity attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . .
Minority interests (before reclassification) . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification related to put options . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(26)
49,374
6,281
(525)
48,712
4,994
(2,461)
44,352
4,747
(3,130)
Minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(23)
5,756
2,533
1,617
55,130
15,915
5,432
2,537
2,890
18,073
7,555
51,245
10,029
5,422
2,333
3,962
18,138
7,063
45,969
10,985
5,666
1,134
9,768
18,009
7,625
52,402
5,549
18,254
1,354
3,992
613
46,947
3,443
19,578
1,753
3,994
615
53,187
3,455
18,296
1,859
2,552
836
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29,762
29,383
26,998
Total equity and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,294
127,575
126,154
Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provisions for pensions and similar obligations . . . . . . . . . . . . . . . . . . . . .
Miscellaneous provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade payables and other operating liabilities . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities associated with assets held for sale . . . . . . . . . . . . . . . . . . . . . .
F-5
(26)
(26)
(24)
(25)
(10)
(26)
(26)
(25)
(4)
E.ON AG AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RECOGNIZED INCOME AND EXPENSES
€ in millions
2007
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,724
Cash flow hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments recognized in income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(81)
(82)
1
2006
6,082
(276)
(302)
26
Available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
261 3,776
Unrealized changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,183 4,202
Reclassification adjustments recognized in income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (922) (426)
Currency translation adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments recognized in income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(966)
(966)
0
145
9
136
Changes in actuarial gains/losses of defined benefit pension plans and similar obligations . . . . . .
852
781
Deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(23)
(862)
Total income and expenses recognized directly in equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43
3,564
Total recognized income and expenses (total comprehensive income) . . . . . . . . . . . . . . . . . . . 7,767
Attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,370
Attributable to minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
397
9,646
8,937
709
F-6
E.ON AG AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
€ in millions
2007
2006
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,724
6,082
Income from discontinued operations, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, amortization and impairment of intangible assets and of property, plant and equipment . . . .
Changes in provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-cash income and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(330)
3,194
(146)
(35)
(111)
(775)
3,670
1,284
(465)
62
Gain/Loss on disposal of . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets and property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Securities (> 3 months) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,502)
(52)
(444)
(1,006)
(950)
(95)
(362)
(493)
Changes in operating assets and liabilities and in income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating receivables and income tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade payables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating liabilities and income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(68)
321
455
(724)
(958)
838
(1,747)
(1,673)
(1,516)
462
73
907
Cash provided by operating activities of continuing operations (operating cash flow) . . . . . . . . . . . .
8,726
7,161
Proceeds from disposal of . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets and property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,431
293
1,138
3,877
303
3,574
Purchase of investments in . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets and property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from disposal of securities (> 3 months) and of financial receivables and fixed-term deposits . .
Purchase of securities (> 3 months) and of financial receivables and fixed-term deposits . . . . . . . . . . . . . .
Changes in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(11,306) (5,037)
(6,916) (4,096)
(4,390)
(941)
9,914
6,899
(9,114) (10,042)
286
(154)
Cash used for investing activities of continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments received/made from changes in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments for treasury shares, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Premiums received for put options on treasury shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends paid to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends paid to minority shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of financial liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(8,789) (4,457)
55
(1)
(3,500)
28
64
0
(2,210) (4,614)
(237)
(244)
12,533 10,845
(4,897) (11,874)
Cash provided by (used for) financing activities of continuing operations . . . . . . . . . . . . . . . . . . . . . .
1,808
(5,860)
Net increase (decrease) in cash and cash equivalents from continuing operations . . . . . . . . . . . . . . . .
Cash provided by operating activities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash used for investing activities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash provided by financing activities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,745
12
(12)
0
(3,156)
69
(109)
2
Net increase (decrease) in cash and cash equivalents from discontinued operations . . . . . . . . . . . . . .
Effect of foreign exchange rates on cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at the beginning of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0
(12)
1,154
(38)
0
4,348
Cash and cash equivalents at the end of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplementary Information on Cash Flows from Operating Activities
Income taxes paid (less refunds) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,887
1,154
(1,822)
(1,134)
814
1,325
(840)
(1,029)
584
1,079
F-7
E.ON AG AND SUBSIDIARIES
STATEMENT OF CHANGES IN EQUITY
Accumulated other comprehensive income
€ in millions
Capital
stock
Additional
paid-in
capital
Retained
earnings
Currency
translation
adjustment
Balance as of January 1, 2006 . . . . . . . . . .
1,799
11,749
22,910
675
7,343
132
(43)
3,148
(222)
(43)
3,148
(222)
Treasury shares repurchased/sold . . . . . . . .
Dividends paid . . . . . . . . . . . . . . . . . . . . . . .
Other changes . . . . . . . . . . . . . . . . . . . . . . .
Net additions/disposals from the
reclassification related to put options . . .
Availablefor-sale
securities
Cash flow
hedges
11
(4,614)
Total comprehensive income . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . .
Changes in actuarial gains/ losses of
defined benefit pension plans and
similar obligations . . . . . . . . . . . . . .
Other comprehensive income . . . . . . .
6,054
5,586
468
Balance as of December 31, 2006 . . . . . . .
1,799
11,760
24,350
632
10,491
(90)
Balance as of January 1, 2007 . . . . . . . . . .
1,799
11,760
24,350
632
10,491
(90)
590
(17)
Changes in scope of consolidation . . . . . . .
Treasury shares repurchased/sold . . . . . . . .
Capital increase . . . . . . . . . . . . . . . . . . . . . .
Capital decrease . . . . . . . . . . . . . . . . . . . . . .
Dividends paid . . . . . . . . . . . . . . . . . . . . . . .
Other changes . . . . . . . . . . . . . . . . . . . . . . .
Net additions/disposals from the
reclassification related to put options . . .
(65)
65
56
Total comprehensive income . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . .
Changes in actuarial gains/ losses of
defined benefit pension plans and
similar obligations . . . . . . . . . . . . . .
Other comprehensive income . . . . . . .
Balance as of December 31, 2007 . . . . . . .
(3,115)
(2,210)
7,747
7,204
(950)
543
1,734
11,825
F-8
26,828
(950)
590
(17)
(318)
11,081
(107)
Treasury
shares
(256)
Put options
on treasury
shares
0
26
Equity
attributable
to shareholders
of E.ON AG
Minority
interests
(before
reclassification)
Reclassification
related to
put options
Minority
interests
Total
44,352
4,747
(3,130)
1,617
45,969
37
(4,614)
(244)
(218)
(244)
(218)
669
37
(4,858)
(218)
669
669
8,937
5,586
709
496
709
496
9,646
6,082
468
2,883
35
178
35
178
503
3,061
(230)
0
48,712
4,994
(2,461)
2,533
51,245
(230)
0
48,712
4,994
(2,461)
2,533
51,245
1,067
1,067
(386)
180
(3,179)
(2,447)
(56)
1,067
(386)
(386)
(3,115)
(2,210)
(1,053)
(997)
7,370
7,204
543
(377)
(616)
(1,053)
180
(64)
(237)
(56)
49,374
180
(64)
(237)
(56)
1,936
1,936
939
397
520
397
520
7,767
7,724
66
(189)
66
(189)
6,281
F-9
(525)
5,756
609
(566)
55,130
E.ON AG AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(1)
BASIS OF PRESENTATION
Based in Germany, the E.ON Group (“E.ON” or the “Group”) is an international group of companies with
integrated electricity and gas operations. The E.ON Group’s reporting segments are presented in line with the
Group’s internal organizational and reporting structure:
•
The Central Europe market unit, led by E.ON Energie AG (“E.ON Energie”), Munich, Germany,
operates E.ON’s integrated electricity business and the downstream gas business in Central Europe.
•
Pan-European Gas is responsible for the upstream and midstream gas business. Moreover, this market
unit holds predominantly minority shareholdings in the downstream gas business. This market unit is led
by E.ON Ruhrgas AG (“E.ON Ruhrgas”), Essen, Germany.
•
The U.K. market unit encompasses the integrated energy business in the United Kingdom. This market
unit is led by E.ON UK plc (“E.ON UK”), Coventry, U.K.
•
The Nordic market unit, which is led by E.ON Nordic AB (“E.ON Nordic”), Malmö, Sweden, focuses
on the integrated energy business in Northern Europe. It operates through the integrated energy
company E.ON Sverige AB (“E.ON Sverige”), Malmö, Sweden.
•
The U.S. Midwest market unit, led by E.ON U.S. LLC (“E.ON U.S.”), Louisville, Kentucky, U.S., is
primarily active in the regulated energy market in the U.S. state of Kentucky.
•
Corporate Center/New Markets contains those interests held directly by E.ON AG (“E.ON” or the
“Company”), including the operations acquired in Russia and those in the area of renewable energy (see
Note 4), as well as E.ON AG itself and the consolidation effects that take place at the Group level.
The market units and Corporate Center/New Markets are the reportable segments as defined by International
Financial Reporting Standard (“IFRS”) 8, “Operating Segments” (“IFRS 8”).
Note 33 provides additional information about the market units.
With European Union (“EU”) Regulation 1606/2002 dated July 19, 2002, the European Parliament and the
European Council mandated the adoption of IFRS into EU law governing the consolidated financial statements of
publicly traded companies for fiscal years beginning on or after January 1, 2005. However, member states were
permitted to defer mandatory application of IFRS until 2007 for companies that, like E.ON, had been preparing
their consolidated financial statements in accordance with generally accepted accounting principles in the United
States of America (“U.S. GAAP”) and whose stock was officially listed for public trading in a non-EU member
state. In Germany, the Bilanzrechtsreformgesetz (“BilReG”) implemented the option to defer mandatory IFRS
application in October 2004.
E.ON made use of this option and, accordingly, the Consolidated Financial Statements for the year ended
December 31, 2007, contained in this Annual Report have been prepared in accordance with IFRS 1, “First-time
Adoption of International Financial Reporting Standards” (“IFRS 1”). These Consolidated Financial Statements
have been prepared in accordance with Article 315a (1) of the German Commercial Code (“HGB”) and with
those IFRS and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations that had
been adopted by the European Commission for use in the EU as of the end of the fiscal year, and whose
application was mandatory as of December 31, 2007. In addition, E.ON has opted for the voluntary early
adoption of IFRS 8.
The preparation of the Consolidated Financial Statements in accordance with IFRS has led to changes in the
Group’s accounting policies as compared with the accounting principles used in the most recent annual
Consolidated Financial Statements, i.e., U.S. GAAP. The following accounting policies have been applied for all
F-10
periods presented in these Consolidated Financial Statements. They have also been used, in accordance with
IFRS 1, for the preparation of the opening balance sheet under IFRS as of January 1, 2006. The effects of the
transition from U.S. GAAP to IFRS are discussed in Note 35.
(2)
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General Principles
The Consolidated Financial Statements are prepared based on historical cost, with the exception of
available-for-sale financial assets that are recognized at fair value and of financial assets and liabilities (including
derivative financial instruments) that must be recognized in income at fair value.
Scope of Consolidation
The Consolidated Financial Statements incorporate the financial statements of E.ON AG and entities
controlled by E.ON (“subsidiaries”). Control is achieved when the parent company has the power to govern the
financial and operating policies of an entity so as to obtain economic benefits from its activities. In addition,
special purpose entities are consolidated when the substance of the relationship indicates that the entity is
controlled by E.ON.
The results of the subsidiaries acquired or disposed of during the year are included in the Consolidated
Statement of Income from the date of acquisition or until the date of the disposal, respectively.
Where necessary, adjustments are made to the subsidiaries’ financial statements to bring their accounting
policies into line with those of the Group. Intercompany receivables, liabilities and results between Group
companies are eliminated in the consolidation process.
Associated Companies
An associate is an entity over which E.ON has significant influence but which is neither a subsidiary nor an
interest in a joint venture. Significant influence is achieved when E.ON has the power to participate in the
financial and operating policy decisions of the investee but does not control or jointly control these decisions.
Significant influence is generally presumed if E.ON directly or indirectly holds at least 20 percent, but less than
50 percent, of an entity’s voting rights.
Interests in associated companies are accounted for under the equity method. In addition, majority-owned
companies in which E.ON does not exercise control due to restrictions concerning the control of assets or
management are also generally accounted for under the equity method.
Interests in associated companies accounted for under the equity method are reported on the balance sheet at
cost, adjusted for changes in the Group’s share of the net assets after the date of acquisition, as well as any
impairment charges. Losses that exceed the Group’s interest in an associated company are not recognized. Any
goodwill resulting from the acquisition of an associated company is included in the carrying amount of the
investment.
Unrealized gains and losses arising from transactions with associated companies accounted for under the
equity method are eliminated within the consolidation process on a pro-rata basis if and insofar as these are
material.
Companies accounted for under the equity method are tested for impairment by comparing the carrying
amount with its recoverable amount. If the carrying amount exceeds the recoverable amount, the carrying amount
is adjusted in the amount of this difference. If the reasons for previously recognized impairment losses no longer
exist, such impairment losses are reversed.
F-11
The financial statements of equity interests accounted for under the equity method are generally prepared
using accounting that is uniform within the Group.
Joint Ventures
Joint ventures are also accounted for under the equity method. Unrealized gains and losses arising from
transactions with joint-venture companies are eliminated within the consolidation process on a pro-rata basis if
and to the extent these are material.
Business Combinations
In accordance with the exemption allowed under IFRS 1, the provisions of IFRS 3, “Business
Combinations” (“IFRS 3”), were not applied with respect to the accounting for business combinations that
occurred before January 1, 2006. The goodwill maintained from this period did not include any intangible assets
that had to be reported separately under IFRS. Conversely, there were no intangible assets that until now had
been reported separately that had to be included in goodwill. As no adjustment for intangible assets was required
relating to such business combinations, the goodwill reported under U.S. GAAP was maintained in E.ON’s
opening balance sheet under IFRS.
Business combinations are accounted for by applying the purchase method, whereby the purchase price is
offset against the proportional share in the acquired company’s net assets. In doing so, the values at the
acquisition date that corresponds to the date at which control of the acquired company was attained are used as a
basis. The acquiree’s identifiable assets, liabilities and contingent liabilities are recognized at their fair values,
regardless of the extent attributable to minority interests. The fair values of individual assets are determined
using published exchange or market prices at the time of acquisition in the case of marketable securities, for
example, and in the case of land, buildings and more significant technical equipment, generally using
independent expert reports that have been prepared by third parties. If exchange or market prices are unavailable
for consideration, fair values are determined using the most reliable information available that is based on market
prices for comparable assets or on suitable valuation techniques. In such cases, E.ON determines fair value using
the discounted cash flow method by discounting estimated future cash flows by a weighted average cost of
capital. Estimated cash flows are consistent with the internal mid-term planning data for the next three years,
followed by two additional years of cash flow projections, which are extrapolated until the end of an asset’s
useful life using a growth rate based on industry and internal projections. The discount rate reflects specific risks
inherent to the asset.
Transactions with minority shareholders are treated in the same way as transactions with equity holders.
Should the acquisition of additional shares in a subsidiary result in a difference between the cost of purchasing
the shares and the carrying amount of the minority interest acquired, that difference must be fully recognized in
equity.
Gains and losses from disposals of shares to minority shareholders are also recognized in equity, provided
that such disposals do not result in a loss of control.
Intangible assets must be recognized separately from goodwill if they are clearly separable or if their
recognition arises from a contractual or other legal right. Provisions for restructuring measures may not be
recorded in a purchase price allocation. If the purchase price paid exceeds the proportional share in the net assets
at the time of acquisition, the positive difference is recognized as goodwill. A negative difference is immediately
recognized in income.
F-12
Foreign Currency Translation
The Company’s transactions denominated in foreign currencies are translated at the current exchange rate at
the date of the transaction. Monetary foreign currency items are adjusted to the current exchange rate at each
balance sheet date; any gains and losses resulting from fluctuations in the relevant currencies are included in
other operating income and other operating expenses, respectively. Gains and losses from the translation of
financial instruments used in hedges of net investments in its foreign operations are recognized in equity. The
ineffective portion of the hedging instrument is immediately recognized in income.
The functional currency as well as the reporting currency of E.ON AG is the euro. The Consolidated
Financial Statements are presented in euro as well. The assets and liabilities of the Company’s foreign
subsidiaries with a functional currency other than the euro are translated using period-end exchange rates, while
items of the statements of income are translated using average exchange rates for the period. Significant
transactions of foreign subsidiaries occurring during the fiscal year are translated in the financial statements
using the exchange rate at the date of the transaction. Differences arising from the translation of assets and
liabilities, as well as gains or losses in comparison with the translation of prior years, are included as a separate
component of equity and accordingly have no effect on net income. In accordance with the option under IFRS 1,
all unrealized cumulative translation differences that had resulted from the translation of financial statements into
the reporting currency of E.ON in prior periods and had been recognized in equity were offset against retained
earnings at the date of transition.
The foreign currency translation effects that are attributable to monetary financial instruments classified as
available for sale are recognized in net income. For non-monetary financial instruments classified as available for
sale, the foreign currency translation effects are recognized in equity with no effect on net income.
The following table depicts the movements in exchange rates for the periods indicated for major currencies
of countries outside the European Monetary Union:
Currencies
ISO
Code
British pound . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Norwegian krone . . . . . . . . . . . . . . . . . . . . . . . . . . .
Russian ruble . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Swedish krona . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hungarian forint . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Dollar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GBP
NOK
RUB
SEK
HUF
USD
€ 1, rate at year-end
€ 1, annual average
rate
2007
2006
2007
2006
0.73
7.97
35.99
9.45
253.81
1.47
0.67
8.24
34.68
9.04
251.77
1.32
0.68
8.02
34.99
9.25
251.34
1.37
0.68
8.05
34.11
9.25
264.26
1.26
Recognition of Income
a) Revenues
The Company generally recognizes revenue upon delivery of products to customers or upon fulfillment of
services. Delivery has occurred when the risks and rewards associated with ownership have been transferred to
the buyer, compensation has been contractually established and collection of the resulting receivable is probable.
Revenues from the sale of goods and services are measured at the fair value of the consideration received or
receivable.
Revenues are presented net of sales taxes, returns, rebates and discounts, and after elimination of
intercompany sales.
F-13
Revenues are generated primarily from the sale of electricity and gas to industrial and commercial
customers and to retail customers. Additional revenue is earned from the distribution of electricity and gas, as
well as from deliveries of steam and heat.
Revenues from the sale of electricity and gas to industrial and commercial customers and to retail customers
are recognized when earned on the basis of a contractual arrangement with the customer; they reflect the value of
the volume supplied, including an estimated value of the volume supplied to customers between the date of their
last meter reading and period-end.
b) Interest Income
Interest income is recognized pro rata using the effective interest method.
c) Dividend Income
Dividend income is recognized when the right to receive the distribution payment arises.
Electricity and Energy Taxes
The electricity tax is levied on electricity delivered to retail customers by domestic utilities in Germany and
Sweden and is calculated on the basis of a fixed tax rate per kilowatt-hour (“kWh”). This rate varies between
different classes of customers. Electricity and energy taxes paid are deducted from sales revenues on the face of
the income statement.
Germany’s Energy Tax Act (“Energiesteuergesetz,” “EnergieStG”) regulates the taxation of energy
generated from petroleum, natural gas and coal. It replaced the Petroleum Tax Act (“Mineralölsteuergesetz”)
effective August 1, 2006. Under the Energy Tax Act, natural gas tax is not levied until delivery to the end
consumer. Under the previously applicable Petroleum Tax Act, natural gas tax became due at the time of the
procurement or removal of the natural gas from storage facilities.
Accounting for Sales of Shares of Subsidiaries or Associated Companies
If a subsidiary or associated company sells shares to a third party, leading to a reduction in E.ON’s
ownership interest in the relevant company (“dilution”), and consequently to a loss of control or significant
influence, gains and losses from these dilutive transactions are included in the income statement under other
operating income or expenses.
Research and Development Costs
Under IFRS, research and development costs must be allocated to a research phase and a development
phase. While expenditure on research is expensed as incurred, recognized development costs must be capitalized
as an intangible asset if all of the general criteria for recognition specified in IAS 38, “Intangible Assets” (“IAS
38”), as well as certain other specific prerequisites, have been fulfilled. In the 2007 and 2006 fiscal years, these
criteria have not been fulfilled.
Research and development costs totaled €37 million in 2007 (2006: €27 million).
Earnings per Share
Basic (undiluted) earnings per share is computed by dividing the consolidated net income attributable to the
shareholders of the parent company by the weighted average number of ordinary shares outstanding during the
relevant period. At E.ON the computation of diluted earnings per share is identical to basic earnings per share,
because E.ON AG has no dilutive potential ordinary shares.
F-14
Goodwill and Intangible Assets
Goodwill
According to IFRS 3, goodwill is not amortized, but rather tested for impairment at the cash-generating unit
level on at least an annual basis. Impairment tests must also be performed between these annual tests if events or
changes in circumstances indicate that the carrying amount of the respective cash-generating unit might not be
recoverable.
Newly created goodwill is allocated to those cash-generating units expected to benefit from the respective
business combination. E.ON has identified the operating units one level below its primary segments as its cashgenerating units.
In a first step, E.ON determines the recoverable amount of a cash-generating unit on the basis of the fair
value (less costs to sell) using valuation procedures that make use of the Company’s internal mid-term planning
data. Valuation is based on the discounted cash flow method, and accuracy is verified through the use of
multiples. In addition, market transactions or valuations prepared by third parties for comparable assets are used
to the extent available.
In an impairment test, the recoverable amount of a cash-generating unit is compared with its carrying
amount, including goodwill. The recoverable amount is the higher of the cash-generating unit’s fair value less
costs to sell and its value in use. If the carrying amount exceeds the recoverable amount, the goodwill allocated
to that cash-generating unit is adjusted in the amount of this difference.
If the impairment thus identified exceeds the goodwill allocated to the affected cash-generating unit, the
remaining assets of the unit must be written down in the proportion of their carrying amounts. Individual assets
may not be written down if their respective carrying amounts were to fall below the highest of the following as a
result:
•
Fair value less costs to sell
•
Value in use
•
Zero
The impairment loss that would otherwise have been allocated to the asset concerned must instead be
allocated pro rata to the remaining assets of the unit.
E.ON has elected to perform the annual testing of goodwill for impairment at the cash-generating unit level
in the fourth quarter of each fiscal year.
Impairment losses recognized for goodwill in a cash-generating unit may not be reversed in subsequent
reporting periods.
Intangible Assets
IAS 38 requires that intangible assets be amortized over their useful lives unless their lives are considered to
be indefinite.
Acquired intangible assets subject to amortization are classified as marketing-related, customer-related,
contract-based, and technology-based. Internally generated intangible assets subject to amortization are related to
software. Intangible assets subject to amortization are measured at cost and amortized using the straight-line
method over their expected useful lives, generally for a period between 5 and 25 years or between 3 and 5 years
for software, respectively. Useful lives and amortization methods are subject to annual verification. Intangible
assets subject to amortization are tested for impairment whenever events or changes in circumstances indicate
that such assets may be impaired.
F-15
Intangible assets not subject to amortization are measured at cost and tested for impairment annually or
more frequently if events or changes in circumstances indicate that such assets may be impaired. Moreover, such
assets are reviewed annually to determine whether an assessment of indefinite useful life remains applicable.
In accordance with IAS 36, “Impairment of Assets” (“IAS 36”), the carrying amount of an intangible asset,
whether subject to amortization or not, is tested for impairment by comparing the carrying value with its
recoverable amount, which is the higher of an asset’s value in use and its fair value less costs to sell. Should the
carrying amount exceed the recoverable amount, an impairment charge equal to the difference between the
carrying amount and the recoverable amount is recognized. If the reasons for previously recognized impairment
losses no longer exist, such impairment losses are reversed. A reversal shall not cause the carrying amount of an
intangible asset subject to amortization to exceed the amount that would have been determined, net of
amortization, had no impairment loss been recognized during the period.
If a recoverable amount cannot be determined for an individual intangible asset, the recoverable amount for
the smallest identifiable group of assets (cash-generating unit) that the intangible asset may be assigned to is
determined.
Please see Note 14(a) for additional information about goodwill and intangible assets.
Emission Rights
Under IFRS, emission rights held under national and international emission-rights systems for the settlement
of obligations are reported as intangible assets. Because emission rights are not amortized, they are reported as
intangible assets not subject to amortization. Emission rights are capitalized at cost on acquisition or when issued
for the respective reporting period as (partial) fulfillment of the notice of allocation from the responsible national
authorities.
A provision is recognized for emissions produced. The provision is measured at the carrying amount of the
emission rights held or, in the case of a shortfall, at the current fair value of the emission rights needed. Any
expected shortfall in emission rights is recorded under miscellaneous provisions. The expenses incurred for the
recognition of the provision are reported under cost of materials.
As part of operating activities, emission rights are also held for proprietary trading purposes. Emission
rights held for proprietary trading are reported under other operating assets and measured at the lower of cost or
fair value.
Property, Plant and Equipment
Property, plant and equipment are initially measured at acquisition or production cost, including
decommissioning or restoration cost that must be capitalized, and are depreciated over their expected useful
lives, generally using the straight-line method, unless a different method of depreciation is deemed more suitable
in certain exceptional cases.
Useful Lives of Property, Plant and Equipment
Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Technical equipment, plant and machinery . . . . . . . . . . . . . . . . . . . . . . . . . .
Other equipment, fixtures, furniture and office equipment . . . . . . . . . . . . . .
10 to 50 years
10 to 65 years
3 to 25 years
Property, plant and equipment are tested for impairment whenever events or changes in circumstances
indicate that an asset may be impaired. In such a case, property, plant and equipment are tested for impairment
F-16
according to the principles prescribed for intangible assets in IAS 36. If an impairment loss is determined, the
remaining useful life of the asset might also be subject to adjustment, where applicable. If the reasons for
previously recognized impairment losses no longer exist, such impairment losses are reversed and recognized in
income. Such reversal shall not cause the carrying amount to exceed the amount that would have been presented
had no impairment taken place during the preceding periods.
Investment subsidies do not reduce the acquisition and production costs of the respective assets; they are
instead reported on the balance sheet as deferred income.
Subsequent costs arising, for example, from additional or replacement capital expenditure are only
recognized as part of the acquisition or production cost of the asset, or else—if relevant—recognized as a
separate asset if it is probable that the Group will receive a future economic benefit and the cost can be
determined reliably.
Repair and maintenance costs that do not constitute significant replacement capital expenditure are
expensed as incurred.
Borrowing Costs
Borrowing costs that arise in connection with the acquisition, construction or production of a qualifying
asset from the time of acquisition or from the beginning of construction or production until entry into service are
capitalized and subsequently amortized alongside the related asset. Borrowing costs are generally allocated using
the Group’s overall cost of financing as a basis. As of December 31, 2007, a financing rate uniform within the
Group of 5.0 percent was applied. In the case of a specific financing arrangement, the respective specific
borrowing costs for that arrangement are used. Other borrowing costs are expensed.
Government Grants
Government investment subsidies do not reduce the acquisition and production costs of the respective
assets; they are instead reported on the balance sheet as deferred income. They are amortized on a straight-line
basis over the related asset’s expected useful life.
Government grants are recognized at fair value if it is highly probable that the grant will be issued and if the
Group satisfies the necessary conditions for receipt of the grant.
Government grants for costs are recognized over the period in which the costs that are supposed to be
compensated through the respective grants are incurred.
Leasing
Leasing transactions are classified according to the lease agreements and to the underlying risks and rewards
specified therein in line with IAS 17, “Leases” (“IAS 17”). In addition, IFRIC 4, “Determining Whether an
Arrangement Contains a Lease” (“IFRIC 4”), further defines the criteria as to whether an agreement that conveys
a right to use an asset meets the definition of a lease. Certain purchase and supply contracts in the electricity and
gas business as well as certain rights of use may be classified as leases if the criteria are met. E.ON is party to
some agreements in which it is the lessor and other agreements in which it is the lessee.
Leasing transactions in which E.ON is the lessee are classified either as finance leases or operating leases. If
the Company bears substantially all of the risks and rewards incident to ownership of the leased property, the
lease is classified as a finance lease. Accordingly, the Company recognizes on its balance sheet the asset and the
associated liability in equal amounts.
F-17
Recognition takes place at the beginning of the lease term at the lower of the fair value of the leased
property or the present value of the minimum lease payments.
The leased property is depreciated over its useful economic life or, if it is shorter, the term of the lease.
The liability is subsequently measured using the effective interest method. All other transactions in which
E.ON is the lessee are classified as operating leases. Payments made under operating leases are generally
expensed over the term of the lease.
Leasing transactions in which E.ON is the lessor and substantially all the risks and rewards incident to
ownership of the leased property are transferred to the lessee are classified as finance leases. In this type of lease,
E.ON records the present value of the minimum lease payments as a receivable. Payments by the lessee are
apportioned between a reduction of the lease receivable and interest income. The income from such arrangements
is recognized over the term of the lease using the effective interest method.
All other transactions in which E.ON is the lessor are treated as operating leases. E.ON retains the leased
property on its balance sheet as an asset, and the lease payments are generally recorded as income over the term
of the lease.
Financial Instruments
The first-time adoption of IFRS 7, “Financial Instruments: Disclosures” (“IFRS 7”), became effective in the
2007 fiscal year. The new standard requires both quantitative and qualitative disclosures about the extent of risks
arising from financial instruments (e.g., credit, liquidity and market risks).
Non-Derivative Financial Instruments
Non-derivative financial instruments are recognized at fair value on the settlement date when acquired.
Unconsolidated equity investments and securities are measured in accordance with IAS 39. E.ON categorizes
financial assets as held for trading, available for sale, or as loans and receivables. Management determines the
categorization of the financial assets at initial recognition.
Securities categorized as available for sale are carried at fair value on a continuing basis, with any resulting
unrealized gains and losses, net of related deferred taxes, reported as a separate component within equity until
realized. Realized gains and losses are recorded based on the specific identification method. Unrealized losses
previously recognized in equity are recognized in financial results in the case of substantial impairment.
Reversals of impairment losses relating to equity instruments are recognized exclusively in equity.
Loans and receivables (including trade receivables) are non-derivative financial assets with fixed or
determinable payments that are not traded in an active market. Loans and receivables are reported on the balance
sheet under “Receivables and other assets.” They are subsequently measured at amortized cost, using the
effective interest method. Valuation allowances are provided for identifiable individual risks. If the loss of a
certain part of the receivables is probable, valuation allowances are provided to cover the expected loss.
Reversals of losses are recognized under “Other operating income.”
Non-derivative financial liabilities (including trade payables) within the scope of IAS 39 are measured at
amortized cost, using the effective interest method. Initial measurement takes place at fair value plus transaction
costs. In subsequent periods, the amortization and accretion of any premium or discount is included in financial
results.
F-18
Derivative Financial Instruments and Hedging Transactions
Derivative financial instruments and separated embedded derivatives are measured at fair value as of the
trade date at initial recognition and in subsequent periods. IAS 39 requires that they be categorized as held for
trading as long as they are not a component of a hedge accounting relationship. Gains and losses from changes in
fair value are immediately recognized in net income.
Instruments commonly used are foreign currency forwards and swaps, as well as interest-rate swaps and
cross-currency swaps. Equity forwards are entered into to cover price risks on securities. In commodities, the
instruments used include physically and financially settled forwards and options related to electricity, gas, coal,
oil and emission rights. As part of conducting operations in commodities, derivatives are also acquired for
proprietary trading purposes.
IAS 39 sets requirements for the designation and documentation of hedging relationships, the hedging
strategy, as well as ongoing retrospective and prospective measurement of effectiveness in order to qualify for
hedge accounting. The Company does not exclude any component of derivative gains and losses from the
measurement of hedge effectiveness. Hedge accounting is considered to be appropriate if the assessment of
hedge effectiveness indicates that the change in fair value of the designated hedging instrument is 80 to
125 percent effective at offsetting the change in fair value due to the hedged risk of the hedged item or
transaction.
For qualifying fair value hedges, the change in the fair value of the derivative and the change in the fair
value of the hedged item that is due to the hedged risk(s) are recognized in income. If a derivative instrument
qualifies as a cash flow hedge, the effective portion of the hedging instrument’s gain or loss is recognized in
equity (as a component of accumulated other comprehensive income) and reclassified into income in the period
or periods during which the transaction being hedged affects income. The hedging result is reclassified into
income immediately if it becomes probable that the hedged underlying transaction will no longer occur. For
hedging instruments used to establish cash flow hedges, the change in fair value of the ineffective portion is
recognized immediately in the income statement. To hedge the foreign currency risk arising from the Company’s
net investment in foreign operations, derivative as well as non-derivative financial instruments are used. Gains or
losses due to changes in fair value and from foreign currency translation are recognized separately within equity
as currency translation adjustments.
Changes in fair value of derivative instruments that must be recognized in income are classified as other
operating income or expenses. Gains and losses from interest-rate derivatives are netted for each contract and
included in interest income. Gains and losses from derivative proprietary trading instruments are shown net as
either revenues or cost of materials. Certain realized amounts are, if related to the sale of products or services,
also included in sales or cost of materials.
Unrealized gains and losses resulting from the initial measurement of derivative financial instruments at the
inception of the contract are not recognized in income. They are instead deferred and recognized in income
systematically over the term of the derivative. An exception to the accrual principle applies if unrealized gains
and losses from the initial measurement are verified by quoted market prices, observable prices of other current
market transactions or other observable data supporting the valuation technique. In this case the gains and losses
are recognized in income.
See Note 30 for additional information regarding the Company’s use of derivative instruments.
Inventories
The Company measures inventories at the lower of acquisition or production cost and net realizable value.
The cost of raw materials, finished products and goods purchased for resale is determined based on the average
cost method. In addition to production materials and wages, production costs include material and production
F-19
overheads based on normal capacity. The costs of general administration are not capitalized. Inventory risks
resulting from excess and obsolescence are provided for using appropriate valuation allowances whereby
inventories are written down to net realizable value.
Receivables and Other Assets
Receivables and other assets are initially measured at fair value, which generally approximates nominal
value. They are subsequently measured at amortized cost, using the effective interest method. Valuation
allowances, included in the reported net carrying amount, are provided for identifiable individual risks. If the loss
of a certain part of the receivables is probable, valuation allowances are provided to cover the expected loss.
Liquid Funds
Liquid funds include current available-for-sale securities, checks, cash on hand and bank balances. Bank
balances and available-for-sale securities with an original maturity of more than three months are recognized
under securities and fixed term deposits. Liquid funds with an original maturity of less than three months are
considered to be cash and cash equivalents, unless they are restricted.
Restricted cash with a remaining maturity in excess of twelve months is classified as financial receivables
and other financial assets.
Assets Held for Sale and Liabilities Associated with Assets Held for Sale
Individual non-current assets or groups of assets held for sale and any directly attributable liabilities
(disposal groups) are reported in these line items if they can be disposed of in their current condition and if there
is sufficient probability of their disposal actually taking place. For a group of assets and associated liabilities to
be classified as a disposal group, the assets and liabilities in it must be held for sale in a single transaction or as
part of a comprehensive plan.
Discontinued operations are components of an entity that are either held for sale or have already been sold
and can be clearly distinguished from other corporate operations, both operationally and for financial reporting
purposes. Additionally, the component classified as a discontinued operation must represent a major business line
or a specific geographic area of the Group.
Non-current assets that are held for sale either individually or collectively as part of a disposal group, or that
belong to a discontinued operation, are no longer depreciated. They are instead accounted for at the lower of the
carrying amount and the fair value less any remaining costs to sell. If the fair value is less than the carrying
amount, an impairment loss is recognized.
The income and losses resulting from the measurement of components held for sale at fair value less any
remaining costs to sell, as well as the gains and losses arising from the disposal of discontinued operations, are
reported separately on the face of the income statement under income/loss from discontinued operations, net, as
is the income from the ordinary operating activities of these divisions. Prior-year income statement figures are
adjusted accordingly. The cash flows of discontinued operations are reported separately in the cash flow
statement with prior-year figures being adjusted accordingly. However, there is no reclassification of prior-year
balance sheet line items attributable to discontinued operations.
Equity Instruments
IFRS defines equity as the residual interest in the Group’s assets after deducting all liabilities. Therefore,
equity is the net amount of all recognized assets and liabilities.
F-20
E.ON has entered into conditional and unconditional purchase commitments to minority shareholders. By
means of these agreements, the minority shareholders have the right to require E.ON to purchase their shares on
specified conditions. None of the contractual obligations has led to the transfer of substantially all of the risk and
rewards to E.ON at the time of entering into the contract. IAS 32, “Financial Instruments: Presentation” (“IAS
32”), prescribes that a liability must be recognized at the present value of the probable future exercise price. This
amount is reclassified from a separate component within minority interests and reported separately as a liability.
The reclassification occurs irrespective of the probability of exercise. Expenses resulting from the accretion of
the liability are recognized in interest expenses. If a purchase commitment expires unexercised, the liability
reverts to minority interests. Any difference between liabilities and minority interests is recognized directly in
retained earnings.
Where shareholders of entities own statutory, non-excludable rights of termination (for example, in German
partnerships), such termination rights require the reclassification of minority interests from equity into liabilities
under IAS 32. The liability is recognized at the present value of the expected settlement amount irrespective of
the probability of termination. Changes in the value of the liability are reported within other operating income.
Accretion of the liability and the minority shareholders’ share in net income are shown as interest expense.
If an E.ON Group company buys treasury shares of E.ON AG, the value of the consideration paid, including
directly attributable additional costs (net after income taxes), is deducted from E.ON AG’s equity until the shares
are retired, distributed or resold. If such treasury shares are subsequently distributed or sold, the consideration
received, net of any directly attributable additional transaction costs and associated income taxes, are added to
E.ON AG’s equity.
Share-Based Payment
Share-based payment plans issued in the E.ON Group are accounted for in accordance with IFRS 2, “ShareBased Payment” (“IFRS 2”). Both the E.ON Share Performance Plan introduced in fiscal 2006 and the remaining
Stock Appreciation Rights granted between 1999 and 2005 as part of the virtual stock option program of
E.ON AG are share-based payment transactions with cash compensation, the value of which is reported at fair
value of the liability at each balance sheet date. Compensation expense is recorded pro rata over the vesting
period. E.ON determines fair value using the Monte Carlo simulation technique.
Provisions for Pensions and Similar Obligations
The valuation of defined benefit obligations in accordance with IAS 19, “Employee Benefits” (“IAS 19”), is
based on actuarial computations using the projected unit credit method, with actuarial valuations performed at
year-end. The valuation encompasses both pension obligations and pension entitlements that are known on the
balance sheet date as well as economic trend assumptions made in order to reflect realistic expectations.
Actuarial gains and losses that may arise from differences between the estimated and actual number of
beneficiaries and from the underlying assumptions are recognized in full in the period in which they occur. Such
gains and losses are not reported within the Consolidated Statements of Income but rather are recognized within
the Statements of Recognized Income and Expenses as part of equity.
The service cost representing the additional benefits that employees earned under the benefit plan during the
fiscal year is reported under personnel costs; interest expenses and expected return on plan assets are reported
under financial results.
Unrecognized past service cost is recognized immediately to the extent that the benefits are already vested
or is amortized on a straight-line basis over the average period until the benefits become vested.
The amount reported in the balance sheet represents the present value of the defined benefit obligation
adjusted for unrecognized past service cost and reduced by the fair value of plan assets. If a net asset position
F-21
arises from this calculation, the amount is limited to the unrecognized past service cost plus the present value of
available refunds and reductions in future contributions.
Payments for defined contribution pension plans are expensed as incurred and reported under personnel
costs. Contributions to government pension plans are treated like payments for defined contribution pension
plans to the extent that the Group’s obligations under these pension plans correspond to those under defined
contribution pension plans.
Provisions for Asset Retirement Obligations and Other Provisions
In accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”),
provisions are recognized when E.ON has a legal or constructive present obligation towards third parties as a
result of a past event, it is probable that E.ON will be required to settle the obligation, and a reliable estimate can
be made of the amount of the obligation. The provision is recognized at the expected settlement amount. Longterm obligations are reported as liabilities at the present value of their expected settlement amounts if the interest
rate effect (the difference between present value and repayment amount) resulting from discounting is material;
future cost increases that are foreseeable and likely to occur on the balance sheet date must also be included in
the measurement. Long-term obligations are discounted at the market interest rate applicable as of the respective
balance sheet date. The accretion amounts and the effects of changes in interest rates are generally presented as
part of financial results. A reimbursement related to the provision that is virtually certain to be collected is
capitalized as a separate asset. No offsetting within provisions is permitted. Advance payments remitted are
deducted from the provisions.
Obligations arising from the decommissioning and restoration of property, plant and equipment are
recognized during the period of their occurrence at their discounted settlement amounts, provided that the
obligation can be reliably estimated. The carrying amounts of the respective property, plant and equipment are
increased by the same amounts. In subsequent periods, capitalized asset retirement costs are amortized over the
expected remaining useful lives of the assets, and the provision is accreted to its present value on an annual basis.
Changes in estimates arise in particular from deviations from original cost estimates, from changes to the
maturity or the scope of the relevant obligation, and also as a result of the regular adjustment of the discount rate
to current market interest rates. The adjustment of provisions for the decommissioning and restoration of
property, plant and equipment for changes to estimates is generally recognized by way of a corresponding
adjustment to assets, with no effect on income. If the property, plant and equipment to be decommissioned have
already been fully depreciated, changes to estimates are recognized within the income statement.
The estimates for non-contractual nuclear decommissioning provisions are based on external studies and are
continuously updated.
Under Swedish law, E.ON Sverige is required to pay fees to the country’s national fund for nuclear waste
management. Each year, the Swedish Nuclear Power Inspectorate calculates the fees for the disposal of highlevel radioactive waste and nuclear power plant decommissioning based on the amount of electricity produced at
the particular nuclear power plant. The proposed fees are then submitted to government offices for approval.
Upon approval, E.ON Sverige makes the corresponding payments. In accordance with IFRIC 5, “Rights to
Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds” (“IFRIC 5”),
payments into the Swedish national fund for nuclear waste management are offset by a right of reimbursement of
asset retirement obligations, which is recognized as an asset under “Other assets.” In a departure from the policy
applied in Germany, provisions for Sweden measured on the basis of the contributions to the fund are discounted
at the real interest rate.
No provisions are established for contingent asset retirement obligations where the type, scope, timing and
associated probabilities can not be determined reliably.
F-22
Contingent liabilities are potential or present obligations toward third parties in which an outflow of
resources embodying economic benefits is not probable or where the amount of the obligation cannot be
measured with sufficient reliability. Contingent liabilities are generally not recognized on the balance sheet.
Income Taxes
Under IAS 12, “Income Taxes” (“IAS 12”), deferred taxes are recognized on temporary differences arising
between the carrying amounts of assets and liabilities on the balance sheet and their tax bases (balance sheet
liability method). Deferred tax assets and liabilities are recognized for temporary differences that will result in
taxable or deductible amounts when taxable income is calculated for future periods, unless those differences are
the result of the initial recognition of an asset or liability in a transaction other than a business combination that,
at the time of the transaction, affects neither accounting nor taxable profit/loss. IAS 12 further requires that
deferred tax assets be recognized for unused tax loss carryforwards and unused tax credits. Deferred tax assets
are recognized to the extent that it is probable that taxable profit will be available against which the deductible
temporary differences and unused tax losses can be utilized. Each of the corporate entities is assessed
individually with regard to the probability of a positive tax result in future years. Any existing history of losses is
incorporated in this assessment. For those tax assets to which these assumptions do not apply, the value of the
deferred tax assets has been reduced.
Deferred tax liabilities caused by temporary differences associated with investments in affiliated and
associated companies are recognized unless the timing of the reversal of such temporary differences can be
controlled within the Group and it is probable that, owing to this control, the differences will in fact not be
reversed in the foreseeable future.
Deferred tax assets and liabilities are measured using the enacted or substantively enacted tax rates expected
to be applicable for taxable income in the years in which temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of changes in tax rates and tax law is generally recognized
in income. Equity is adjusted for deferred taxes that had previously been recognized directly in equity. Following
passage of the 2008 corporate tax reforms in Germany, deferred taxes for domestic companies were calculated
using a total tax rate of 30 percent (2006: 39 percent). This tax rate includes, in addition to the 15 percent (2006:
25 percent) corporate income tax, the solidarity surcharge of 5.5 percent on the corporate tax, and the average
trade tax rate of 14 percent (2006: 13 percent) applicable to the E.ON Group. Foreign subsidiaries use applicable
national tax rates.
Note 10 shows the major temporary differences so recorded.
Consolidated Statement of Cash Flows
In accordance with IAS 7, “Cash Flow Statements” (“IAS 7”), the Consolidated Statements of Cash Flows
are classified by operating, investing and financing activities. Cash flows from discontinued operations are
reported separately in the Consolidated Statement of Cash Flows. Interest received and paid, income taxes paid
and refunded, as well as dividends received are classified as operating cash flows, whereas dividends paid are
classified as financing cash flows. The purchase and sale prices respectively paid and received in connection with
the acquisition and disposal of affiliated companies are reported under investing activities, net of the cash and
cash equivalents acquired or divested as part of the transaction. This also applies to valuation changes due to
exchange rate fluctuations, whose impact on cash and cash equivalents is separately disclosed.
Segment Information
Segment reporting has for the first time taken place in accordance with IFRS 8. The so-called management
approach required by IFRS 8 stipulates that the internal reporting organization used by management for making
decisions on operating matters and the internal performance measure, i.e., adjusted EBIT, should be applied in
the identification of the Company’s reportable segments (see Note 33).
F-23
Structure of the Consolidated Balance Sheets and Statements of Income
In accordance with IAS 1, “Presentation of Financial Statements” (“IAS 1”), the Consolidated Balance
Sheets have been prepared using a classified balance sheet structure. Assets that will be realized within twelve
months of the reporting date, as well as liabilities that are due to be settled within one year of the reporting date
are classified as current.
In addition, as part of the transition to IFRS, classification of the Income Statement was changed to the
nature of expense method which is also applied for internal purposes.
Capital Structure Management
At the end of May 2007, E.ON announced its future corporate strategy. As part of this strategic reorientation
at E.ON, the financial strategy of the Group was also developed further.
Accordingly, E.ON has replaced adjusted EBITDA with the debt factor as a metric for the management of
capital structure. The debt factor is defined as the ratio of net economic debt to adjusted EBITDA. Net economic
debt includes provisions for pensions and waste disposal in addition to financial debt. E.ON has set a debt factor
of 3 as its target, which is derived from the target rating of single A flat/A2 and is actively managed.
Based on adjusted EBITDA in 2007 of €12,450 million (2006: €11,724 million) and net economic debt of
€24,138 million as of the balance sheet date (2006: €18,233 million), the debt factor is 1.9 (2006: 1.6).
Critical Accounting Estimates and Assumptions; Critical Judgments in the Application of Accounting Policies
The preparation of the Consolidated Financial Statements requires management to make estimates and
assumptions that may influence the application of accounting principles within the Group and affect the valuation
and presentation of reported figures. Estimates are based on past experience and on additional knowledge
obtained on transactions to be reported. Actual amounts could differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Adjustments to accounting
estimates are recognized in the period in which the estimate is revised if the change affects only that period or in
the period of the revision and subsequent periods if both current and future periods are affected.
Estimates are particularly necessary for the measurement of the value of property, plant and equipment and
of intangible assets, especially in connection with purchase price allocations, the recognition and measurement of
deferred tax assets, the accounting treatment of provisions for pensions and miscellaneous provisions, as well as
for impairment testing in accordance with IAS 36.
The underlying principles used for estimates in each of the relevant topics are outlined in the respective
sections.
New Standards and Interpretations
The International Accounting Standards Board (“IASB”) and the IFRIC have issued standards and
interpretations whose application is not yet mandatory in the reporting period. The application of some of these
standards and interpretations is at the present time still subject to adoption by the EU, which remains outstanding.
IFRS 3, “Business Combinations”
In January 2008, the IASB published a revised version of IFRS 3, “Business Combinations” (“IFRS 3”), as
part of its “Business Combinations II” project. The most significant changes from the previous version relate to
F-24
the recognition and measurement of assets and liabilities acquired through a business combination, the
measurement of non-controlling interests, as well as to the calculation of goodwill and the presentation of
transactions with variable purchase prices. The revised standard is to be applied for transactions taking place in
fiscal years beginning on or after July 1, 2009. However, the standard has not yet been transferred by the EU into
European law. E.ON is currently evaluating the potential effects arising from the revision of IFRS 3.
IFRS 2, “Share-based Payment”
In January 2008, the IASB issued revised IFRS 2, “Share-based Payment” (“IFRS 2”). The changes from
the previous version relate primarily to the definition of vesting conditions and to the regulations governing the
cancellation of a plan by a party other than the entity. The amendments are to be applied for fiscal years
beginning on or after January 1, 2009. However, the standard has not yet been transferred by the EU into
European law. Revised IFRS 2 will not have a material impact on E.ON’s Consolidated Financial Statements.
IAS 23, “Borrowing Costs”
In March 2007, the IASB issued revised IAS 23, “Borrowing Costs” (“IAS 23”). IAS 23 eliminates the
option of recognizing borrowing costs immediately as an expense, to the extent that they are directly attributable
to the acquisition, construction or production of a qualifying asset. Capitalization of such directly attributable
borrowing costs is now mandatory. The revised standard applies to borrowing costs relating to qualifying assets
for which the commencement date for capitalization is on or after January 1, 2009. However, the standard has not
yet been transferred by the EU into European law. Revised IAS 23 has no impact for E.ON as E.ON already
capitalizes borrowing costs as a part of the cost of acquisition or construction.
IAS 1, “Presentation of Financial Statements”
In September 2007, the IASB issued a revised version of IAS 1. The main changes from the previous
version relate to the presentation of equity and to changes in the titles of the financial statements. The revised
standard is to be applied for fiscal years beginning on or after January 1, 2009. However, the standard has not yet
been transferred by the EU into European law. Revised IAS 1 will not have a material impact on E.ON’s
Consolidated Financial Statements.
IAS 27, “Consolidated and Separate Financial Statements”
In January 2008, the IASB published a revised version of IAS 27, “Consolidated and Separate Financial
Statements” (“IAS 27”), as part of its “Business Combinations II” project, which contains rules on consolidation.
In particular, this standard has for the first time dealt with transactions in which shares in a company (subsidiary)
are bought or sold without resulting in a change of control. Additional significant changes from the previous
version relate in particular to the recognition and measurement of the remaining investment in an entity after a
loss of control of what had been a subsidiary, and to the recognition of losses attributable to minority interests.
The amendments introduced by the revised standard are to be applied for fiscal years beginning on or after
July 1, 2009. However, the standard has not yet been transferred by the EU into European law. E.ON is currently
evaluating the potential effects arising from the revision of IAS 27.
Amendments to IAS 32 and IAS 1, “Puttable Financial Instruments and Obligations Arising on Liquidation”
In February 2008, the IASB approved amendments to IAS 32 and IAS 1. The primary purpose of the
amendments is to address the accounting treatment for particular types of puttable financial instruments that have
characteristics similar to ordinary shares. IAS 32 previously required that such financial instruments be classified
as a financial liability. The new version provides for reporting such instruments as equity if the holder can
require the issuer to deliver a pro rata share of the net assets of the entity only on liquidation. The amendments
are to be applied for fiscal years beginning on or after January 1, 2009. The amendments have not yet been
F-25
transferred by the EU into European law. E.ON is currently evaluating the potential effects of the amendments to
IAS 32 and IAS 1.
IFRIC 11, “IFRS 2—Group and Treasury Share Transactions”
IFRIC 11, “IFRS 2—Group and Treasury Share Transactions” (“IFRIC 11”), addresses how to apply IFRS 2
to share-based payment arrangements in which an entity’s own equity instruments or equity instruments of
another company in the same group are granted. IFRIC 11 requires share-based compensation systems in which a
company receives goods or services as consideration for its own equity instruments to be accounted for as equitysettled share-based payment transactions. IFRIC 11 further provides guidance on how share-based compensation
systems in which a parent company’s equity instruments are granted should be accounted for at a member of a
group of companies. IFRIC 11 is to be applied for fiscal years beginning on or after March 1, 2007. The adoption
of IFRIC 11 will not have a material impact on E.ON’s Consolidated Financial Statements.
IFRIC 12, “Service Concession Arrangements”
IFRIC 12, “Service Concession Arrangements” (“IFRIC 12”), governs accounting for arrangements in
which a public-sector institution grants contracts to private companies for the performance of public services. In
performing these services, the private company uses infrastructure that remains under the control of the publicsector institution. The private company is responsible for the construction, operation, and maintenance of the
infrastructure. IFRIC 12 is to be applied for fiscal years beginning on or after January 1, 2008; however, it has
not yet been transferred by the EU into European law. E.ON is currently evaluating the potential effects of an
introduction of IFRIC 12.
IFRIC 13, “Customer Loyalty Programmes”
IFRIC 13, “Customer Loyalty Programmes” (“IFRIC 13”), addresses accounting by entities that grant
loyalty award credits. The interpretation clarifies how such entities should account for their obligations to
provide free or discounted goods or services to customers who redeem award credits. The provisions of IFRIC 13
are to be applied for fiscal years beginning on or after July 1, 2008. However, the interpretation has not yet been
transferred by the EU into European law. The adoption of IFRIC 13 will not have a material impact on E.ON’s
Consolidated Financial Statements.
IFRIC 14, “IAS 19—The Limit on a Defined Benefit Asset, Minimum Funding Requirements and Their
Interaction”
IFRIC 14, “IAS 19—The Limit on a Defined Benefit Asset, Minimum Funding Requirements and Their
Interaction” (“IFRIC 14”), provides general guidance on how to assess the limit in IAS 19 on the amount of the
surplus that can be recognized as an asset. The interpretation also explains how the pension asset or liability for
defined benefit plans may be affected when there is a statutory or contractual minimum funding requirement.
Under IFRIC 14 no additional liability needs to be recognized by the employer unless the contributions that are
payable under the minimum funding requirement cannot be returned to the Company. The interpretation is
mandatory for fiscal years beginning on or after January 1, 2008; however, it has not yet been transferred by the
EU into European law. The adoption of IFRIC 14 will not have a material impact on E.ON’s Consolidated
Financial Statements.
F-26
(3)
SCOPE OF CONSOLIDATION
The number of consolidated companies changed as follows during the reporting year:
Scope of Consolidation
Domestic
Foreign
Total
Consolidated companies as of January 1, 2006 . . . . . . . . . . . . . . . . . . . . .
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposals/Mergers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
129
15
5
379
18
35
508
33
40
Consolidated companies as of December 31, 2006 . . . . . . . . . . . . . . . . .
139
362
501
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Disposals/Mergers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23
9
100
24
123
33
Consolidated companies as of December 31, 2007 . . . . . . . . . . . . . . . . .
153
438
591
In 2007, a total of 107 domestic and 78 foreign associated companies were accounted for under the equity
method (2006: 108 domestic and 60 foreign).
See Note 4 for additional information on acquisitions, disposals and discontinued operations.
(4)
ACQUISITIONS, DISPOSALS AND DISCONTINUED OPERATIONS
Acquisitions in 2007
OGK-4
On October 12, 2007, E.ON acquired from the Russian government’s energy holding company RAO UES a
majority stake in the Russian power-plant company OAO OGK-4 (“OGK-4”), Surgut, Tyumenskaya Oblast,
Russian Federation. After the acquisition of additional smaller tranches following the purchase of the majority
stake, E.ON holds 72.7 percent of OGK-4 as of the balance sheet date. The total expense incurred for this
acquisition, which includes a contractually agreed capital increase of €1.3 billion to finance the investment
program planned for the coming years, was approximately €4.4 billion.
Under Russian capital-markets legislation, E.ON was required to make a public offer to purchase the
remainder of the shares held by the minority shareholders of OGK-4, and this offer, at a price of 3.3503 rubles
per share, was made public on November 15, 2007. The acceptance period ended on February 4, 2008. E.ON was
thus able to acquire additional shares equivalent to approximately 3.4 percent of OGK-4 and increase its total
ownership stake to approximately 76.1 percent. As was expected, RAO UES did not accept the offer for its 22.5
percent stake in OGK-4.
OGK-4 operates conventional power plants at five locations with a total installed output of 8.6 gigawatts
(GW) and plans to build additional power plants with a capacity of about 2.4 GW at the existing locations by
2011.
The initial recognition of the company in the E.ON Consolidated Financial Statements took place in the
fourth quarter of 2007.
The E.ON Consolidated Financial Statements included revenues of €248 million and earnings of €3 million
(after write-down of fair value adjustments from the purchase price allocation) attributable to OGK-4 for the
period from October 1 through December 31, 2007. OGK-4’s revenues and earnings for the full year amounted to
€898 million and €29 million, respectively.
F-27
The purchase price allocation for OGK-4 was not final as of December 31, 2007, because effects on
property, plant and equipment and also from potential obligations, in particular, remain to be evaluated.
Major Balance Sheet Line Items—OGK-4
IFRS carrying
amounts before
initial recognition
Purchase price
allocation
Carrying amounts
at initial
recognition
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
738
1,497
—
2,212
5
11
2,950
1,502
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,246
2,217
4,463
Non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
210
124
529
—
739
124
Total equity and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
334
529
863
Net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to shareholders of E.ON AG . . . . . . . . . . . . .
Attributable to minority interests . . . . . . . . . . . . . . . . . . . .
1,912
1,390
522
€ in millions
1,688
(1,390)
461
Total acquisition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,350
Goodwill (preliminary) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,733
3,600
—
983
1,733
ENERGI E2 Renovables Ibéricas
On August 13, 2007, E.ON Climate & Renewables GmbH acquired a 100-percent stake in ENERGI E2
Renovables Ibéricas S.L.U. (“E2-I”), Madrid, Spain. The purchase price totaled roughly €481 million. E2-I and
its affiliated companies were fully consolidated as of August 31, 2007. Through its affiliated and associated
companies, E2-I primarily operates wind farms in Spain and Portugal with an installed generating capacity of
260 megawatts (MW). A more extensive development project pipeline is in place for the coming years. The
purchase price allocation is still preliminary as a definitive clarification of certain technical issues remains
outstanding.
The E.ON Consolidated Financial Statements included revenues of €5 million and a loss of €1 million (after
write-down of fair-value adjustments from the purchase price allocation) attributable to E2-I for the period from
September 1 through December 31, 2007. E2-I’s revenues and earnings for the full year amounted to roughly
€15 million and €4 million, respectively.
Airtricity
On December 18, 2007, E.ON North America Holdings LLC acquired all the shares of Airtricity Inc.,
Chicago, Illinois, U.S., and all the shares of Airtricity Holdings (Canada) Ltd., Toronto, Ontario, Canada, for a
purchase price of approximately €580 million. Airtricity operates a number of wind farms in the U.S. states of
Texas and New York with a total installed output of around 250 MW. Additional wind farms with greatly
enhanced generating capacity are to be completed by the end of 2008. As the timing of this consolidation is so
close to the preparation of the Consolidated Financial Statements, the entire difference between the purchase
price and Airtricity’s equity is being carried provisionally as goodwill.
For the full year, Airtricity generated revenues of roughly €9 million and a loss of approximately €44
million.
F-28
Major Balance Sheet Line Items—E.ON Climate & Renewables (E2-I and Airtricity)
IFRS carrying
amounts before
initial recognition
€ in millions
Purchase price
allocation
Carrying amounts
at initial
recognition
Intangible assets and acquired goodwill . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
74
934
202
231
31
218
305
965
420
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,210
480
1,690
Non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
335
828
143
5
478
833
Total equity and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,163
148
1,311
Net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Attributable to shareholders of E.ON AG . . . . . . . . . . . . .
Attributable to minority interests . . . . . . . . . . . . . . . . . . . .
47
43
4
332
(43)
32
Total acquisition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,061
Goodwill (preliminary) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
718
379
—
36
718
Disposals and Discontinued Operations in 2007
ONE
E.ON and its partners Telenor and Tele Danmark had signed a contract in June 2007 to sell their shares in
the Austrian telecommunications company ONE GmbH (“ONE”), Vienna, Austria, to a consortium of bidders
consisting of France Télécom and the financial investor Mid Europa Partners. The transfer of E.ON’s 50.1percent stake became effective on October 2, 2007. In the fourth quarter of 2007, E.ON realized cash proceeds of
€569 million from the sale, including the consideration for the shareholder loans granted, as well as a disposal
gain of €321 million.
RAG
On August 7, 2007, E.ON, ThyssenKrupp and RWE came to an agreement with the foundation “RAGStiftung” to sell their shares of RAG AG (“RAG”), Essen, Germany, to that foundation. The three shareholding
companies held a total of 90 percent of the share capital of RAG. The block of E.ON shares was transferred on
November 30, 2007, for a price of €1.
The following were the effects arising from discontinued operations:
WKE
Through Western Kentucky Energy Corp. (“WKE”), Henderson, Kentucky, U.S., E.ON U.S. has a 25-year
lease on and operates the generating facilities of Big Rivers Electric Corporation (“BREC”), a power generation
cooperative in western Kentucky, and a coal-fired facility owned by the city of Henderson, Kentucky, U.S.
In March 2007, E.ON U.S. entered into a termination agreement with BREC to terminate the lease and the
operational agreements for nine coal-fired and one oil-fired electricity generation units in western Kentucky,
which were all held through its wholly-owned company WKE and its subsidiaries.
The closing of the agreement is subject to a number of conditions, including review and approval by various
regulatory agencies and acquisition of certain consents by other interested parties. Subject to such contingencies,
the parties are working on completing the termination transaction by mid-2008. WKE therefore continued to be
classified as a discontinued operation.
F-29
The tables below provide selected financial information from the discontinued WKE operations in the U.S.
Midwest segment for the periods indicated:
Selected Financial Information—WKE
(Summary)
€ in millions
2007
2006
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income/(expenses), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
204
(338)
227
(129)
Income from continuing operations before income taxes and minority interests . .
(134)
98
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
(34)
Income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(81)
64
Major Balance Sheet Line Items—WKE
(Summary)
December 31
€ in millions
2007
2006
January 1
2006
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
202
362
215
396
211
471
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
564
611
682
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
613
615
836
In addition, there were other gains from discontinued operations recognized in 2007. These relate to
€418 million in intercompany gains from the sale of tranches of Degussa shares to RAG from previous years and
arose from the transfer to RAG-Stiftung on November 30, 2007, of E.ON’s shareholding in RAG. Moreover,
there were €6 million in gains from the discontinued operations of the Company’s former Viterra segment, which
had already been disposed of in 2005, as well as a loss of €13 million from the sale of the former Oil segment.
Acquisitions in 2006
JČP/DDGáz
In the course of portfolio adjustments undertaken in the Czech Republic and Hungary, minority
shareholdings in various companies were sold. In exchange, E.ON acquired, in addition to two other minority
shareholdings, a further 46.7 percent of the company Jihočeská plynárenská, a.s. (“JČP”), České Budějovice,
Czech Republic, in which E.ON previously held a 13.1 percent share. This company was fully consolidated as of
September 1, 2006. An additional 39.2 percent interest was acquired in a separate transaction, which also took
place in September. E.ON thus held 99.0 percent of JČP. The remaining stake in JČP was purchased in 2007.
As part of the portfolio adjustment, an additional 49.9 percent interest was acquired in the fully consolidated
company Dél-dunántúli Gázszolgáltató ZRt. (“DDGáz”), Pécs, Hungary, in which E.ON previously held 50.02
percent interest. As a result E.ON held 99.9 percent of DDGáz.
The exchange transaction resulted in total acquisition costs of €104 million, taking into account a total cash
component of €30 million. The gains on the disposal of the minority interests totaled €31 million.
F-30
E.ON Földgáz Storage/E.ON Földgáz Trade
As of March 31, 2006, E.ON Ruhrgas had acquired a 100 percent interest in the gas trading and storage
business of the Hungarian oil and gas company MOL through the acquisition of interests in MOL Földgázellátó
ZRt. (now E.ON Földgáz Storage) and MOL Földgáztároló ZRt. (now E.ON Földgáz Trade), both of Budapest,
Hungary. The purchase price was approximately €400 million. It had been agreed that, contingent on regulatory
developments in Hungary, compensatory payments may be required until the end of 2009. The companies were
fully consolidated as of March 31, 2006. As of December 31, 2006, the purchase price allocation resulted in
preliminary goodwill of €119 million, which in 2007 was adjusted by €9 million to €110 million.
Disposals and Discontinued Operations in 2006
The following were reported as discontinued operations in 2006: E.ON Finland, Espoo, Finland, (“E.ON
Finland”) in the Nordic market unit, the operations of WKE in the U.S. Midwest market unit, and Degussa. In
addition, E.ON recorded a gain of approximately €54 million (net of tax: €53 million) in 2006 from a purchase
price adjustment on the disposal of Viterra.
E.ON Finland
On June 26, 2006, E.ON Nordic and the Finnish energy group Fortum Power and Heat Oy (“Fortum”)
finalized the transfer to Fortum of all of E.ON Nordic’s shares in E.ON Finland pursuant to an agreement signed
on February 2, 2006. The purchase price for the 65.56 percent stake totaled approximately €390 million. E.ON
Finland was classified as a discontinued operation in mid-January 2006.
The table below provides selected financial information from the discontinued operations of the Nordic
segment for the periods indicated:
Selected Financial Information—E.ON Finland (Summary)
€ in millions
2006
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on disposal, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income/(expenses), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
131
11
(115)
Income from continuing operations before income taxes and minority interests . . . . . . . . .
27
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(7)
Income from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
Degussa
In December 2005, E.ON and RAG signed a framework agreement on the sale of E.ON’s 42.9 percent stake
in Degussa to RAG. As part of the implementation of that framework agreement, E.ON transferred its stake in
Degussa into RAG Projektgesellschaft mbH, Essen, Germany on March 21, 2006. E.ON’s stake in this entity was
forward sold to RAG on the same date. On July 3, 2006, E.ON and RAG executed the forward sales agreement
for E.ON’s stake in RAG Projektgesellschaft mbH. Thus E.ON has sold its entire remaining, indirectly held stake
in Degussa.
RAG paid E.ON the roughly €2.8 billion purchase price on August 31, 2006. The transaction initially
resulted in a gain of €981 million, which subsequently had to be adjusted for the intercompany gain attributable
to E.ON’s minority ownership interest in RAG (39.2 percent). An initial gain of €596 million was thus realized
from the transfer and the subsequent sale.
F-31
As the interest in Degussa qualified as a discontinued operation under IFRS 5, “Non-current Assets Held for
Sale and Discontinued Operations” (“IFRS 5”), until its disposal, this gain, together with the effect of the equitymethod measurement of Degussa in the first quarter of 2006 of €37 million was reported as income from
discontinued operations in E.ON’s Consolidated Financial Statements. In total, income of €633 million was
recognized for Degussa.
Intercompany gains arising from the sale of tranches of Degussa shares to RAG totaled €418 million as of
December 31, 2006.
(5)
REVENUES
Revenues are generally recognized upon delivery of products to customers or upon fulfillment of services.
Delivery is considered to have occurred when the risks and rewards associated with ownership have been
transferred to the buyer, compensation has been contractually established and collection of the resulting
receivable is probable.
Revenues are generated primarily from the sale of electricity and gas to industrial and commercial
customers and to retail customers. Additional revenue is earned from the distribution of gas and electricity and
deliveries of steam and heat.
Revenues from the sale of electricity and gas to industrial and commercial customers and to retail customers
are recognized when earned on the basis of a contractual arrangement with the customer; they reflect the value of
the volume supplied, including an estimated value of the volume supplied to customers between the date of their
last meter reading and period-end.
The classification of revenues by segment is presented in Note 33.
(6)
OWN WORK CAPITALIZED
Own work capitalized amounted to €517 million in 2007 (2006: €395 million) and resulted primarily from
engineering services rendered in connection with new construction projects.
(7)
OTHER OPERATING INCOME AND EXPENSES
The table below provides details of other operating income for the periods indicated:
Other Operating Income
€ in millions
2007
Income from exchange rate differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,284
2006
4,439
Gain on derivative financial instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,767 1,087
Gain on disposal of investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,588
981
Other trade income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
232
169
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
905 1,238
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,776
7,914
Realized gains from currency derivatives and the effects of positive exchange rate differences recognized in
income are reported as income from exchange rate differences.
Gains on derivative financial instruments include the gains recognized as a result of the required marking to
market and realized gains from derivatives under IAS 39, except for the income effects from interest rate
derivatives.
F-32
Gains on the disposal of investments included proceeds from the sale of ONE in the amount of €321 million.
The line item further included gains realized on the sale of securities in the amount of €1,128 million (2006: €613
million). In 2006, this line item also included gains from the disposal of institutional securities funds as part of
the transfer to the Contractual Trust Arrangement (“CTA”) in the amount of €159 million (see also Note 24).
Miscellaneous other operating income in 2007 consisted primarily of reductions of valuation allowances on
accounts receivable, rental and leasing income, the sale of scrap metal and materials, as well as compensation
payments received for damages.
The following table provides details of other operating expenses for the periods indicated:
Other Operating Expenses
€ in millions
2007
2006
Loss from exchange rate differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivative financial instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,218
1,331
216
138
4,821
4,447
3,052
190
125
4,093
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,724
11,907
Realized losses from currency derivatives and the effects of negative exchange rate differences recognized
in income are reported as losses from exchange rate differences.
Losses on derivative financial instruments include losses recognized as a result of the required marking to
market and realized losses from derivatives under IAS 39, except for the income effects from interest rate
derivatives.
Miscellaneous other operating expenses in 2007 consisted primarily of concession payments in the amount
of €471 million (2006: €512 million), expenses for external audit and nonaudit services and consulting in the
amount of €414 million (2006: €263 million), advertising and marketing expenses in the amount of €360 million
(2006: €281 million), as well as write-downs of receivables in the amount of €333 million (2006: €293 million).
Additionally reported in this item are services rendered by third parties, IT expenditures and insurance premiums.
(8)
COST OF MATERIALS
The principal components of expenses for raw materials and supplies and for purchased goods are the
purchase of gas and electricity and of fuels for electricity generation, as well as the nuclear segment. Expenses
for purchased services consist primarily of maintenance costs. Network usage charges are also included in the
cost of materials.
Cost of Materials
€ in millions
2007
2006
Expenses for raw materials and supplies and for purchased goods . . . . . . . . . . . . .
Expenses for purchased services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
47,667
2,556
44,171
2,537
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50,223
46,708
F-33
(9)
FINANCIAL RESULTS
The following table provides details of financial results for the periods indicated:
Financial Results
€ in millions
2007
2006
Income from companies in which equity investments are held . . . . . . . . . . . . . . . . .
Impairment of other financial assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
215
(36)
209
(159)
Income from equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loans and receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Held for trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
179
207
696
51
81
50
216
779
53
121
Income from securities, interest and similar income . . . . . . . . . . . . . . . . . . . . . .
Amortized cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Held for trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other interest expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,035
(929)
(78)
(979)
1,169
(988)
(142)
(1,084)
Interest and similar expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,986)
(2,214)
Net interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(951)
(1,045)
Financial results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(772)
(995)
The measurement categories are described in detail in Note 2.
Reduced impairments of minority shareholdings and lower interest expenses led to a significant
improvement in financial results for 2007 as compared with the previous year.
A total of €140 million in impairment charges that arose in connection with changes in network regulation
on minority interests in Germany were recognized in 2006 as impairments of other financial assets.
Net interest and similar expenses improved in 2007 primarily as a result of an increase in expected returns
on plan assets determined in connection with the measurement of the provisions for pensions and similar
obligations.
Other interest income consists mostly of the income from lease receivables (finance leases). Other interest
expense includes accretion of provisions for asset retirement obligations in the amount of €708 million (2006:
€713 million).
Also included in this item is the interest expense from provisions for pensions—net of the expected return
on plan assets—in the amount of €79 million (2006: €242 million).
The accretion of liabilities in connection with put options resulted in an expense of €22 million (2006: €102
million) pursuant to IAS 32.
Interest expense was reduced by capitalized interest on debt totaling €62 million (2006: €27 million).
Realized gains and losses from interest rate swaps are shown net.
F-34
(10)
INCOME TAXES
The following table provides details of income taxes, including deferred taxes, for the periods indicated:
Income Taxes
€ in millions
2007
Current taxes
Domestic corporate income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Domestic trade tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
931
735
648
10
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,324
2006
(407)
354
553
5
505
Deferred taxes
Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(149)
114
(61)
(404)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(35)
(465)
Total Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,289
40
The increase in tax expense of €2,249 million compared with 2006 primarily reflects the special effect of
first-time capitalization of discounted corporate tax credits which in 2006 had produced tax income of €1,279
million. The remainder of the increase is attributable to increased earnings.
The Corporate Tax Reform Act of 2008, which took effect on August 18, 2007, provides for extensive tax
changes in Germany. In particular, the corporate income tax rate is cut from 25 percent in 2007 to 15 percent in
2008, while the average domestic trade tax rises from 13 percent in 2007 to 14 percent in 2008. The solidarity
surcharge remains unchanged at 5.5 percent of the corporate income tax rate. The change in the overall tax rate
from the previous rate of 39 percent to 30 percent necessitates a revaluation of all domestic deferred tax assets
and deferred tax liabilities as of December 31, 2007. This revaluation in 2007 produced non-cash deferred tax
income in the amount of €59 million.
German legislation providing for fiscal measures to accompany the introduction of the European Company
and amending other fiscal provisions (“SE-Steuergesetz” or “SEStEG”), which came into effect on December 13,
2006, altered the regulations on corporate tax credits arising from the corporate imputation system
(“Anrechnungsverfahren”), which had existed until 2001. The change de-links the corporate tax credit from
distributions of dividends. Instead, after December 31, 2006, an unconditional claim for payment of the credit in
ten equal annual installments from 2008 through 2017 has been established. While the recognition of the
discounted credits resulted in tax income of €1,279 million in 2006, the change in corporate tax credits resulted
in tax income of €75 million in 2007.
With the entry into force on December 29, 2007, of the Annual Tax Act of 2008 in Germany, those
currently untaxed income components that until then had been recognized in a type of equity called “EK 02” now
have to be declared retrospectively irrespective of distributions. Taxes on this income must be paid in up to ten
equal annual installments, with the first payment due on September 30, 2008. This so-called corporate income
tax surcharge is equal to 3 percent of the EK 02 calculated as of December 31, 2006. This produces a gross
amount of €88 million. A one-time payment option is also available. Assuming a scheduled payment on
September 30, 2008, the tax expense for 2007 is €70 million.
No deferred tax liabilities were recognized in 2006 for the differences between net assets and the tax bases
of subsidiaries and associated companies (the so-called “outside basis differences”). As of December 31, 2007,
F-35
deferred tax liabilities amounted to €7 million. Deferred tax liabilities were not recognized for subsidiaries and
associated companies to the extent that the Company can control the reversal effect and insofar as it is probable
that temporary differences will not be reversed in the foreseeable future. No deferred tax liabilities were
recognized for temporary differences of €1,646 million (2006: €1,335 million) at subsidiaries and associated
companies, as E.ON is able to control the timing of their reversal and the temporary difference will not reverse in
the foreseeable future.
Changes in tax rates in the United Kingdom, the Czech Republic and a number of other countries resulted in
deferred tax income of €118 million. In 2006, changes in foreign tax rates produced total deferred tax income of
€21 million.
The differences between the 2007 base income tax rate of 39 percent (2006: 39 percent) applicable in
Germany and the effective tax rate are reconciled as follows:
Reconciliation to Effective Income Taxes/Tax Rate
2007
€ in millions
%
2006
€ in millions
%
Expected corporate income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Credit for dividend distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign tax rate differentials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in tax rate/tax law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax effects on tax-free income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax effects on equity accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,776
(75)
(405)
(177)
(790)
(353)
313
39.0
(0.8)
(4.2)
(1.8)
(8.2)
(3.6)
3.2
2,085
(76)
(71)
(21)
(491)
(227)
(1,159)
39.0
(1.4)
(1.3)
(0.4)
(9.2)
(4.2)
(21.7)
Effective income taxes/tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,289
23.6
40
0.8
(1) Income from capitalization of corporate tax credits in 2006: €(1,279) million.
As discussed in Note 4, the corporate income taxes relating to discontinued operations are reported in
E.ON’s Consolidated Statement of Income under “Income/Loss from discontinued operations, net,” and break
down as follows:
Income Taxes from Discontinued Operations
€ in millions
2007
2006
WKE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
E.ON Finland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Viterra . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(53)
—
—
34
7
1
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(53)
42
Income from continuing operations before income taxes and minority interests was attributable to the
following geographic locations in the periods indicated:
€ in millions
2007
2006
Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,500
4,183
3,463
1,884
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,683
5,347
F-36
Deferred tax assets and liabilities as of December 31, 2007, and December 31, 2006, break down as shown
in the following table:
Deferred Tax Assets and Liabilities
December 31
€ in millions
2007
2006
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
73
608
138
9
70
3,107
2,070
452
81
163
62
647
209
12
397
4,209
2,418
613
38
187
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,771
8,792
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(212)
(435)
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,559
8,357
Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,033
6,501
1,727
176
1,946
443
253
880
1,101
6,547
1,977
246
2,076
502
178
1,546
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,959
14,173
Net deferred tax assets/liabilities (–) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(6,400) (5,816)
Of the deferred taxes reported, a total of €2,246 million was charged directly to equity in 2007 (2006:
€2,223 million).
Net deferred taxes break down as follows based on the timing of their reversal:
Net Deferred Tax Assets and Liabilities
December 31, 2007
current
non-current
€ in millions
December 31, 2006
current
non-current
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
298
(4)
1,069
(208)
254
(11)
1,428
(424)
Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . .
294
861
243
1,004
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
(712)
(6,843)
(568)
(6,495)
Net deferred tax assets/liabilities (–) . . . . . . . . . . . . .
(418)
(5,982)
(325)
(5,491)
In the acquisition of OGK-4, the purchase price allocation resulted in deferred tax liabilities of €529 million
as of December 31, 2007. The purchase price allocation for E2-I resulted in deferred tax liabilities of
€148 million as of December 31, 2007.
F-37
The purchase price allocations of other acquisitions resulted in the recognition on December 31, 2007, of a
total of €19 million in deferred tax liabilities.
The acquisitions of DDGáz, E.ON Földgáz Trade, E.ON Földgáz Storage, Somet and E.ON Värme resulted
in the recognition on December 31, 2006, of a total of €6 million in deferred tax assets and €27 million in
deferred tax liabilities.
The tax loss carryforwards as of the dates indicated are as follows:
Tax Loss Carryforwards
December 31
2007
2006
€ in millions
Domestic tax loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign tax loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,646
739
2,016
956
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,385
2,972
Since January 1, 2004, domestic tax loss carryforwards can only be offset against up to 60 percent of taxable
income, subject to a full offset against the first €1 million. This minimum corporate taxation also applies to trade
tax loss carryforwards.
Of the tax credits for which no deferred taxes have been recognized, €12 million expire after 2012.
(11)
PERSONNEL-RELATED INFORMATION
Personnel Costs
The following table provides details of personnel costs for the periods indicated:
Personnel Costs
€ in millions
2007
2006
Wages and salaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Social security contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension costs and other employee benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,692
556
349
327
3,553
580
396
377
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,597
4,529
In 2007, E.ON purchased on the market a total of 373,905 of its own shares (0.05 percent of the shares of
E.ON AG) for resale to employees as part of the employee stock purchase program at an average purchase price
of €121.10 per share (in 2006, treasury share usage: 443,290 shares; 0.06 percent). These shares were sold to
employees at preferential prices between €45.20 and €104.64 (2006: between €38.37 and €74.77). The costs
arising from the granting of these preferential prices were charged to personnel costs as “wages and salaries.”
Further information about the changes in the number of its own shares held by E.ON AG can be found in
Note 19.
Since the 2003 fiscal year, employees in the U.K. have the opportunity to purchase E.ON shares through an
employee stock purchase program and to acquire additional bonus shares. The cost of issuing these bonus shares
is also recorded under personnel costs as part of “Wages and salaries.”
F-38
Share-Based Payment
Members of the Board of Management of E.ON AG and certain executives of E.ON AG and of the market
units receive share-based payment as part of their long-term variable compensation. Share-based payment can
only be granted if the qualified executive owns a certain minimum number of shares of E.ON stock, which must
be held until maturity or full exercise. The purpose of such compensation is to reward their contribution to
E.ON’s growth and to further the long-term success of the Company. This variable compensation component,
comprising a long-term incentive effect along with a certain element of risk, provides for a sensible linking of the
interests of shareholders and management.
The following discussion includes a report on the E.ON AG Stock Appreciation Rights plan, which ended in
2005, and on the E.ON Share Performance Plan, newly introduced in 2006.
Stock Appreciation Rights of E.ON AG
From 1999 up to and including 2005, E.ON annually granted virtual stock options (“Stock Appreciation
Rights” or “SAR”) through the E.ON AG Stock Appreciation Rights program. The third tranche of SAR was
exercised in full in 2007. SAR from the fourth through seventh tranches may still be exercised after the end of
the program, in accordance with the SAR terms and conditions.
Stock Appreciation Rights of E.ON AG
7th tranche
6th tranche
5th tranche
4th tranche
3rd tranche
Date of issuance . . . . . . . . . . . . . . . . . . . Jan. 3, 2005 Jan. 2, 2004 Jan. 2, 2003 Jan. 2, 2002 Jan. 2, 2001
Term . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7 years
7 years
7 years
7 years
7 years
Blackout period . . . . . . . . . . . . . . . . . . . .
2 years
2 years
2 years
2 years
2 years
Price at issuance (1) . . . . . . . . . . . . . . . .
€61.10
€44.80
€37.86
€50.70
€58.70
Level of the Dow Jones STOXX
Utilities Index (Price EUR) . . . . . . . .
268.66
211.58
202.14
262.44
300.18
Number of participants in year of
issuance . . . . . . . . . . . . . . . . . . . . . . . .
357
357
344
186
231
Number of SAR issued . . . . . . . . . . . . . .
2.9 m
2.7 m
2.6 m
1.7 m
1.8 m
Exercise hurdle (minimum percentage
by which exercise price exceeds the
price at issuance) . . . . . . . . . . . . . . . .
10%
10%
10%
10%
20%
Exercise hurdle (minimum exercise
price) (1) . . . . . . . . . . . . . . . . . . . . . . .
€67.21
€49.28
€41.65
€55.77
€70.44
Maximum exercise gain . . . . . . . . . . . . .
€65.35
€49.05
—
—
—
(1) Adjusted for special dividend distribution in 2006.
SAR can be exercised by eligible executives following the blackout period within preset exercise windows,
provided that the exercise thresholds have been crossed.
The amount paid to executives when they exercise their SAR is paid out in cash, and is equal to the
difference between the E.ON AG share price at the time of exercise and the underlying share price at issuance
multiplied by the number of SAR exercised. Beginning with the sixth tranche, a cap on gains on SAR equal to
100 percent of the underlying price at the time of issuance was put in place in order to limit the effect of
unforeseen extraordinary increases in the underlying share price. This cap on gains took effect for the first time
in the 2006 fiscal year.
In accordance with IFRS 2 measurement criteria, the SAR were measured by reference to the fair value of
the rights as of December 31, 2007.
F-39
A recognized option pricing model is used for measuring the value of these options. This option pricing
model simulates a large number of different possible developments of the E.ON share price and the benchmark
Dow Jones STOXX Utilities Index (Price EUR) (Monte Carlo simulation).
A certain exercise behavior is assumed when determining fair value. Individual exercise rates are defined
for each of the tranches, depending on the price performance of the E.ON share. Historical volatility and
correlations of the E.ON share price and of the benchmark index that reflect remaining maturities are used in the
calculations. The risk-free interest rate used for reference is the zero swap rate for the corresponding remaining
maturity. The dividend yields of the E.ON share (2.30 percent) and of the benchmark index (3.18 percent) are
also included in the pricing model. The dividend yield used for the E.ON share in the calculations is based on the
ratio of the most recent dividend distributed and the share price on the valuation date. Accordingly, as of the
balance sheet date, this yield corresponds approximately to the anticipated future dividend yield. The average of
the Xetra closing prices for E.ON AG shares was €118.08 in 2007. The Xetra closing price for E.ON AG shares
at year-end was €145.59. The Dow Jones STOXX Utilities Index (Price EUR) closed at 549.75 points.
The following overview contains additional parameters used for measurement:
SAR Program of E.ON AG—Measurement Parameters of the Option Pricing Model
7th tranche
Intrinsic value as of December 31, 2007 . . . . . . . . . . . . . . . . . . .
Fair value as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . .
Swap rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Volatility of the E.ON share . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Volatility of the Dow Jones STOXX Utilities Index (Price
EUR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Correlation between the E.ON share price and the Dow Jones
STOXX Utilities
Index (Price EUR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6th tranche
5th tranche
4th tranche
€65.35
€64.09
4.43%
25.61%
€49.05
€48.64
4.42%
25.47%
€107.73
€104.39
4.45%
24.44%
€94.89
€93.81
4.55%
21.97%
14.74%
14.78%
14.54%
13.78%
0.7015
0.7191
0.7492
0.7845
2,902,786 SAR from tranches three through seven were exercised on an ordinary basis in 2007. In addition,
100,349 SAR from tranches three, four, five, and seven were exercised in accordance with the SAR terms and
conditions on an extraordinary basis. The total gain to the holders on exercise amounted to €163.2 million (2006:
€134.4 million). 7,000 SAR from tranche three expired during 2007.
The provision for the SAR program was €23.2 million as of the balance sheet date (2006: €143.1 million).
The expense for the 2007 fiscal year amounted to €43.4 million (2006: €113.0 million).
F-40
The number of SAR, provisions for and expenses arising from the E.ON SAR program have changed as
shown in the following table:
Changes in the E.ON AG SAR Program
7th tranche
6th tranche
5th tranche
4th tranche
3rd tranche
SAR outstanding as of December 31, 2005 . . . . . . .
SAR granted in 2006 . . . . . . . . . . . . . . . . . . . . . . . .
SAR exercised in 2006 . . . . . . . . . . . . . . . . . . . . . .
SAR expired in 2006 . . . . . . . . . . . . . . . . . . . . . . . .
2,885,428
—
49,511
26,041
2,417,995
—
2,349,731
13,717
613,711
—
346,358
2,423
238,909
—
169,742
—
158,750
—
85,750
—
SAR outstanding as of December 31, 2006 . . . . .
2,809,876
54,547
264,930
69,167
73,000
SAR granted in 2007 . . . . . . . . . . . . . . . . . . . . . . . .
SAR exercised in 2007 . . . . . . . . . . . . . . . . . . . . . .
SAR expired in 2007 . . . . . . . . . . . . . . . . . . . . . . . .
—
2,754,876
—
—
26,547
—
—
113,379
—
—
42,333
—
—
66,000
7,000
SAR outstanding as of December 31, 2007 . . . . .
55,000
28,000
151,551
26,834
Gains on exercise in 2007 . . . . . . . . . . . . . . . . . . . .
Provision as of December 31, 2007 . . . . . . . . . . . . .
Expense in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
€145.3 m
€3.5 m
€31.2 m
€1.3 m
€1.4 m
€0.1 m
€9.2 m
€15.8 m
€8.7 m
€2.8 m
€2.5 m
€2.0 m
—
€4.6 m
€0.0 m
€1.4 m
The SAR of tranches four through seven were exercisable on December 31, 2007.
E.ON Share Performance Plan
In 2007, virtual shares (“Performance Rights”) from the second tranche of the E.ON Share Performance
Plan were granted. For the first time, certain members of senior management were also granted Performance
Rights alongside top management.
E.ON Share Performance Rights
Date of issuance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Target value at issuance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of participants in year of issuance . . . . . . . . . . . . . . . . . . . . . . .
Number of Performance Rights issued . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum amount paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2nd tranche
1st tranche
Jan. 1, 2007
3 years
€96.52
501
395,025
€289.56
Jan. 1, 2006
3 years
€79,22
396
458,641
€237.66
At the end of its three-year term, each Performance Right is entitled to a cash payout linked to the final
E.ON share price established at that time. The amount of the payout is also linked to the relative performance of
the E.ON share price in comparison with the benchmark index Dow Jones STOXX Utilities Index (Total Return
EUR). The amount paid out is equal to the target value of this compensation component if the E.ON share price
at the end of the term is equal to the initial price at the beginning of the term and the performance matches that of
the benchmark. The maximum amount to be paid out to each participant per Performance Right is limited to
three times the original target value on the grant date.
60-day average prices are used to determine the initial price, the final price and the relative performance, in
order to mitigate the effects of incidental, short-lived price movements.
The calculation of the amount to be paid out takes place at the same time for all plan participants with effect
on the last day of the term of the tranche. If the performance of the E.ON share matches that of the index, the
F-41
amount paid out is not adjusted; the final share price is paid out. However, if the E.ON share outperforms the
index, the amount paid out is increased proportionally. If, on the other hand, the E.ON share underperforms the
index, disproportionate deductions are made. In the case of underperformance by 20 percent or more, no payment
at all takes place.
The plan contains adjustment mechanisms to eliminate the effect of events such as interim corporate actions.
Accordingly, to compensate for the economic effects of the special dividend payment of May 5, 2006, capital
adjustment factors were established for the first tranche.
The fair value is determined for the Performance Rights in accordance with IFRS 2 using a recognized option
pricing model. Similar to the option pricing model used for the SAR program, this model involves the simulation of
a large number of different possible development tracks for the E.ON share price (taking into account the effects of
reinvested dividends and capital adjustment factors) and the benchmark index (Monte Carlo simulation). However,
unlike the SAR program, the benchmark for this plan is the Dow Jones STOXX Utilities Index (Total Return EUR),
which stood at 968.95 points on December 31, 2007. Since payments to all plan participants take place on a
specified date, no assumptions concerning exercise behavior are made in this plan structure, and such assumptions
are therefore not considered in this option pricing model. Dividend payments and corporate actions are taken into
account through corresponding factors that are analogous to those employed by the index provider.
E.ON Share Performance Plan—Measurement Parameters of the Option Pricing Model
2nd tranche
Intrinsic value as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Swap rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Volatility of the E.ON share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Volatility of the Dow Jones STOXX Utilities Index (Total Return EUR) . . .
Correlation between the E.ON share price and the Dow Jones STOXX
Utilities Index (Total Return EUR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1st tranche
€162.93
€163.59
4.45%
21.73%
13.46%
€157.47
€158.72
4.55%
21.56%
13.81%
0.7977
0.8056
395,025 second-tranche Performance Rights were granted in 2007. In 2007, the cash amount from 15,500 of
the first and second tranches of Performance Rights was paid out on an extraordinary basis in accordance with
the terms and conditions of the plan. Total payments amounted to €1.6 million (2006: €0.1 million). 4,349 first
and second-tranche Performance Rights expired in the 2007 fiscal year. Provisions for the plan totaled
€67.8 million at year-end (2006: €8.9 million). Each provision is prorated for the respective period elapsed of the
total three-year term. The total expense for the E.ON Share Performance Plan amounted to €60.5 million in 2007
(2006: €9.0 million).
Changes in the E.ON Share Performance Plan
Performance Rights granted in 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settled Performance Rights in 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Performance Rights expired in 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Performance Rights outstanding as of December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
Performance Rights granted in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settled Performance Rights in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Performance Rights expired in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Performance Rights outstanding as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
Cash amount paid in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expense in 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-42
2nd tranche
1st tranche
—
—
—
—
395,025
4,458
1,658
388,909
€0.6 m
€21.2 m
€21.7 m
458,641
2,020
2,020
454,601
—
11,042
2,691
440,868
€1.0 m
€46.6 m
€38.8 m
The first and second tranches were not yet payable on an ordinary basis on the balance sheet date.
The issue of a third tranche of the E.ON Share Performance Plan is planned for 2008.
Employees
During 2007, the Company employed an average of 83,434 people (2006: 80,453), not including 2,352
apprentices (2006: 2,280). The breakdown by market unit is shown below:
Employees
Central Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pan-European Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nordic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Midwest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate Center/New Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(12)
2007
2006
44,054
12,204
16,499
5,872
2,940
1,865
83,434
44,148
12,653
14,599
5,697
2,919
437
80,453
OTHER INFORMATION
German Corporate Governance Code
On December 17, 2007, the Board of Management and Supervisory Board of E.ON AG made a declaration
of compliance pursuant to Article 161 of the German Stock Corporation Act (“AktG”). The declaration was made
publicly accessible on E.ON’s Web site (www.eon.com).
Fees and Services of the Independent Auditor
During 2007 and 2006, the Company incurred the following fees for services provided by its independent
auditor, PwC:
Independent Auditor Fees
€ in millions
Financial statement audits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other attestation services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax advisory services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
2006
33
22
1
1
57
33
25
1
2
61
The fees for the financial statement audits concern the audit of the Consolidated Financial Statements and
the legally mandated financial statements of E.ON AG and its affiliates. This item also includes the additional
fees charged for the audit of internal controls over financial reporting.
Fees for other attestation services concern in particular the review of the interim IFRS financial statements
and, in 2006, the review of the conversion to IFRS. Further included in this item are project-related reviews
connected to the introduction of IT and internal-control systems, due-diligence services rendered in connection
with acquisitions and disposals, and other specific items.
F-43
Fees for tax advisory services primarily include advisory on a case-by-case basis with regard to the tax
treatment of M&A transactions, ongoing consulting related to preparing tax returns and review of tax
assessments, as well as advisory on other tax-related issues, both in Germany and abroad.
Fees for other services consist primarily of technical support in IT projects, technical training measures and
regulatory matters.
Shareholdings and Other Interests
A listing of all shareholdings and other interests of E.ON AG has been compiled and will be published
separately in the Electronic Federal Gazette (“elektronischer Bundesanzeiger”) in Germany. That listing also
contains those shareholdings for which the preparation and publication of consolidated financial statements and
of a corresponding management report under Articles 264 (3) and 264b HGB, respectively, is not required.
(13)
EARNINGS PER SHARE
The computation of basic and diluted earnings per share for the periods indicated is shown below:
Earnings per Share
€ in millions
2007
2006
Income/Loss (–) from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
less: Minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,394
(520)
5,307
(486)
Income/Loss (–) from continuing operations (attributable to shareholders of
E.ON AG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,874
4,821
Income/Loss (–) from discontinued operations, net . . . . . . . . . . . . . . . . . . . . . . . . .
330
775
less: Minority interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
(10)
Income/Loss (–) from discontinued operations, net (attributable to shareholders of
E.ON AG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
330
765
Net income attributable to shareholders of E.ON AG . . . . . . . . . . . . . . . . . . . . . . .
7,204
5,586
10.55
7.31
from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.51
1.16
from net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11.06
8.47
Weighted-average number of shares outstanding (in millions) . . . . . . . . . . . . . . . . . .
651
659
in €
Earnings per share (attributable to shareholders of E.ON AG)
from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The computation of diluted EPS is identical to basic EPS, as E.ON AG has not issued any potentially
dilutive common stock.
F-44
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F-45
(14)
GOODWILL, INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT
Goodwill, Intangible Assets and Property, Plant and Equipment
Acquisition and production costs
€ in millions
Goodwill . . . . . . . . . . . . . . . . . . . . .
Marketing-related intangible
assets . . . . . . . . . . . . . . . . . . . . . .
Customer-related intangible
assets . . . . . . . . . . . . . . . . . . . . . .
Contract-based intangible assets . . .
Technology-based intangible
assets . . . . . . . . . . . . . . . . . . . . . .
Internally generated intangible
assets . . . . . . . . . . . . . . . . . . . . . .
Intangible assets subject to
amortization . . . . . . . . . . . . . . . .
Intangible assets not subject to
amortization . . . . . . . . . . . . . . . . .
Advance payments on intangible
assets . . . . . . . . . . . . . . . . . . . . . .
January 1,
2007
Exchange
rate
differences
Change
in scope
of consolidation
13
Disposals
Transfers
(10)
(229)
(175)
—
December 31,
2007
15,604
(822)
227
(4)
—
2,482
1,694
(98)
(22)
25
305
1
66
(2)
(12)
10
(11)
503
(8)
10
49
(23)
68
218
(21)
—
32
—
5,124
(153)
340
148
(212)
67
5,314
1,263
(43)
—
990
(239)
(400)
1,571
—
—
29
(1)
(13)
30
15
2,489
Additions
—
—
17,045
48
2,418
2,020
599
229
Intangible assets . . . . . . . . . . . . . . .
6,402
(196)
340
1,167
(452)
(346)
6,915
Real estate and lease