OFFERING CIRCULAR
CONFIDENTIAL
Electric Power Development Co., Ltd. OÅering of 138,808,000 Shares of Common Stock OFFER PRICE: Í2,700 PER SHARE The information in this oÅering circular relates to an international oÅering outside Japan of the common stock of Electric Power Development Co., Ltd. (the ""Company''), a joint stock corporation incorporated with limited liability under the laws of Japan. J-POWER Privatization Fund Co., Ltd. (the ""Fund'' or the ""international selling shareholder''), a joint stock corporation formed under the laws of Japan, is oÅering 34,702,000 existing shares of the Company in this international oÅering. The shares being oÅered in the international oÅering, or the international shares, are being underwritten and oÅered by the international managers named herein. See ""OÅering and Sale''. The international shares are being oÅered by the international managers (i) to non-U.S. persons in oÅshore transactions outside the United States and Japan in reliance on Regulation S (""Regulation S'') under the United States Securities Act of 1933, as amended (the ""Securities Act''), and (ii) through U.S. broker-dealer agents of certain international managers, or Rule 144A selling agents, to institutions that are ""qualiÑed institutional buyers'', or QIBs, as deÑned in Rule 144A (""Rule 144A'') under the Securities Act, in the United States in reliance on Rule 144A. The international shares may be resold or transferred only in accordance with the restrictions described under ""Transfer Restrictions''. Concurrently with the international oÅering, 104,106,000 existing shares of the Company, or the Japanese shares, are being sold in a public oÅering in Japan by shareholders of the Company named herein, or the Japanese selling shareholders, in a Japanese oÅering. The Japanese shares are being oÅered by Japanese underwriters led by Nomura Securities Co., Ltd. and UBS Securities Japan Ltd. The closing of the international oÅering is conditional upon the closing of the Japanese oÅering. The Company will not receive any proceeds from the sale of its shares in the oÅerings. Nomura Securities Co., Ltd. and UBS Securities Japan Ltd are the joint global coordinators of the oÅerings. Shares of the Company's common stock currently are not listed on any stock exchange. The Tokyo Stock Exchange, Inc. (the ""Tokyo Stock Exchange'') has approved the listing of the shares. It is expected that the shares will be admitted for trading on the Tokyo Stock Exchange on or about October 6, 2004. INVESTING IN THE INTERNATIONAL SHARES INVOLVES RISKS. TIONS'' BEGINNING ON PAGE 5.
SEE ""INVESTMENT CONSIDERA-
The international managers are oÅering the international shares subject to their acceptance of the international shares and subject to prior sale. The international managers reserve the right to withdraw, cancel or modify orders and to reject any orders in whole or in part. It is expected that payment for the international shares will be made in yen for value, and delivery of the international shares will be made through the facilities of the Japan Securities Depository Center, Inc. (""JASDEC'') in Tokyo, on or about October 6, 2004 (Tokyo time). See ""Clearance and Settlement''. THE INTERNATIONAL SHARES HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE SECURITIES ACT. THE INTERNATIONAL SHARES MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES (AS DEFINED IN REGULATION S) OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, U.S. PERSONS (AS DEFINED IN REGULATION S), EXCEPT TO QIBS IN RELIANCE ON THE EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144A AND TO NON-U.S. PERSONS OUTSIDE THE UNITED STATES IN RELIANCE ON REGULATION S. YOU ARE HEREBY NOTIFIED THAT SELLERS OF THE SHARES MAY BE RELYING ON THE EXEMPTION FROM THE PROVISIONS OF SECTION 5 OF THE SECURITIES ACT PROVIDED BY RULE 144A. THE INTERNATIONAL SHARES OFFERED HEREBY ARE NOT TRANSFERABLE EXCEPT IN ACCORDANCE WITH THE RESTRICTIONS DESCRIBED UNDER ""TRANSFER RESTRICTIONS''.
Joint Global Coordinators and Joint Bookrunners (listed alphabetically)
Nomura Securities
UBS Securities Japan Ltd Joint Lead Managers (listed alphabetically)
Nomura International
UBS Investment Bank International Managers
Daiwa Securities SMBC Europe Merrill Lynch International Deutsche Bank JPMorgan
Morgan Stanley
The date of this oÅering circular is September 27, 2004.
Goldman Sachs International Nikko Citigroup HSBC Lehman Brothers
Electric Power Business Facilities
(As of March 31, 2004)
Oma Tomamae Winvilla
Kitahon HVDC Link
Wind Power (1)
Setana Rinkai Green Power Kuzumaki
Wind Power (3)
Wind Power (1) Nikaho-kogen Wind Power (1)
Okukiyotsu
Tagokura
Okukiyotsu II
Onikobe Okutadami
Itoigawa Shintoyone Miboro Tedorigawa I
Shimogo
Nagano
Numappara Genex Mizue (2)
Honshi Interconnecting Line
Shinminato (3)
Takasago Takehara
Tokyo Rinkai Wind Power (3)
Nagasaki Shikamachi Wind Power (1) Kanmon Interconnecting Line
Ichihara (Ichihara Power Co., Ltd.) (1)
Ichihara (Bay Side Energy Co., Ltd.) (3) Sakuma Matsuura
Isogo New No.1 Isogo New No.2
Sakuma Frequency Ikehara
Converter Station
Tahara Rinkai Wind Power (1)
Tachibanawan Anan Kihoku HVDC Link
Matsushima
Aso Nishihara Wind Power (1)
Notes: (1) Owned and operated by a subsidiary which the Company expects to begin consolidating for financial reporting purposes for the first time beginning the year ending March 31, 2005.
Facilities Hydroelectric power plants Thermal power plants Wind power plants Transmission lines Substations, frequency converter stations and AC/DC converter stations Substations of EPCOs Under Construction and Planning Hydroelectric power plants Thermal power plants Nuclear power plants Wind power plants Transmission lines
(2) Owned and operated by an affiliate not accounted for under the equity method which the Company expects to begin accounting for under the equity method beginning the year ending March 31, 2005. Ishikawa Coal
(3) Owned and operated by an affiliate not accounted for under the equity method or a non-consolidated subsidiary.
IPP Investment Projects (In operation as of
March 31, 2004)
ShanXi TianShi Power Generation Co., Ltd. (2) (Waste Coal) Chiahui Power Corporation (1) Roi-Et Green Co., Ltd. (2)
(Gas Thermal)
(Biomass)
Ormat Leyte Co., Ltd. (3) (Geothermal)
TLP Cogeneration Co., Ltd. (2) (Gas Cogeneration) Gulf Cogeneration Co., Ltd. (1) (Gas Cogeneration) Nong Khae Cogeneration Co., Ltd. (1) SEC HoldCo, S.A. (1)
(Gas Cogeneration) Samutprakarn Cogeneration Co., Ltd. (1)
Thaioil Power Co., Ltd. (1)
(Gas Cogeneration)
(Gas Cogeneration) Independent Power (Thailand) Co., Ltd. (1) (Gas Thermal)
(Wind Power)
Notes: (1) Affiliate accounted for under the equity method. (2) Affiliate not accounted for under the equity method. (3) Minority equity investment.
No person has been authorized in connection with the international oÅering to give any information or to make any representation other than as contained in this oÅering circular and, if given or made, such information or representation must not be relied upon as having been authorized by us, the international selling shareholder, any international manager or any Rule 144A selling agent. The distribution of this oÅering circular and the oÅering and sale of the shares in certain jurisdictions may be restricted by law. Persons into whose possession this oÅering circular comes are required by us and the international managers to inform themselves about and to observe any such restrictions. This oÅering circular does not constitute an oÅer to sell or a solicitation of an oÅer to buy any of the securities oÅered hereby by any person in any jurisdiction in which it is unlawful for such person to make such an oÅering or solicitation. No action has been, or will be, taken to permit a public oÅering of the international shares in any jurisdiction where action would be required for that purpose. Accordingly, the international shares oÅered hereby may not be oÅered or sold, directly or indirectly, and this oÅering circular may not be distributed, in any jurisdiction, except in accordance with the legal requirements applicable in such jurisdiction. Neither delivery of this oÅering circular nor any sale made in connection with this oÅering circular shall under any circumstances imply that the information herein is correct as of any date subsequent to the date hereof. There are restrictions on the oÅer and sale of the international shares in the United Kingdom. All applicable provisions of the Financial Services and Markets Act 2000 with respect to anything done by any person in relation to the international shares in, from, or otherwise involving, the United Kingdom must be complied with. See ""OÅering and Sale''. The international shares have not been and will not be registered under the Securities and Exchange Law of Japan, as amended (the ""Securities and Exchange Law''). Each international manager has represented and agreed that the international shares which it will purchase will be purchased by it as principal and that, in connection with the international oÅering, it will not, directly or indirectly, oÅer or sell any international shares in Japan or to, or for the beneÑt of, any Japanese person (as deÑned below) or to others for reoÅer or resale, directly or indirectly, in Japan or to, or for the beneÑt of, any Japanese person (as deÑned below), except pursuant to any exemption from the registration requirements and from the requirements to deliver a prospectus under the Securities and Exchange Law and otherwise in compliance with the Securities and Exchange Law and other applicable laws and regulations. For the purpose of this paragraph, ""Japanese person'' is deÑned as any individual whose place of abode is in Japan, or any corporation whose principal place of business is in Japan (other than a branch or oÇce located outside Japan of any Japanese person), and includes any Japanese branch or oÇce of a person who is otherwise not a Japanese person. IN MAKING AN INVESTMENT DECISION, INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF US AND THE TERMS OF THE INTERNATIONAL OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THE INTERNATIONAL SHARES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION OR ANY OTHER SECURITIES COMMISSION OR OTHER REGULATORY AUTHORITY, NOR HAVE THE FOREGOING AUTHORITIES APPROVED THIS OFFERING CIRCULAR OR CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS OFFERING CIRCULAR. ANY REPRESENTATION TO THE CONTRARY IS UNLAWFUL. This oÅering circular is personal to each oÅeree and does not constitute an oÅer to any other person or to the public generally to purchase or otherwise acquire international shares. Distribution of this oÅering circular to any person other than the oÅeree and those persons, if any, retained to advise such oÅeree with respect thereto is unauthorized, and any disclosure of any of its contents, without our prior written consent, is prohibited. Each person receiving this oÅering circular acknowledges that: (i) such person has not relied on any international manager, any Rule 144A selling agent or any person aÇliated with the international managers in connection with its investigation of the accuracy of such information or its investment decision; and (ii) no person has been authorized to give any information or to make any representation concerning us or the international shares other than as contained herein and, if given or made, any such other information or representation should not be relied upon as having been authorized by us, the international selling shareholder, any international manager or any Rule 144A selling agent. Prospective purchasers are hereby notiÑed that the seller of any international shares oÅered hereby may be relying on the exemption from the provisions of Section 5 of the Securities Act provided by Rule 144A.
iii
NOTICE TO NEW HAMPSHIRE RESIDENTS NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER RSA 421-b 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 CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-b IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN 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.
AVAILABLE INFORMATION We intend to apply to the United States Securities and Exchange Commission to claim the exemption aÅorded by Rule 12g3-2(b) under the United States Securities Exchange Act of 1934, as amended (the ""Exchange Act''). If, at any time, we are neither subject to Section 13 or 15(d) of the Exchange Act nor exempt from reporting pursuant to Rule 12g3-2(b) under the Exchange Act, we will furnish, upon request, to any holder of the shares, or any prospective purchaser designated by a holder of the shares, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.
ENFORCEMENT OF CIVIL LIABILITIES The Company is a joint stock corporation incorporated with limited liability in Japan. All of our directors, executive oÇcers, corporate auditors and independent auditors named under ""Independent Auditors'', as well as the international selling shareholder and the Japanese selling shareholders, reside outside of the United States. All or substantially all of our assets and the assets of such persons are located outside the United States. As a result, it may not be possible for investors to eÅect service of process within the United States upon such persons with respect to matters arising under United States federal securities laws or to enforce against them judgments of courts of the United States, whether or not predicated upon the civil liability provisions of the federal securities or other laws of the United States or any state thereof. The Company and the international selling shareholder have been advised by their Japanese legal counsel, Tomotsune & Kimura, that there is some doubt as to the enforceability in Japan, in original actions or in actions for enforcement of judgments of United States courts, of liabilities predicated solely upon the federal securities or other laws of the United States or any state thereof.
iv
PRESENTATION OF FINANCIAL AND OTHER INFORMATION In this oÅering circular, references to the ""Company'' refer to Electric Power Development Co., Ltd., and references to ""we'', ""our'', ""us'' and ""J-POWER'' refer to the Company and, unless the context requires otherwise, our consolidated subsidiaries and equity method aÇliates. In this oÅering circular, except as otherwise indicated, currency amounts are expressed in Japanese yen (""yen'' or ""Í'') or in United States dollars (""dollars'', ""U.S.$'', or ""$''). Except as otherwise indicated, for the convenience of the reader, the translations of yen into dollar amounts have been made at the rate of Í105.69 • U.S.$1.00, the approximate rate of exchange prevailing on March 31, 2004, the date of our most recent balance sheet included herein. See ""Exchange Rates'' for information regarding rates of exchange between the yen and the dollar from the year ended March 31, 1999 to the present. The U.S. dollar translations are included solely for the convenience of the reader and are not intended to imply that the assets and liabilities which originated in yen have been or could be readily converted into, realized or settled in U.S. dollars at the above or any other rate. In this oÅering circular, where information is presented in thousands, millions or billions of yen or thousands, millions or billions of dollars, amounts of less than one thousand, one million, or one billion, as the case may be, have been truncated unless otherwise speciÑed. All percentages have been rounded to the nearest percent, one-tenth of one percent or one-hundredth of one percent, as the case may be. In some cases, Ñgures presented in tables in this oÅering circular may not add up due to such rounding or truncating. Our Ñnancial statements are prepared in accordance with accounting principles generally accepted in Japan, or Japanese GAAP, which diÅer in certain respects from accounting principles generally accepted in certain other countries. DiÅerences between Japanese GAAP and accounting principles generally accepted in the United States, or U.S. GAAP, are summarized herein under ""Summary of Certain SigniÑcant DiÅerences between Japanese and U.S. Generally Accepted Accounting Principles''. In accordance with applicable Japanese legal requirements, we prepare audited consolidated Ñnancial statements for each Ñscal year in accordance with Japanese GAAP. Our audited consolidated balance sheets as of March 31, 2002, 2003 and 2004 and the related consolidated statements of income and cash Öows for each of the three years ended March 31, 2004 are contained elsewhere in this oÅering circular. Unless otherwise speciÑed, all Ñnancial information set forth herein is presented on a consolidated basis.
v
FORWARD-LOOKING STATEMENTS This oÅering circular contains statements that constitute ""forward-looking statements'' within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These statements appear in a number of places in this oÅering circular and are based on our current expectations, assumptions, estimates and projections about our Ñnancial condition, results of operations, business and industry. These forward-looking statements are subject to various risks and uncertainties. Generally, these forward-looking statements can be identiÑed by the use of forward-looking terminology such as ""may'', ""will'', ""expect'', ""anticipate'', ""estimate'', ""plan'' or similar words. These statements discuss future expectations, identify strategies, contain projections of results of operations or of our Ñnancial condition, or state other forwardlooking information. We cannot promise that the expectations expressed in these forward-looking statements will turn out to be correct. Known and unknown risks, uncertainties and other factors could cause our actual results, performance or achievements to be materially diÅerent from and worse than any future results, performance or achievements expressed or implied by these forward-looking statements. Important risks and factors that could cause actual results to be materially diÅerent from expectations are set forth in ""Investment Considerations'' and elsewhere in this oÅering circular and include, but are not limited to: ‚
Deregulation of the Japanese electricity industry may put pressure on our prices and lead to declines in our proÑts;
‚
Declining growth in electricity demand may have a long-term negative aÅect on our revenue growth due to a decline in new power plant development;
‚
Declining growth in electricity demand and other changes in conditions may force us to delay or discontinue our current power plant construction, leading to additional costs and possible losses;
‚
Many of our activities involve risks relating to environmental issues, including environmental regulations and liabilities arising from environmental hazards;
‚
Our pursuit of overseas business opportunities may lead to losses; and
‚
Our pursuit of new business opportunities may not produce revenues and may lead to losses.
All forward-looking statements in this oÅering circular are made as of the date hereof, based on information available to us as of the date hereof and we do not undertake to update or revise any of its forward-looking statements to reÖect future events or circumstances.
vi
GLOSSARY The following is a glossary of some of the electricity industry terms used in this oÅering circular. Base source ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Electric power generation source which is generally operated at a constant output level and used to supply electricity irrespective of Öuctuations in demand.
Competitive bidding ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The system through which IPPs bid for the right to engage in wholesale electricity supply to EPCOs. Competitive bidding is one of the deregulatory measures introduced as part of the December 1995 amendments to the EUIL.
Comprehensive cost system ÏÏÏÏÏÏÏÏÏÏ
The basis on which EPCOs determine the retail rates they charge to customers in the regulated market. The comprehensive cost system takes into account the aggregate generation, transmission and distribution costs of the relevant EPCO as a whole.
Conventional hydroelectric power plants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
One of two broadly deÑned categories of hydroelectric power plants, the other category being pumped-storage hydroelectric power plants. There are three types of conventional hydroelectric power plants: reservoir-type, natural Öow with dam and natural Öow. Reservoir-type hydroelectric power plants hold water in a reservoir or lake behind a dam, storing water when it is abundant and releasing it later when electricity is needed. Natural Öow with dam-type hydroelectric power plants also hold water, but on a smaller scale, adjusting water Öows over comparatively shorter periods, generally less than one week. Natural Öow hydroelectric power plants do not hold and release water, instead depending on natural water Öow for power generation. The Company's conventional hydroelectric power plants consist of reservoir-type and natural Öow with dam-type hydroelectric power plants.
A consultative body to the METI established in January 2001 to examine and make recommendations regarding the future of the Japanese electricity industry.
Electricity suppliers ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Entities engaged in either wholesale or retail supply of electricity. The EUIL classiÑes electricity suppliers into four categories: general electric utilities, wholesale electric utilities, speciÑed-scale electric utilities, or PPSs and special electric utilities.
Electricity supply plan ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The plan which each EPCO and wholesale electric utility is required by the EUIL to Ñle with the METI before the commencement of each Ñscal year. This plan describes the outlook for electricity supply in the utility's supply region over the next ten years, construction plans and related matters.
EPCOs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
See ""General electric utilities''.
EUIL ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The Electricity Utilities Industry Law.
General electric utilities ÏÏÏÏÏÏÏÏÏÏÏÏÏ
A deÑned term in the EUIL, it refers to entities which engage in retail electricity supply to general retail customers, including largeload customers. Japan's ten regional general electric utilities are also referred to in this oÅering circular as EPCOs.
IPPs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Independent power producers. IPPs, typically established by large industrial companies, generate and supply wholesale electricity to EPCOs through a competitive bidding process. IPPs emerged vii
following a 1995 amendment to the EUIL that eliminated the licensing requirement for wholesale suppliers with a generation capacity of 2,000 MW or less. IPPs are classiÑed as wholesale suppliers under the EUIL. J-POWER Law ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The Electric Power Development Promotion Law, pursuant to which the Company was established in 1952. The Company's business and operation were regulated under the J-POWER Law until it was repealed in October 2003.
kWh ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Kilowatt-hour. A quantitative measure of electric current Öow equivalent to one thousand watts (or one kilowatt (kW)) being used continuously for a period of one hour.
Large-load customers ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
A ministerial ordinance under the EUIL deÑnes large-load customers as those that consume 0.5 MW of electricity or more at voltages of 6,000 volts or more. An amendment to the EUIL, eÅective March 2000, opened the market for large-load customers (which at the time was deÑned as customers that consume 2 MW or more with voltages of 20,000 volts or more) to retail competition by allowing PPSs to supply electricity to large-load customers and by allowing the EPCOs themselves to supply electricity to largeload customers outside their service areas. EÅective April 2005, the deÑnition of large-load customers under the EUIL will be further expanded to include customers consuming 0.05 MW or more with voltages of 6,000 volts or more.
Load factor ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
In the case of the Company, a measure of power plant utilization equal to the ratio of average load to generation capacity. In the case of EPCOs, it is the ratio of average load to peak load during a given year. Because peak load depends on the maximum aggregate demand for electricity at the retail level, the Company uses generation capacity instead of peak load in measuring load factor.
METIÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The Minister of Economy, Trade and Industry.
MW ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Megawatt. A unit of power equal to one million watts.
Peak load ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The highest amount of electricity consumed within one day in a given year.
Peak source ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
An electric power generation source that is highly Öexible and can therefore be used to satisfy demand during peak periods.
PPSsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Power producers and suppliers. PPSs, typically established by large trading companies, gas utilities and large industrial manufacturers, supply electricity to large-load customers. PPSs generally purchase electricity from other suppliers, including self-generators, for resale, but some generate and sell their own electricity. PPSs began selling electricity following an amendment to the EUIL in 2000 that introduced retail competition to the Japanese electricity industry. PPSs are classiÑed as speciÑed-scale electric utilities under the EUIL.
Pumped-storage hydroelectric power plants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
One of two broad categories of hydroelectric power plants, the other category being conventional hydroelectric power plants. Pumped-storage hydroelectric power plants pump water during oÅpeak demand periods, such as nights and weekends, from reservoirs at lower elevations for storage in reservoirs at higher elevations. Pumped-storage hydroelectric power plants can generate electricity during peak demand periods by releasing water from their higher viii
elevation reservoirs, allowing it to Öow downhill through turbines connected to generators. Self-generators ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Entities that generate electricity for their own consumption as well as, in some cases, for supply to PPSs. Self-generators consist mainly of large industrial companies.
Special electric utilities ÏÏÏÏÏÏÏÏÏÏÏÏÏ
A deÑned term in the EUIL, it refers to entities which engage in retail electricity supply only to a speciÑc, designated location without using the transmission lines of EPCOs. A 1995 amendment to the EUIL provided for the introduction of special electric utilities to the Japanese electricity industry. Electricity supplied by special electric utilities is typically used in manufacturing plants, oÇces and other local facilities.
SpeciÑed-scale electric utilities ÏÏÏÏÏÏÏ
A deÑned term in the EUIL, it refers to entities which engage in retail electricity supply only to large-load customers. Referred to as PPSs.
StreamÖowÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The volume of water Öow in a given body of water that naturally occurs as a result of snow and rainfall, indicated as a percentage relative to prior years. 100% streamÖow in a given body of water for a given year means the volume of water Öow in that body of water for that year is equal to the average streamÖow over the previous 30-year period for that body of water.
Volts/voltage ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The volt is the standard unit used to measure the strength at which an electrical current is sent through a system. Voltage is the force of an electrical current measured in volts.
Wholesale electric utilities ÏÏÏÏÏÏÏÏÏÏÏ
A deÑned term in the EUIL, it refers to entities with total output capacity of more than 2,000 MW which engage in wholesale electricity supply to EPCOs for retail to general customers. The Company is a wholesale electric utility.
Wholesale electricity exchange ÏÏÏÏÏÏÏ
The Japan Electric Power Exchange, established by nine of the EPCOs and nine PPSs as part of the deregulation of the Japanese electricity industry. The exchange is scheduled to commence trading on April 1, 2005. The Company is currently a member of the exchange.
Wholesale suppliers ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
A deÑned term in the EUIL, it refers to entities, other than EPCOs and wholesale electric utilities, which engage in wholesale electricity supply to EPCOs at a volume of more than 1 MW for a period of 10 years or longer or at a volume of more than 100 MW for a period of Ñve years or longer. IPPs are classiÑed as wholesale suppliers. Public utilities and joint venture utilities are also classiÑed as wholesale suppliers. See ""Regulation Ì Electricity Suppliers''.
Wholesale supply ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Wholesale supply of electricity to EPCOs, which in turn supply retail electricity to general retail customers, including large-load customers.
ix
TABLE OF CONTENTS Page Summary InformationÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Investment Considerations ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Exchange Rates ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Information Concerning the SharesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capitalization ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Selected Consolidated Financial Information and Other DataÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Management's Discussion and Analysis of Financial Condition and Results of Operations ÏÏÏÏÏÏÏÏÏÏ The Electricity Industry in Japan ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Business ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Regulation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Subsidiaries and AÇliatesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ManagementÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Shareholders and Selling Shareholders ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Description of the Shares ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Taxation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OÅering and SaleÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Transfer Restrictions ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Japanese Foreign Exchange RegulationsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Clearance and SettlementÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Validity of SecuritiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Independent Auditors ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ General Information ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Summary of Certain SigniÑcant DiÅerences between Japanese and U.S. Generally Accepted Accounting Principles ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Index to Financial Statements ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
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1 5 12 13 14 15 18 44 59 82 91 93 96 98 106 111 115 116 117 118 118 119 120 F-1
SUMMARY INFORMATION The following summary is qualiÑed in its entirety by, and is subject to, the detailed information contained or referred to elsewhere in this oÅering circular. For a discussion of certain matters that should be considered in evaluating an investment in the international shares, see ""Investment Considerations''.
J-POWER As the largest supplier of wholesale electricity in Japan, we develop and operate power plants and transmission facilities throughout the country. To date, we have been a government-controlled entity primarily engaged in the wholesale supply and transmission of electricity. Our main customers are Japan's ten EPCOs, the regional general electric utilities which supply electricity to general retail customers. Our core business consists of supplying electricity generated at our coal-Ñred thermal and hydroelectric power plants and providing transmission facilities, in both cases through long-term arrangements pursuant to which our fees are calculated on a fair cost plus fair return on capital basis. As of March 31, 2004, these activities and the generation activities at one coal-Ñred thermal power plant owned by a consolidated subsidiary accounted for approximately 92% of our consolidated operating revenues. We are the leading supplier of coal-Ñred thermal power in Japan, with eight power plants. We are also one of the leading suppliers of hydroelectric power, with 59 power plants. Our total generation capacity of 16,509 MW as of March 31, 2004 represented approximately 7% of the total generation capacity used by the EPCOs. We also own transmission facilities, including 2,404 kilometers of transmission lines, some of which connect the island of Honshu with the islands of Kyushu, Shikoku and Hokkaido. Our privatization resulting from the oÅerings will occur in the context of increasing deregulation in the electricity industry in Japan. Currently, deregulation of the retail electricity market is proceeding incrementally for large-load customers, and in or around April 2007, a consultative body to the Minister of Trade, Economy and Industry, or METI, will begin to consider whether the entire retail electricity market should be opened to full competition. In response to increased pricing pressure resulting from deregulation, we have been implementing measures to increase our eÇciency and enhance our proÑtability. We are also focused on leveraging our knowledge and experience in the electricity industry to expand our other businesses. As a result, we have been seizing new business opportunities, making investments in independent power producers, or IPPs, and companies that supply electricity to power producers and suppliers, or PPSs. Additionally, we have been making investments in overseas power generation businesses and domestic clean energy source businesses such as wind power. In the years ended March 31, 2002, 2003 and 2004, we had total operating revenues of Í593,343 million, Í584,122 million and Í569,854 million, respectively, and net income of Í17,638 million, Í20,725 million and Í27,623 million, respectively. As of July 31, 2004, we had 6,076 employees.
Strengths ‚
We have a unique position in the Japanese electricity industry as a large-scale wholesale electric utility.
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We possess attractive assets supporting our core business. ‚
We are the leading supplier of coal-Ñred thermal power.
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We are one of the leading suppliers of hydroelectric power in Japan.
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We own transmission lines which connect neighboring EPCOs' service areas.
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We have a stable source of income and ample operating cash Öow.
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We have extensive experience in the electricity generation Ñeld. 1
Strategy ‚
‚
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Reduce costs to increase proÑts and strengthen cost competitiveness. ‚
We are reducing personnel.
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We are increasing the eÇciency of our maintenance activities.
Strengthen our overall Ñnancial position. ‚
We are reducing our debt.
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We are improving our asset eÇciency.
Take advantage of new business opportunities in a changing business environment. ‚
We are capturing new business opportunities presented by the ongoing deregulation of the Japanese electricity industry.
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We are investing in overseas power generation businesses.
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We are diversifying our domestic generation businesses.
Our head oÇce is located at 15-1, Ginza 6-chome, Chuo-ku, Tokyo 104-8165, Japan. Our main telephone number is 81-3-3546-2211. Our Internet website address is http://www.jpower.co.jp. The information on our website is not a part of this oÅering circular and should not be deemed incorporated by reference into this oÅering circular.
2
The OÅerings The OÅeringsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
138,808,000 existing shares of our common stock are being oÅered in the international oÅering and the Japanese oÅering.
The International OÅering ÏÏÏ
34,702,000 international shares are being oÅered by the international managers (i) to non-U.S. persons in oÅshore transactions outside the United States and Japan in reliance on Regulation S and (ii) through the Rule 144A selling agents of certain international managers to QIBs in the United States in reliance on Rule 144A. See ""OÅering and Sale''.
The Japanese OÅering ÏÏÏÏÏÏ
Concurrently with the international oÅering, 104,106,000 Japanese shares are being oÅered by Japanese underwriters in a public oÅering in Japan. See ""OÅering and Sale''.
The Selling Shareholders ÏÏÏÏÏÏÏ
All of the international shares being sold in the international oÅering are being sold by the international selling shareholder. All of the shares being sold in the Japanese oÅering are being sold by the international selling shareholder and The Tokyo Electric Power Company, Incorporated, The Kansai Electric Power Company, Incorporated, Chubu Electric Power Company, Incorporated, Tohoku Electric Power Company, Incorporated, Kyushu Electric Power Company, Incorporated, The Chugoku Electric Power Company, Incorporated, Hokkaido Electric Power Company, Incorporated, Hokuriku Electric Power Company and Shikoku Electric Power Company, Incorporated, or, collectively, the Japanese selling shareholders. The international selling shareholder and the Japanese selling shareholders are collectively referred to herein as the selling shareholders. The international shares and Japanese shares represent 25% and 75%, respectively, of our total issued shares as of the date hereof. See ""Shareholders and Selling Shareholders''.
OÅer Price ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í2,700 per share.
Use of ProceedsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
We will not receive any of the proceeds from the sale of the shares.
Lock-up Agreement ÏÏÏÏÏÏÏÏÏÏÏ
We have agreed with the international managers to restrictions on issuances, sales and other disposals of our shares, subject to some exceptions, for a period that will end 180 days after the date of this oÅering circular as described under ""OÅering and Sale''.
Shares Outstanding ÏÏÏÏÏÏÏÏÏÏÏÏ
As of the date hereof, there are 138,808,000 of our shares issued and outstanding, all of which will continue to be issued and outstanding after the oÅerings.
Listing ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Shares of our common stock are currently not listed on any stock exchange. The Tokyo Stock Exchange has approved the listing of the shares. It is expected that the shares will be admitted for trading on the Tokyo Stock Exchange on or about October 6, 2004.
Dividends ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
See ""Information Concerning the Shares Ì Dividend Policy'', ""Description of the Shares Ì Dividends'' and ""Taxation Ì Japanese Taxation''.
Voting RightsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Generally, holders of our shares are entitled to one vote per unit, consisting of 100 shares. See ""Description of the Shares Ì Voting Rights''.
Investment Considerations ÏÏÏÏÏÏ
For a discussion of certain factors that should be considered in evaluating an investment in the international shares, see ""Investment Considerations''.
Status of the International SharesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Withholding Tax ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
The international shares rank pari passu with all other outstanding shares in respect of dividends and other rights attached thereto, excluding any dividend or other right attaching to the outstanding shares the record date of which precedes the date of delivery of the international shares. Under Japanese tax law, dividends payable by us to non-residents of Japan are subject to Japanese withholding tax at the rate of 7% for dividends to be paid on or before March 31, 2008 and 15% thereafter, 3
except for dividends paid to any individual shareholder who holds 5% or more of our shares, for which the applicable withholding tax rate is 20%. Japan has concluded income tax conventions with several countries, including the United States and several European countries. See ""Taxation Ì Japanese Taxation''. Payment and Settlement ÏÏÏÏÏÏÏ
It is expected that payment for the international shares will be made in Japanese yen for value, and delivery of the international shares will be made through the facilities of JASDEC in Tokyo, on or about October 6, 2004 (Tokyo time). See ""Clearance and Settlement''.
Security CodesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Securities IdentiÑcation Code: 9513 ISIN: JP3551200003 Common Code: 020048867 SEDOL: B02Q328
4
INVESTMENT CONSIDERATIONS In addition to the information set forth elsewhere in this oÅering circular, prospective investors should carefully evaluate the considerations set forth below before purchasing the international shares oÅered hereby. Risks Related to Our Business Deregulation of the Japanese electricity industry may put pressure on our prices and lead to declines in our proÑts. Most of our operating revenue comes from the wholesale supply of electricity to Japan's ten EPCOs. The EPCOs in turn provide electricity to Japan's retail customers, including household, commercial and industrial users. Until recently, under the Electricity Utilities Industry Law, or the EUIL, the EPCOs enjoyed a monopoly in the retail electricity market for their respective service areas. However, an amendment to the EUIL that came into eÅect in March 2000 introduced retail competition by deregulating the market for certain large-load customers, which accounted for approximately 30% of total electricity demand. The scope of the deregulated market is continuing to increase in stages. The scope of the deregulated market reached approximately 40% of total electricity demand in April 2004 and is expected to reach approximately 60% of total electricity demand in April 2005 as the result of the further expansion of retail competition. See ""The Electricity Industry in Japan Ì Electricity Industry Deregulation in Japan''. The EPCOs have been reducing and are expected to further reduce their rates. They have been creating new rate options and expanding their services in order to secure customers in the deregulated retail market and to respond to customer demands to lower electricity rates. In October 2000, the EPCOs lowered their retail rates in the regulated market by an average of 5.4%. Between April and October 2002, they lowered them further, by between 5.2% and 7.1%. Some EPCOs, such as The Tokyo Electric Power Company, Chubu Electric Power Company and Tohoku Electric Power Company recently announced further rate reductions to take eÅect in our current Ñscal year, and based on past experience, we believe the other EPCOs may take similar steps. While the EPCOs' rates in the deregulated market are generally determined on a customer-bycustomer basis and are not made public, we believe retail rates in the deregulated market have also declined. Although our fees are calculated on a fair cost plus fair return on capital basis and are not directly aÅected by decreasing retail electricity prices, from time to time we review with the EPCOs the fees we charge and make adjustments to reÖect changes in our cost of capital, such as changes in our interest costs, as well as changes in the assumptions related to our Ñxed and variable costs. We have been facing increasing pressure from the EPCOs to lower our fees as the EPCOs lower their retail rates, and such pressure may strengthen as the deregulated portion of the retail market further expands. In April 2001 and April 2003, we reduced the fees we charge for hydroelectric electricity and transmission by an average of 3.4% and 6.5%, respectively, in part as a result of this pressure. Further pressure could force us to signiÑcantly decrease the fees that we charge to the EPCOs, and this in turn could have a material adverse eÅect on our results of operations. For further information on our fees, see ""Management's Discussion and Analysis of Financial Condition and Results of Operations Ì Factors AÅecting Our Results of Operations Ì Operating Revenues Ì Electric Power Segment Ì Electricity Fees''. In connection with the ongoing deregulation of the Japanese electricity industry, a wholesale electricity exchange is scheduled to commence wholesale electricity trading in Japan in April 2005, pursuant to a proposal by the Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy. This will make available market price quotations for electricity at the wholesale level. Although we presently do not expect a large amount of electricity to be traded on the exchange in the near term, we expect to be a participant in the exchange. In order to sell electricity on the exchange, however, we will Ñrst have to seek amendments to our supply contracts with the EPCOs under terms to be agreed with them. Whether or not we choose to sell electricity on the exchange, if trading on the exchange expands beyond our current expectations, and prices quoted on the exchange have an eÅect on our fees, or the exchange otherwise has an adverse impact on our wholesale electricity supply business over time, our results of operations may be adversely aÅected. The Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy has stated that it will be appropriate to begin considering full retail deregulation, including the market for individual household customers, in or around April 2007, based on an examination of the eÅectiveness of prior deregulation and consideration of the need for energy security and universal service. We cannot predict what additional mid- to long-term measures to deregulate Japan's electricity industry will be adopted, and we 5
cannot guarantee that such additional deregulation would not have an adverse impact on our Ñnancial condition and results of operations. For a further discussion of the deregulation of the Japanese electricity industry, see ""The Electricity Industry in Japan Ì Electricity Industry Deregulation in Japan''. Declining growth in electricity demand may have a long-term negative aÅect on our revenue growth due to a decline in new power plant development. In March 2004, a report by the Agency for Natural Resources and Energy projected that the demand for electricity in Japan would grow by a compound annual growth rate of about 1.1% over the period from the year ended March 31, 2003 to the year ending March 31, 2014, as compared with a 1.9% compound annual growth rate over the period from the year ended March 31, 1994 to the year ended March 31, 2004. In June 2004, the Subcommittee on Energy Demand of the Advisory Committee for Natural Resources and Energy issued its preliminary report on the outlook for electricity demand in 2030. The Subcommittee concluded that in a base case scenario assuming no major changes in electricity consumption patterns, demand for electricity would grow at a compound annual growth rate of about 0.9% over the period from the year ended March 31, 2001 to the year ending March 31, 2031. Under an energy-saving scenario, in which the Subcommittee assumed a decrease in demand for electricity due to the introduction of more energy-saving devices and products utilizing new information technology, the Subcommittee forecast a compound annual growth rate of about 0.3%, with demand for electricity in Japan peaking in the year 2025 and declining thereafter. The fees that we charge for our coal-Ñred thermal power plants include a portion that covers our depreciation costs, which are based mainly on the declining-balance method. In addition, the portion of the fees that represents a fair return on capital is calculated based on the then-current book value of the relevant power plant. As a result, absent additional investments to construct new facilities or upgrade existing facilities, the Ñxed portion of the fees we receive from the EPCOs for the electricity generated at existing coal-Ñred thermal power plants generally declines over time. In addition, while our fees related to hydroelectric power plants are generally more stable, they may also decline over time, for example, if our ongoing cost-reduction eÅorts are reÖected into the cost assumptions of the fees in the event the fees are renegotiated. Future revenue growth depends in large part on our ability to Ñnd new revenue sources, principally by building new power plants. If declining growth in demand for electricity results in reduced demand for new power plants, it may be more diÇcult for us to increase our operating revenue. Declining growth in electricity demand and other changes in conditions may force us to delay or discontinue our current power plant construction, leading to additional costs and possible losses. Prior to constructing a power plant, we obtain the agreement of the prospective customers of the power plant regarding the generating capacity of the power plant, the target launch date, projected construction costs for the power plant and the basis for our fees. Once the power plant begins operating, we supply electricity pursuant to electricity supply contracts. Pursuant to these arrangements, our fees are calculated on a fair cost plus fair return on capital basis. Under existing arrangements with certain EPCOs, in the next ten years, we plan to commence operation of two large-scale power plants, with an aggregate generating capacity of 1,983 MW. For further information on our arrangements with the EPCOs, see ""Business Ì Electric Power Business Ì Wholesale Supply of Electricity to the EPCOs''. Given the lower growth trends forecast for long-term electricity demand, the EPCOs are increasingly delaying construction plans for new power plants and are, in some cases, choosing to temporarily or permanently stop the operation of thermal power plants that are ineÇcient. The EPCOs have also been reducing their aggregate capital expenditures in recent years. The EPCOs' planned aggregate capital investment for the year ending March 31, 2005 is expected to be approximately 3.8% less than for the year ended March 31, 2004. We must obtain local government and community concurrence to build our power plants. The process of obtaining the concurrence of a local government and community on a plan of construction can cause delays or increase costs related to the construction of the power plant. If we are unable to obtain local concurrence, we would have to alter or cancel the project. Following deliberations with our EPCO clients, we have, in the past, decided to cancel some construction plans. We have sometimes been requested by the EPCO to which a power plant was to provide electricity to delay or alter the plan for a power plant, usually based on its assessment that paying us for such electricity would be uneconomical due to decreased demand or other reasons. In cases where such request is 6
made by an EPCO, and we agree to alter or cancel a project following discussions with the EPCO, we have generally been reimbursed by the EPCO for most of the costs related to the alteration or cancellation. However, we were in the past generally required to bear some of the costs associated with ceasing construction based on negotiations with the EPCO. Since April 1, 2001, we have reevaluated Ñve projects. For example, we halted plans to build a pumped-storage hydroelectric power plant in Yunotani, and we transferred a joint project at the Hitachinaka thermal power plant to partner The Tokyo Electric Power Company. In the three years ended March 31, 2004, we have written oÅ an aggregate of approximately Í14 billion in relation to our reevaluation of these Ñve projects. In addition, we recently agreed with Chubu Electric Power Company to alter our construction plans for the Tokuyama hydroelectric power plant based on a proposal by the Ministry of Land, Infrastructure and Transport to decrease the amount of water dedicated to the generation of electricity, reÖecting a change in regional water management policy, and weaker than anticipated demand for electricity. The proposed new plan calls for the power plant to be changed from a 400 MW pumped-storage hydroelectric power plant to a 153 MW conventional hydroelectric power plant, and the power plant is expected to commence operations in the year ending March 31, 2015. We are currently trying to obtain the concurrence of the local government and community to these changes. We confer with local oÇcials before we undertake projects, and the basic agreements we enter into with the EPCOs prior to construction are based on then current projections of future electricity demand. Nevertheless, future changes in projected demand or other conditions may force us to reevaluate projects in the future, leading to further write-oÅs. Many of our activities involve risks relating to environmental issues, including environmental regulations and liabilities arising from environmental hazards. Many of our activities, including power generation and transmission, involve potential risks relating to environmental issues. Many of those activities are currently subject to extensive environmental regulation, and it is possible that our activities will be subject to further regulation in the future. For example, we operate many coal-Ñred thermal power plants that emit large volumes of CO2. We have taken various steps to reduce these emissions, and we believe that we are in compliance in all material respects with environmental laws and regulations established by the national and local regulators and other government agencies in each of the jurisdictions where we operate power plants. However, risk of environmental costs and liabilities is inherent in our operations, and there can be no assurance that we will not incur additional material costs and liabilities in the future. Japan has signed and ratiÑed the Kyoto Protocol, which still has not yet taken eÅect because certain preconditions to eÅectiveness, including a suÇcient number of ratiÑcations, have not been fulÑlled. If the Kyoto Protocol were to take eÅect, Japan would be required to individually or jointly reduce its global warming greenhouse gas emissions by a speciÑed deadline. According to a projection recently announced by the Ministry of Economy, Trade and Industry, however, Japan is unlikely to fulÑll its emissions reduction obligation by the deadline unless additional measures are taken to reduce Japan's emissions. Every year since 1996, jointly with the EPCOs, we have published our goals for reducing our CO2 emissions. See ""Business Ì Environmental Matters''. While we are making our best eÅort to meet this goal, we anticipate that it will be diÇcult to do so. It is unclear at this time whether or when the Kyoto Protocol will come into eÅect. In light of the current level of greenhouse gas emissions in Japan, which is high in light of the Kyoto Protocol targets, the Ministry of the Environment is currently formulating a proposal for further measures to help reduce emissions, which are likely to include the introduction of a so-called ""environmental tax'', a national tax based upon CO2 emissions. Any such measures, if imposed, could increase our costs and expenses and could have a negative impact on our business, Ñnancial condition and results of operations if we were unable to reÖect such increased costs in our fees. As the regulatory environment continues to evolve, changes to the regulatory framework, our compliance costs related to such changes and the eÅect of such changes on us is uncertain. Future additional regulatory changes and costs associated with such changes could negatively aÅect our business, Ñnancial condition and results of operations if we are unable to reÖect such increased costs in our fees. Our pursuit of overseas business opportunities may lead to losses. The major focus of our overseas business is investment in independent power producers and power plant development-related consulting, primarily in Asia. As of March 31, 2004, we have invested in 15 independent power producer projects in 6 countries. For example, since 2001, we have invested in six gas-Ñred 7
and gas cogeneration power plants in Thailand. In our consulting business, we primarily receive consulting fees from Japanese organizations related to foreign assistance projects supported by the Government of Japan, though we also receive commissions from foreign governments and private entities. International operations in developing countries present risks that are greater than those in our operations in Japan. These risks include adverse changes in economic, social and political conditions, delays in construction and interruption of business, war, expropriation, nationalization, renegotiation or nulliÑcation of existing contracts and adverse changes in law, regulation or tax policy. There can be no assurance that such events will not occur or will not result in a material adverse aÅect on our results of operations. Our pursuit of new business opportunities may not produce revenues and may lead to losses. As part of our corporate strategy, we are endeavoring to grow our other electricity supply businesses in response to changes in the Japanese electricity industry, including businesses that generate and supply electricity to power producers and suppliers, or PPSs, wind power and the supply of electricity to the new wholesale electricity exchange. We have also made investments in alternative energy sources, such as cogeneration and waste-fueled power plants. Many of these opportunities have emerged as a result of regulatory changes and are dependent on the continuation of the new regulatory framework to support these businesses. Our other electricity supply businesses and alternative power source businesses are largely dependent on the deregulation of the electricity industry in Japan, and laws such as the Renewable Portfolio Standard Law, which requires the EPCOs to source a certain amount of their electricity from renewable energy sources. Further changes in the regulatory framework that negatively aÅect the incentives that promote our new businesses may negatively aÅect the performance of those businesses. Many of our new enterprises are joint ventures, and we have less than a controlling interest in some of them. While we partner with entities we believe are sound, in many cases we are dependent on their ability to fulÑll their obligations and we may experience losses if they are unable to do so or if they otherwise negatively aÅect the business. More generally, many of our new businesses are tied to electricity demand in much the same way as our core wholesale electricity supply businesses. There may be a lack of future demand for electricity produced by our new businesses and a lack of demand for our other businesses related to power plant development. SigniÑcant changes in demand and other unforeseen events may force us to change or abandon plans related to new businesses. As a result, we may not be able to achieve the anticipated Ñnancial results from, and may also incur losses in connection with, these new businesses. Because our business requires substantial investments in generation and transmission assets, we must often borrow money to Ñnance our operations. If we are unable to obtain funding on acceptable terms or in a timely manner, our growth prospects and future proÑtability may be adversely aÅected. In connection with the development of power plants and transmission facilities, we have historically made substantial investments in property, plant and equipment. We have depended mainly on loans and bonds to Ñnance these investments. Our expected capital expenditures in the years ending March 31, 2005 and 2006 for committed projects in our electric power segment are Í70,349 million and Í69,872 million, respectively. We are scheduled to make additional major investments after March 31, 2006, including investments in our Isogo New No. 2 thermal power plant and Oma nuclear power plant, and we expect to borrow substantial funds to Ñnance these investments. To the extent we are unable to obtain additional capital on acceptable terms or in a timely manner due to a deterioration in the condition of the Ñnancial markets or in our credit quality or for any other reason, our growth prospects and future proÑtability may be adversely aÅected. Our business is concentrated in a limited number of customers. In the year ended March 31, 2004, 91.8% of our operating revenues were attributable to our electricity business, and 99.7% of our electric power business operating revenues were attributable to our supply of electricity to and the use of our transmission lines by the ten EPCOs. The Tokyo Electric Power Company, The Chugoku Electric Power Company and The Kansai Electric Power Company, our three largest customers by operating revenues, accounted for 62.1% of our electricity business operating revenues for that year. As a result of our limited customer base, our future results of operations will be aÅected by the performance of the EPCOs. In particular, the expansion of our electricity supply business depends in large 8
part on whether we are able to conclude new long-term supply contracts. While we believe that deregulation of the electricity industry in Japan will lead to new opportunities to sell electricity to new customers, the EPCOs will remain the most important source of ongoing revenue and new business opportunities. Any adverse change in EPCO operations, such as a decrease in the EPCOs' share of the retail electricity market in light of continuing deregulation, may have a signiÑcant adverse impact on our business, results of operations and Ñnancial condition. We will be subject to risks associated with the development, Ñnancing and construction of a nuclear power plant in Oma. We are currently developing a 1,383 MW nuclear power plant in Oma, Aomori Prefecture. We are scheduled to start construction in 2006 and begin operation of the power plant in 2012. We will incur substantial capital expenditures connected with the development of the Oma power plant which will require us to take on additional indebtedness. Currently, construction costs are projected to be Í469,000 million, part of which we will fund through research and development grants from the Government of Japan and others. We have invested Í104,453 million, including some amounts funded through research and development grants, through July 31, 2004. We plan to procure a signiÑcant portion of the required funds through debt Ñnancing and internal cashÖows, and no revenues are expected from the project until the commencement of operation in 2012. While we have entered into basic agreements with nine of the ten EPCOs to provide them with electricity generated at Oma, there can be no assurance that the project will proceed as planned if, for example, there is an unexpected decline in the demand for electricity. We have obtained approval from the local municipality and have applied to the METI for a license to construct the Oma power plant. Though most of the area's residents and the local governments favor the development of the Oma power plant, some individual citizens and groups are opposed to the presence of any nuclear power plants in Japan. In 2003, several nuclear power plants in Japan were suspended from operation following inappropriate maintenance practices at some of the power plants. Additionally, in August 2004, a steam leak accident occurred at a nuclear power plant in Japan. It did not occur in the nuclear reactor or its primary system and no radiation was released, although several workers were killed and injured. Any similar incidents or a serious nuclear accident could lead to an escalation of public opposition to nuclear power and negatively impact our development plans. Should any delay or other material change in the construction plan occur, we may incur signiÑcant costs, including write-oÅs of investments already made, to the extent we are unable to have the EPCOs bear such costs through negotiation. Our results of operations could be adversely aÅected by large short-term Öuctuations in coal prices. Sales volume of electricity from our coal-Ñred thermal power plants accounted for 81.5% of the electricity we supplied, excluding pumped-storage hydroelectric power, in the year ended March 31, 2004. In that year, we purchased approximately 18 million tons of coal, 96.4% of which was imported. The cost of the coal accounted for approximately 20% of our operating expenses for the year. Accordingly, a signiÑcant portion of our operating expenses are inÖuenced by the price of coal on the world markets. The price of coal in the each of the markets from which we procure it is subject to change. For example, in the years ended March 31, 2002, 2003, and 2004, the average price in annual contracts for coal from Australia, currently our most important source of coal, was U.S.$34.50, $31.85 and $26.75 per ton on an FOB basis, respectively. In the current Ñscal year, annual contract prices for coal from Australia have risen by as much as 70% due to a decline in the availability of coal from China, among other things. Under our electricity sales contracts with the EPCOs, our fees are calculated on a fair cost plus fair return on capital basis, and the assumed coal price used as a factor in determining the electricity fees under such contracts is adjusted every two years or, in the event of signiÑcant changes in the price of coal, on an annual basis. Therefore, while the risk of long-term changes in coal price levels is hedged by the terms of our long-term electricity supply arrangements, our results are subject to the risk of short-term coal price Öuctuations. In order to mitigate the eÅects of signiÑcant short-term price Öuctuations and secure a stable supply of coal, we have entered into one year and longer-term contracts with suppliers in several countries, including Australia, Indonesia and China, under which purchase prices are typically adjusted every year. However, if our cost of coal Öuctuates signiÑcantly, to the extent we are unable to reÖect the increased cost in higher fees in a timely manner, our results of operations may be adversely aÅected. 9
We will be subject to risks associated with the ownership and operation of a nuclear power plant if we complete our plans to build a nuclear reactor in Oma. In 2012, we plan to begin operating an advanced boiling water reactor, or ABWR, nuclear power plant in Oma that will utilize mixed oxide, or MOX, fuel made from a mixture of plutonium and uranium oxide. There are risks associated with nuclear power generation, including risks arising from the storage and handling of radioactive materials. The occurrence of a nuclear accident could result in substantial clean up costs, liability and litigation expenses and substantial harm to our reputation. Failures, breakdowns, planned or unplanned outages as well as natural disasters or sabotage at our power plants may harm our business and reputation. Our power plants, transmission facilities and information systems controlling these facilities could be subject to breakdowns, unplanned outages or physical damage due to natural disasters such as storms and earthquakes, sabotage, terrorism, fuel interruptions and other causes. Our emergency response, disaster recovery or crisis management measures may not eÅectively protect us from these events. Any service disruption may cause customer dissatisfaction and may also lead to liabilities for damages, imposition of penalties and other unforeseen costs and expenses. We may also need to temporarily shut down some of our power plants and incur expenses in connection with inspections, maintenance or repair activities in addition to those that we currently conduct, including such additional activities that the government may require us to conduct. Not all potential losses are insured, and insurance claims may be subject to challenge or delay. In addition, any physical damage to our facilities may be costly to repair. Any of these events could have a material adverse eÅect on our business, Ñnancial condition and results of operations. In recent months, a nuclear power plant and a thermal power plant in Japan experienced steam leak accidents arising from internal erosion of high-pressure steam pipes. In response, the METI has required the operators of all nuclear power plants and certain large thermal power plants in Japan to report to the METI schedules for inspections of their water and steam pipe systems. On September 13, 2004, we reported our schedule for inspections to the METI for power plants in operation for 20 years or more. For power plants in operation for less than 20 years, we are currently formulating a schedule for performing inspections and expect to report our schedule to the METI in October 2004. The inspections will require us to brieÖy shut down each power plant under inspection. While we currently do not anticipate that the inspections and resulting repairs, if any, will lead to substantial additional expenses or signiÑcant declines in operating revenues, there can be no assurance that our results of operations will not be materially adversely aÅected. Finally, any failure to comply with environmental regulations, including as a result of accidents that harm the environment or the health of local residents, could subject us to substantial mitigation and remediation costs, civil liability, Ñnes and criminal sanctions. For further information regarding environmental regulation, see ""Regulation Ì Environmental Regulation''. We are subject to electricity industry regulations, which may decrease our Öexibility. We are currently subject to regulations under the EUIL, which may reduce our business Öexibility and impose regulatory costs on our business. These regulations include: ‚
A requirement to maintain a license from the METI to act as a wholesale electric utility;
‚
A requirement to Ñle with the METI fees and other terms and conditions of wholesale electricity supply, subject to the METI's power to issue an order to change;
‚
A requirement to obtain approval from the METI to transfer or acquire wholesale electricity supply businesses or to conduct a consolidation, merger or corporate split;
‚
A requirement to Ñle with the METI advance notiÑcation to dispose of electric power facilities, subject to the METI's power to issue an order to change or cancel the transaction; and
‚
A requirement to Ñle a notiÑcation with, or obtain approval from, the METI with respect to construction or alteration of electric power facilities, and to perform an environmental impact assessment before such construction or alteration, subject to the METI's power to issue an order to change or cancel the construction or alteration plan or to change the related environmental protection measures. 10
While we do not presently anticipate the introduction of any major new regulations which may reduce our business Öexibility or impose regulatory costs on our business, there can be no assurance that new regulations imposing new burdens and expenses on our business will not be adopted in the future. For further information regarding regulation of the electricity industry, see ""Regulation''. Risks Related to the Shares A signiÑcant public market for the shares may not develop or be sustained. Prior to the oÅerings, there has been no trading market for the shares. In connection with the oÅerings, we have obtained approval from the Tokyo Stock Exchange for the listing of the shares, but there can be no assurance that a signiÑcant public market for the shares will develop or be sustained after the oÅerings. Because the shares are not being listed in any other jurisdiction, there will be no public market outside Japan. The oÅer price for the oÅered shares will be determined by agreement between the selling shareholders and the joint global coordinators and may bear no relationship to the price at which the shares will trade after the completion of the oÅerings. The market price of the shares could be subject to Öuctuations based on facts such as changes in our Ñnancial results or those of other companies in the energy industry, changes in analysts' estimates of our Ñnancial performance, general conditions in the energy industry and conditions in the Ñnancial markets. Due to daily price range limitations under the Tokyo Stock Exchange rules, you may not be able to sell your shares of our common stock at a particular price on any particular trading day, or at all. Stock prices on the Tokyo Stock Exchange are determined on a real-time basis by the equilibrium between bids and oÅers. The Tokyo Stock Exchange is an order-driven market without specialists or market makers to guide price formation. To prevent excessive volatility, the Tokyo Stock Exchange sets daily upward and downward price Öuctuation limits for each stock, based on the previous day's closing price. Although transactions may continue at the upward or downward limit price if the limit price is reached on a particular trading day, no transactions may take place outside these limits. Consequently, an investor wishing to sell at a price above or below the relevant daily limit may not be able to sell his or her shares at such price on a particular trading day or at all. Rights of shareholders under Japanese law may be diÅerent from rights of shareholders in other jurisdictions. The Company's Articles of Incorporation and Regulations of the Board of Directors and the Commercial Code of Japan govern the Company's corporate aÅairs. Legal principles relating to such matters as the validity of corporate procedures, directors' and oÇcers' Ñduciary duties and liabilities, and shareholders' rights under Japanese law may be diÅerent from those that would apply to companies incorporated in other jurisdictions. You may have more diÇculty in asserting your rights as a shareholder than you would as a shareholder of a corporation organized in other jurisdictions. In addition, Japanese courts may not be willing to enforce judgments of non-Japanese courts against the Company which are based on non-Japanese securities laws, including U.S. federal and state securities laws.
11
EXCHANGE RATES The following table sets forth certain information concerning the exchange rate for U.S. dollars against Japanese yen, based on the mean of the exchange rate quotations by The Bank of Tokyo-Mitsubishi, Ltd. for buying and selling spot dollars by telegraphic transfer against yen on each Japanese bank business day during the periods indicated. No representation is made that the Japanese yen or U.S. dollar amounts referred to herein could have been or could be converted into U.S. dollars or Japanese yen, as the case may be, at any particular rate or at all. Year ended or ending March 31, 1999 2000 2001 2002 2003 2004 2005
High
ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (through September 24, 2004)ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í146.40 124.40 123.90 134.80 133.20 120.80 114.50
Low Average Period End (yen per U.S. dollar) Í110.45 Í128.26 Í120.55 101.55 111.62 106.15 104.30 110.51 123.90 116.55 124.98 133.25 115.95 121.98 120.20 105.37 113.19 105.69 103.96 109.76 110.61
Fluctuations in exchange rates aÅect the foreign currency amounts received when dividends are converted to a foreign currency. Such Öuctuations may, once the shares are listed on the Tokyo Stock Exchange, also aÅect the foreign currency equivalents of the yen price of the shares on the Tokyo Stock Exchange and, accordingly, the foreign currency amounts received when a sale of shares is made on the Tokyo Stock Exchange and the proceeds of such sale are remitted outside of Japan.
12
INFORMATION CONCERNING THE SHARES Dividend Policy Year-end dividends may be recommended by our Board of Directors and are subject to approval by shareholders at an ordinary general meeting of shareholders customarily held in June of each year. If a dividend is approved at the meeting, year-end dividend payments are made promptly thereafter to holders or pledgees of record as of March 31 of such year. Additionally, as the result of an amendment to our Articles of Incorporation which took eÅect in October 2003, we may, by resolution of our Board of Directors, make interim dividend payments in cash to holders or pledgees of record as of September 30 of any year after 2003. See ""Description of the Shares Ì Dividends''. In each of the Ñve years ended March 31, 2004, we paid year-end cash dividends of Í60 per share. As it only became possible for us to pay interim dividends beginning in the current Ñscal year, we have not paid interim dividends in the past, and we do not presently expect to make any interim dividend payments in the current Ñscal year. With regard to the distribution of proÑts, it is the present intention of our Board of Directors to continue to provide a stable level of dividends to shareholders, subject to the level of our future earnings, our Ñnancial condition and other factors, including such legal, contractual and regulatory restrictions as may apply from time to time with respect to the payment of dividends, while at the same time to increase our internal reserves in order to strengthen our Ñnancial position. Dividends payable to non-residents of Japan or non-Japanese corporations are subject to Japanese withholding tax. See ""Taxation Ì Japanese Taxation''. Issued Share Capital As of March 31, 2004, we had an authorized share capital of 280,000,000 shares of common stock, of which 138,808,000 shares were issued and outstanding. The authorized share capital was increased to 550,000,000 shares by resolution at the ordinary general meeting of shareholders held in June 2004. The international selling shareholder holds 83.06% of our total issued shares and the remaining shares are held by nine EPCOs. Listing The Tokyo Stock Exchange has approved the listing of the shares of the Company's common stock. The Tokyo Stock Exchange will determine at the time of the pricing of the shares in connection with the oÅerings whether the shares will be eligible for listing on its First Section on the basis of criteria relating to the expected number of outstanding shares, the expected aggregate market value of the shares and the expected amount of public Öoat of the shares, in each case at the time of listing, after taking into account the oÅer price of the shares and certain other factors. It is expected that the shares will be admitted for trading on the Tokyo Stock Exchange on or about October 6, 2004. On the basis of the current information concerning the shares, we expect that the Tokyo Stock Exchange will approve the listing of the shares on the First Section. Prior to the oÅerings, the shares have not been publicly traded.
13
CAPITALIZATION The following table and notes thereto set forth our consolidated audited capitalization as of March 31, 2004. The following table should be read in conjunction with ""Management's Discussion and Analysis of Financial Condition and Results of Operations'' and the consolidated Ñnancial statements included elsewhere in this oÅering circular. The consolidated Ñnancial statements have been prepared in accordance with Japanese GAAP, which diÅers in certain signiÑcant respects from U.S. GAAP. See ""Summary of Certain SigniÑcant DiÅerences between Japanese and U.S. Generally Accepted Accounting Principles''. As of March 31, 2004 (millions of yen and thousands of U.S. dollars) Short-term debt: Short-term loans ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Current portion of long-term debt and other ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Commercial paper ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Long-term debt ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Shareholders' equity: Common stock: Authorized Ì 280,000,000 shares(1); Issued and outstanding Ì 138,808,000 shares ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Capital surplus ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Retained earningsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Unrealized gain on securities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Foreign currency translation adjustments ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total shareholders' equity ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total capitalization ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í
40,466 57,595 40,000 Í 138,061
$
382,874 544,951 378,465 $ 1,306,290
Í1,454,867
$13,765,425
152,449 81,849 123,213 3,738 (1,605) 359,645 Í1,814,513
1,442,422 774,430 1,165,803 35,372 (15,194) 3,402,834 $17,168,260
Notes: (1) The authorized share capital was increased to 550,000,000 shares by resolution at the ordinary general meeting of shareholders held in June 2004. (2) Other than as set out in note (1) above, there has been no material change in our consolidated capitalization since March 31, 2004. (3) As of March 31, 2004, we had aggregate contingent liabilities of Í67,142 million in guaranteed debt. In July 2004, we entered into additional debt assumption arrangements, and as a result, we have an additional Í50,250 million in contingent liabilities.
14
SELECTED CONSOLIDATED FINANCIAL INFORMATION AND OTHER DATA We prepare our Ñnancial statements in accordance with Japanese GAAP, which diÅers in certain respects from U.S. GAAP. See ""Summary of Certain SigniÑcant DiÅerences between Japanese and U.S. Generally Accepted Accounting Principles'' and the Ñnancial statements and notes thereto included elsewhere in this oÅering circular. Selected Consolidated Financial Data The following selected consolidated Ñnancial data as of or for the years ended March 31, 2000, 2001, 2002, 2003 and 2004 are derived from our consolidated Ñnancial statements for such periods. With the exception of our consolidated Ñnancial statements for the year ended March 31, 2000, which were not audited, the consolidated Ñnancial statements were audited by Ernst & Young Shin Nihon, formerly known as Century Ota Showa & Co. The information set forth below should be read in conjunction with, and is qualiÑed in its entirety by reference to, ""Management's Discussion and Analysis of Financial Condition and Results of Operations'' and the consolidated Ñnancial statements and notes contained elsewhere in this oÅering circular. As of or for the year ended March 31, 2000
2001
2002
2003
2004
(unaudited) (millions of yen, except per share data)
Statement of Income Data: Operating revenues: Electric power ÏÏÏÏÏÏÏÏÏÏÏ Í 449,902 Others ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 40,705 Total operating revenues Operating expenses: Electric power ÏÏÏÏÏÏÏÏÏÏÏ Others ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
2004 (thousands of U.S. dollars, except per share data)
Í 494,907 Í 547,333 Í 545,824 Í 522,922 46,684 46,010 38,297 46,931
$ 4,947,702 444,047
490,607
541,592
593,343
584,122
569,854
5,391,750
331,268 52,020
371,683 52,595
421,816 51,937
407,131 42,789
386,463 51,251
3,656,579 484,922
Total operating expenses
383,288
424,279
473,753
449,920
437,715
4,141,502
Operating income ÏÏÏÏÏÏÏÏÏÏ
107,319
117,313
119,590
134,201
132,138
1,250,248
Other income (expense), net
(84,014)
(87,522)
(89,064)
(98,679)
(88,381)
(836,234)
Income before income taxes and minority interestsÏÏÏÏÏ
23,305
29,790
30,526
35,522
43,757
414,014
Income taxesÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Minority interests ÏÏÏÏÏÏÏÏÏÏ
9,682 137
11,769 182
12,486 400
14,370 426
15,912 220
150,562 2,085
Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Í
13,485
Í
17,838 Í
17,638 Í
20,725 Í
27,623
$
261,365
Net income per share ÏÏÏÏÏÏ Í 191.02 Cash dividends per share ÏÏÏÏ Í 60.00 Balance Sheet Data: Current assets ÏÏÏÏÏÏÏÏÏÏÏÏÏ Í 124,626 Property, plant and equipment, net ÏÏÏÏÏÏÏÏÏÏ 2,156,675 Total assets ÏÏÏÏÏÏÏÏÏÏÏ 2,351,886 Long-term debt, less current portion ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 1,906,097 Interest-bearing debt(2) ÏÏÏÏÏ 2,103,302 Shareholders' equity ÏÏÏÏÏÏÏÏ 127,149
Í Í
252.67 Í 60.00 Í
249.84 Í 60.00 Í
291.40 Í 60.00 Í
304.88 60.00(1)
$ $
2.88 0.56
Í 142,499 Í 233,956 Í 182,027 Í 130,967
$ 1,239,163
2,209,196 2,420,661
1,999,364 2,314,720
1,890,617 2,195,897
1,813,182 2,076,107
17,155,665 19,643,371
1,900,141 2,129,392 138,868
1,794,228 2,007,488 152,304
1,733,126 1,895,689 168,301
1,454,867 1,592,929 359,645
13,765,425 15,071,716 3,402,834
15
As of or for the year ended March 31, 2000
2001
2002
2003
(unaudited) (millions of yen, except percentages and ratios)
2004
2004 (thousands of U.S. dollars)
Statement of CashÖows Data: Net cash provided by operating activities ÏÏÏÏÏÏÏ Í 127,857 Í 145,835 Í 200,708 Í 167,368 Í 179,948 $ 1,702,608 Net cash used in investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ (211,920) (166,942) (77,248) (11,030) (64,507) (610,349) Net cash used in Ñnancing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 85,055 22,127 (125,572) (117,709) (147,516) (1,395,745) Other Consolidated Financial Data: Depreciation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Í 100,440 Í 127,322 Í 149,145 Í 137,148 Í 131,380 $ 1,243,071 EBITDA(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 207,760 244,636 268,735 271,350 263,518 2,493,319 Gross cash Öows(4) ÏÏÏÏÏÏÏÏÏ 113,926 145,161 166,784 157,874 159,003 1,504,436 Capital expenditures(5) ÏÏÏÏÏÏ 204,141 191,473 76,641 53,443 46,202 437,148 Return on assets(6) ÏÏÏÏÏÏÏÏÏ n.a. 0.75% 0.74% 0.92% 1.29% Return on equity(7) ÏÏÏÏÏÏÏÏÏ n.a. 13.4% 12.1% 12.9% 10.5% Shareholders' equity ratio(8) 5.4% 5.7% 6.6% 7.7% 17.3% Debt to equity ratio(9) ÏÏÏÏÏÏ 16.5 15.3 13.2 11.3 4.4 Notes: (1) Cash dividends paid on 68,208,000 new shares of common stock issued in December 2003 were prorated based on the number of days such shares were outstanding during the Ñscal year ended March 31, 2004. As a result, cash dividends per share actually paid on such shares were Í17.22, and the average cash dividend per share actually paid on all of our shares of common stock outstanding as of March 31, 2004 was Í38.98. (2) Interest-bearing debt consists of long-term debt, less current portion, current portion of long-term debt and other short-term loans and commercial paper. (3) EBITDA is deÑned as operating income before depreciation and amortization. We have included information concerning EBITDA because certain investors use it as a measure of our ability to service our debt. EBITDA is not required under Japanese GAAP or U.S. GAAP, and should not be considered by investors as an alternative to operating income or net income as an indicator of our performance nor as an alternative to cash Öows from operating activities, investing activities or Ñnancing activities as a measure of liquidity. EBITDA disclosed here is not comparable to EBITDA disclosed by other companies because EBITDA is not uniformly deÑned. (4) Gross cash Öows represents the sum of net income and depreciation. (5) Capital expenditures diÅers from payments for purchase of property, plant and equipment in the consolidated cash Öow statements because the former is recorded on an accrual basis and the latter is based on actual cash payments in the relevant Ñscal year. (6) Calculated as net income as a percentage of average total assets based on total assets at the beginning and end of the Ñscal year. As the year ended March 31, 2000 was the Ñrst year for which we prepared consolidated Ñnancial statements, it is not possible to calculate the return on assets for that year. (7) Calculated as net income as a percentage of average total shareholders' equity based on the mean of shareholders' equity at the beginning and end of the Ñscal year. As the year ended March 31, 2000 was the Ñrst year for which we prepared consolidated Ñnancial statements, it is not possible to calculate return on equity for that year. (8) Calculated as shareholders' equity as a percentage of total assets at the end of the Ñscal year. (9) Calculated as interest-bearing debt divided by shareholders' equity.
16
Selected Operational Data The following table presents selected consolidated operational data as of or for the years ended March 31, 2000, 2001, 2002, 2003 and 2004. As of or for the year ended March 31, 2000 2001 2002 2003 2004 Employees(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Generation capacity: Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Amount of electricity supplied: Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Note: (1) The number of our employees as of July 31, 2004 was 6,076.
17
7,742
7,434
5,655 8,261 13,915
7,073 6,543 (MW) 7,755 7,825 7,825 8,261 8,261 8,261 16,015 16,085 16,085
5,871 7,959 8,551 16,509
30,041 9,786 39,827
(million kWh) 38,986 41,530 45,527 9,929 8,873 8,902 48,915 50,403 54,429
48,455 10,850 59,305
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis should be read in conjunction with our consolidated Ñnancial statements contained elsewhere in this oÅering circular. Our Ñnancial statements have been prepared in accordance with Japanese GAAP, which diÅers in certain signiÑcant respects from U.S. GAAP. See ""Summary of Certain SigniÑcant DiÅerences between Japanese and U.S. Generally Accepted Accounting Principles''. The discussion and analysis of Ñnancial condition and results of operations and all Ñnancial information set forth below are given on a consolidated basis unless stated otherwise. The discussion and analysis contains forwardlooking statements that involve risks, uncertainties and assumptions. Our actual results may diÅer materially from those anticipated in these forward-looking statements as a result of certain factors, including, but not limited to, those set forth under ""Investment Considerations''. See ""Forward-Looking Statements''. Overview Our Business: Wholesale Electricity Supply For many years, we have been a government-controlled entity engaged in the wholesale supply and transmission of electricity, primarily to Japan's ten EPCOs. We generate the vast majority of our electricity with coal-Ñred thermal power plants and hydroelectric power plants. As of March 31, 2004, we operated nine thermal power plants with an aggregate generation capacity of 7,959 MW, of which eight were coal-Ñred thermal power plants (including one owned by a consolidated subsidiary) and one was a geothermal power plant with a generation capacity of 13 MW, and 59 hydroelectric power plants with an aggregate generation capacity of 8,551 MW. We sold 59,305 million kWh of electricity generated at these power plants in the year ended March 31, 2004. We also engage in businesses related to our electricity supply business, directly and through several consolidated subsidiaries, such as construction, maintenance and fuel supply businesses for both our own electric power plants and those owned by other companies, and engineering and consulting services. Our Segments: Electric Power and Others We have two operating segments, electric power and others. In the years ended March 31, 2002, 2003 and 2004, the electric power segment accounted for 92.2%, 93.4% and 91.8% of our consolidated operating revenues, and 94.9%, 92.7%, and 90.4% of our consolidated operating income, respectively. Our electric power segment consists primarily of our wholesale electricity supply business, which primarily supplies electricity to the EPCOs. Under this segment, we have also made investments in other electricity supply businesses, including two IPPs and three companies with power plants selling electricity to PPSs, to take advantage of the deregulation of the electricity industry in Japan, and wind power plants, in response to government initiatives to promote environmentally-friendly sources of energy. Our others segment includes electric power-related businesses, primarily operated by our consolidated subsidiaries, and diversiÑed businesses. Our electric power-related businesses provide construction and maintenance services for power plants and telecommunications facilities and supply fuels for power plants. Although most of our electric power-related businesses revenues are from intersegment sales of services to our electric power segment, we also receive revenues from the provision of such services to third parties. Our diversiÑed businesses include domestic and overseas engineering and consulting services, investments in overseas independent power producers, alternative energy and environmental businesses and businesses that sell a variety of products produced with by-products of our electricity supply businesses. Our Sources of Cash and Revenues: Long-Term Electricity Supply and Transmission Arrangements We enjoy a stable source of proÑts and ample operating cash Öow from long-term electricity supply and transmission arrangements with the EPCOs. Prior to constructing a power plant or transmission facility, we obtain the agreement of the prospective customers of the facility regarding the size and cost of the facility and the basis for our fees. Once the facility begins operating, we supply or transmit electricity pursuant to electricity supply or transmission contracts. Pursuant to these arrangements, our fees are calculated on a fair cost plus fair return on capital basis. We determine the pricing of our fees separately for each facility in a manner designed to allow us to recover the costs of constructing, maintaining and operating the facility and to give us a fair return on our invested capital over time. Under our long-term electricity supply arrangements, we 18
are required to provide to the EPCOs, and the EPCOs are required to take, all of the electricity generated by the relevant power plant pursuant to ongoing discussion with the EPCOs regarding their electricity needs. The EPCOs pay for our fair cost and fair return on capital regardless of the amount of electricity they actually purchase.
Our Operating Environment: Slowing Growth of Electricity Demand and Deregulation In recent years, growth in demand for electricity in Japan has been declining, reÖecting, among other things, several years of economic stagnation and lower industrial activity. In March 2004, Japan's Agency for Natural Resources and Energy published a report stating that over the period from the year ended March 31, 2003 to the year ending March 31, 2014, demand for electricity to be supplied by EPCOs in Japan is expected to increase by a compound annual growth rate of about 1.1% per year, compared to an average compound annual growth rate of 2.4% from the year ended March 31, 1991 to the year ended March 31, 2000. For further information regarding historical and projected electricity demand in Japan, see ""The Electricity Industry in Japan Ì Demand for Electricity in Japan''. At the same time, Japan's electricity industry has been and will continue to be further deregulated. In response to deregulation, as well as the general economic environment, the EPCOs have lowered their retail electricity rates in recent years. For further information regarding deregulation of the electricity industry in Japan, see ""The Electricity Industry in Japan Ì Electricity Industry Deregulation in Japan''. Deregulation in the retail electricity industry has created and may continue to create pressure from the EPCOs for us to lower our current fees to the EPCOs over time.
Our Opportunities and Challenges: Reduce Costs and Build New Businesses We were regulated under the Electric Power Development Promotion Law, or the J-POWER Law, and the EUIL until October 2003, when the J-POWER Law was repealed, and since then, we have been regulated principally under the EUIL. Upon the sale of our shares by the Fund through the oÅerings, we expect to be completely privatized. To respond to the downward pressures on our fees for wholesale electricity, we have been focusing on improving our cost eÇciency by reducing personnel, maintenance, interest and other operating expenses and restructuring our subsidiaries. We have also been strengthening our Ñnancial condition by reducing our outstanding long-term debt over time as well as through a capital infusion in December 2003. We hope to continue enhancing our cost eÇciency and reducing our outstanding debt in the near term. See ""Business Ì Strategy''. Finally, we intend to take advantage of new opportunities created by the deregulation of the Japanese electricity industry. For example, we intend to play, and the Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy has indicated that it expects us to play, an important role in the new wholesale electricity exchange to be introduced in April 2005. We also plan to focus on growing our other electricity supply businesses and the businesses in our others segment to develop new sources of revenues.
Factors AÅecting Our Results of Operations Operating Revenues Electric Power Segment We currently derive almost all of our operating revenues from our electric power segment. Almost all of the operating revenues of our electric power segment come from the wholesale supply and transmission of electricity to the EPCOs. Our operating revenues from the sale of electricity depend on our generation capacity, demand from the EPCOs and the fees we charge to supply the electricity we generate, which are contractually negotiated and calculated on a fair cost plus fair return on capital basis. Because we are a wholesale supplier of electricity to the EPCOs, which in turn supply electricity to retail electricity customers, the size of our generation capacity and the amount of electricity we supply are indirectly aÅected by demand for electricity at the retail level.
19
The following tables show the generation capacity, amount of electricity supplied to our customers and operating revenues of our electric power segment over the last Ñve years:
Our Electric Power Segment Generation Capacity As of March 31, 2001 2002 2003 (MW)
2000 Capacity of power plants: Thermal(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
5,655 8,261 13,915
7,755 8,261 16,015
7,825 8,261 16,085
7,825 8,261 16,085
2004
7,959 8,551 16,509
Amount of Electricity Supplied and Operating Revenues (2)
2000 Amount of electricity supplied: Thermal(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric(3) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
30,041 9,786 39,827
Year ended March 31, 2001 2002 2003 (million kWh)
2004
38,986 9,929 48,915
45,527 8,902 54,429
48,455 10,850 59,305
41,530 8,873 50,403
(millions of yen) Operating revenues: Thermal(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric (conventional)ÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric (pumped-storage) ÏÏÏÏÏÏÏÏÏÏ Transmission ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other(4) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total operating revenues for electric power segmentÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í241,604 144,114 94,634 49,480 62,287 2,324
Í281,084 144,100 94,477 49,623 67,095 3,026
Í339,947 137,901 90,062 47,839 67,183 2,701
Í335,371 138,195 90,358 47,836 66,739 5,902
Í322,192 135,758 91,666 44,092 63,398 2,100
Í450,330
Í495,307
Í547,733
Í546,209
Í523,450
Notes: (1) The generation capacity, electricity supplied and operating revenues of our thermal power plants for the year ended March 31, 2004 reÖect the new consolidation of our IPP subsidiary ITOIGAWA POWER Inc. for the Ñrst time in that year. The generation capacity of ITOIGAWA POWER Inc., as of March 31, 2004 was 134 MW. (2) Operating revenue data for the year ended March 31, 2000 are unaudited. (3) The amount of electricity described in this table as supplied by our hydroelectric power plants does not include electricity supplied by our pumped-storage hydroelectric power plants. (4) Other electric power segment operating revenues include revenue from renting equipment and sales of ash. Through the Ñscal year ended March 31, 2003, other electric power operating revenues also included revenues from domestic engineering services. Beginning in the year ended March 31, 2004, operating revenues from such services have been recorded in the others segment.
Generation Capacity Because we typically conclude long-term electricity supply arrangements with one or more of the EPCOs to supply the electricity we generate at each power plant and because the fees we charge for electricity are calculated to ensure recovery of fair cost and fair return on capital, increased generation capacity typically leads to increased operating revenue of our electric power segment. In July and December of 2000, our Tachibanawan No. 1 and No. 2 thermal power plants commenced operation, increasing our power generation capacity at March 31, 2001 by 2,100 MW, or 15.0%, compared to March 31, 2000, to 16,015 MW. In the year 20
ended March 31, 2001, our segment operating revenues (including intersegment sales) were Í495,307 million, an increase of 10.0% from the previous year. Our generation capacity increased by 424 MW in the year ended March 31, 2004 due to the expansion of our hydroelectric power plants at Okutadami and Otori and the consolidation of our new IPP coal-Ñred thermal power plant at Itoigawa, leading to a total generation capacity of 16,509 MW at March 31, 2004, an increase of 2.6% from the previous year. Our electric power segment operating revenues (including intersegment sales) in the year ended March 31, 2004 were Í523,450 million, a decrease of 4.2% from the previous year, as the increased capacity introduced during the year was not suÇcient to overcome a decrease in our operating revenues due to reductions in the fees we charged for the electricity supplied by our existing thermal and hydroelectric power plants and for the use of our transmission facilities. We presently have plans to open two new major power plants over the next ten years, the 600 MW Isogo New No. 2 thermal power plant in the year ending March 31, 2010, and the 1,383 MW Oma nuclear power plant in the year ending March 31, 2012. For more information about these power plants, see ""Ì Cash and Capital Requirements Ì Capital Expenditures''. The planning and introduction of future power plant projects depend on projections of growth in demand for retail electricity, and changes in growth projections can lead to changes in the scheduled plans. For example, the original plan for our Tokuyama hydroelectric power plant was to open a 400 MW pumped-storage hydroelectric power plant by the year ending March 31, 2009, but changes in retail electricity demand projections, among other reasons, led to proposed changes in the planned scale and schedule of the project. Under the proposed plan, we will construct and commence operation of a 153 MW conventional hydroelectric power plant by the year ending March 31, 2015. For more information regarding retail electricity demand and the eÅects of retail electricity demand on our business, see ""The Electricity Industry in Japan Ì Demand for Electricity in Japan'' and ""Ì Electricity Demand''. Electricity Demand The amount of electricity we generate and supply to the EPCOs is based on demand from the EPCOs. The EPCOs' electricity demand is directly related to retail demand for electricity. As a result, demand for electricity in Japan indirectly impacts our operating revenues. In the long-term, demand for electricity impacts the number and capacity of the power plants we can build and operate. In the short term, demand for electricity impacts the amount of coal-Ñred electricity we generate and sell, which aÅects our operating revenues related to the variable portion of our fees from coal-Ñred thermal power plants. The amount of demand for electricity in Japan does not have a material eÅect on our operating revenues from existing hydroelectric power plants and transmission facilities. Electricity demand in Japan has grown steadily in recent years. The compound annual growth rate for electricity demand in the period from the year ended March 31, 1994 to the year ended March 31, 2004 was 1.9%. In the short to medium term, demand for electricity in Japan is expected to continue to grow, but at a slower pace. The Agency for Natural Resources and Energy announced in March 2004, based on demand and supply projections prepared by the EPCOs, that the compound annual growth rate for retail electricity demand in Japan for the period from the year ended March 31, 2003 to the year ending March 31, 2014 is expected to be 1.1%. In the residential and commercial sector, the introduction of larger electric appliances, such as refrigerators, televisions and air conditioners of larger size, capacity and variety, is expected to sustain growth in demand for electricity despite the introduction of various energy-saving devices. In the industrial sector, a shift from electricity-intensive industries to less electricity-intensive industries and the ongoing movement of manufacturing operations oÅshore is expected to result in slower growth of electricity demand. Electricity demand in Japan varies from year to year and season to season, mainly reÖecting diÅerences in weather and economic conditions. In the years ended March 31, 2002 and 2004, for example, mild summer and winter weather decreased consumption of electricity for air conditioning and heating, which decreased demand for electricity and aÅected our operating revenues related to the variable portion of our fees from coal-Ñred thermal power plants. Peak electricity demand typically occurs in the afternoon in the summer months and in the evening in the winter months, when more customers are using electricity for airconditioners or heaters. Our coal-Ñred thermal power plants supply electricity to EPCOs mainly as a base electricity source, and our hydroelectric power plants generate electricity mainly to meet the EPCOs' peak retail electricity demand needs. Our hydroelectric power plants are suited to meeting peak electricity demand because they can be activated quickly as and when necessary.
21
Electricity Fees The fees we charge for the electricity we supply and transmission facilities we provide to the EPCOs are calculated on a fair cost plus fair return on capital basis. They are determined through negotiation with our EPCO customers and are set forth in our electricity supply and transmission contracts with them. Our fees vary plant-by-plant, reÖecting the costs speciÑc to the particular power plant. We use the following types of basic pricing formulas depending on the type of power plant, which reÖect diÅerent cost and power generation structures: ‚
Our fees for coal-Ñred thermal power plants include both a Ñxed portion, to recover Ñxed costs and provide a fair return on capital, and a variable portion, to recover variable costs of fuel and cleaning chemicals needed to reduce environmentally harmful emissions.
‚
Our fees for conventional hydroelectric power plants include both a Ñxed and a variable portion, with the variable portion reÖecting the amount of electricity supplied, which is, in turn, aÅected generally by changes in the Öow of water into the reservoir, or streamÖow.
‚
Our fees for pumped-storage hydroelectric power plants and transmission services include only a Ñxed portion.
The amount of fees we derive from the Ñxed and variable portions of fees we charge for electricity from our thermal power plants depends on the amount of electricity we supply from them. As the amount of electricity we supply increases, the amount of our variable fees increases. In the year ended March 31, 2004, we derived approximately 70% and 30% of our coal-Ñred thermal power plant revenues from the Ñxed fees and variable fees for our electricity, respectively. The fee structure for our conventional hydroelectric power plants is set so that we derive approximately 80% of our revenues from the Ñxed portions of our fees in a year with average streamÖow. Until October 2003, our electricity supply and transmission fees were subject to approval by the METI. Our electricity supply fees are currently subject only to notiÑcation procedures. Our transmission fees will remain subject to the approval of the METI until March 31, 2005, and will thereafter be subject only to notiÑcation procedures. Under the notiÑcation procedures, however, the METI can issue an order to change a fee arrangement if the fees do not meet certain basic standards, if they are discriminatory, or if they otherwise hinder the public interest. Thermal power fees. The components of fair cost and fair return on capital for each of our coal-Ñred thermal power plants include variable costs, Ñxed costs and fair return on capital. The variable costs are covered by the variable portion of our fees from the relevant power plant and the Ñxed costs and fair return on capital are covered by the Ñxed portion of the fees from the power plant. The variable portion of the fees for each of our coal-Ñred thermal power plants is determined by multiplying the amount of electricity supplied by the sum of the cost, per unit of electricity, of fuel and of the chemicals used in the desulfurization and denitration units we use to reduce emissions from the power plants. As the amount of electricity we supply to the EPCOs from a coal-Ñred thermal power plant increases, the amount of our variable fees for the relevant power plant also increases, increasing our revenues. As the unit price for the fuel and chemicals is assumed, as in the case of Ñxed costs, it is possible that our actual unit price of fuel will be diÅerent from the assumptions used to establish our fees. The Ñxed costs for each of our coal-Ñred thermal power plants are determined based on assumptions regarding maintenance and operation costs related to the power plant, including depreciation, maintenance and headquarter costs and taxes. Depreciation expenses included in the assumed cost for each of our coal-Ñred thermal power plants other than our Tachibanawan and Matsuura coal-Ñred thermal power plants are calculated pursuant to the declining-balance method. The depreciation expenses for our Tachibanawan and Matsuura coal-Ñred thermal power plants are calculated pursuant to the straight-line method. Because the expense amounts used in determining our fees are assumed, they may vary from the actual expenses of operating the power plant. The amount of the fair return on capital is determined by multiplying a fair rate of return, which is based on the average cost of capital for all of our operations, including both a negotiated return on equity and an assumed interest rate on our debt, by the book value of the power plant in question. In negotiating the return on equity, we take into account, among other things, the average returns on equity among a broad range of public and private companies in Japan over several recent Ñscal years. We negotiate the assumed interest rate on our debt by reference to the average interest rate on our debt. The book values of our power plants generally decrease over time as the assets are depreciated, but may increase as to a particular 22
power plant if major improvements or modiÑcations are made to the power plant after it commences operation. The amount of electricity generated by each of our coal-Ñred thermal power plants is determined based on ongoing discussions with the EPCOs that draw electricity from the relevant power plant and is based on the EPCOs' need for electricity to meet retail electricity demand. As a result, revenues generated by our coal-Ñred thermal power plants depend indirectly on retail demand. However, the Ñxed portion of our fees covers the Ñxed costs and return on capital for each of our coal-Ñred thermal power plants regardless of the amount of electricity we supply to the EPCOs, and only the variable portion of our fees changes depending on the amount of electricity we generate and supply to the EPCOs. The following table summarizes the components of the fair cost and fair return on capital and of the variable and Ñxed portions of our fees for our thermal power plants: Fair cost and fair return on capital components underlying fee Variable costs Fuel cost
Assumed cost of coal as well as heavy and diesel oil used to aid combustion.
Cost of chemicals
Assumed cost of chemicals needed to reduce pollution-causing emissions.
Fixed costs Generally calculated based on the decliningbalance method, but based on the straight-line method for Tachibanawan and Matsuura power plants.
Maintenance costs
Assumed expenses required to operate the facility, including personnel and repair expenses and other miscellaneous costs.
Headquarters costs
An allocated portion of expenses relating to headquarter and branch office operations. Assumed property tax and enterprise tax.
Taxes
amount of electricity supplied unit price per electricity, which is based upon assumed unit cost of variable cost items Fixed portion of fee
Depreciation
Return on capital
Overall fee Variable portion of fee
Calculated by multiplying book value of power plant by a fair rate of return.
Pursuant to our long-term electricity supply arrangements, the fair cost and fair return on capital for each of our coal-Ñred thermal power plants are reviewed by the parties and adjusted every two years to reÖect changes in our actual costs and changes in the factors used in calculating our return on capital. The electricity supply contracts covering approximately 10% of our capacity are reviewed in Ñscal years ending with even numbers and the electricity supply contracts covering approximately 90% of our capacity are reviewed in Ñscal years ending with odd numbers. We generally reduce the Ñxed portion of our fees related to each of our thermal power plants in connection with the biennial fee revisions due to declines in the assumed depreciation costs of the power plants and declines in the book values of the power plants used in calculating our return on capital. Our assumed fuel costs are revised annually in the event of signiÑcant changes in prices. Because we procure most of the coal from overseas, the variable portion of our rates is also adjusted retroactively every quarter as necessary to oÅset the eÅects of actual changes in underlying foreign exchange rates. In recent years, the fees for each of our coal-Ñred thermal power plants have been reduced to reÖect lower actual costs, including lower depreciation costs, and lower maintenance costs and headquarters costs due to deÖation and our cost control eÅorts, as well as lower returns on capital, which resulted from declining book values and declining actual interest rates, due in part to our repayments of debt with higher interest rates. We agreed with the EPCOs to lower the assumed fuel costs for each of our thermal power plants from April 2003 due to a decline in our actual fuel costs. In October 2003, however, world coal prices began to rise signiÑcantly, and accordingly, we agreed with the EPCOs between June and August 2004 to increase the assumed cost of coal for each of our thermal power plants, eÅective from April 1, 2004. Conventional hydroelectric power fees. The fair cost and fair return on capital components of our fees for each of our hydroelectric power plants are determined in a manner similar to that for our coal-Ñred thermal power plants, except for the lack of any variable costs associated with the operation of hydroelectric power plants. As with our coal-Ñred thermal power plants, we make assumptions regarding maintenance and operation costs related to the power plant, including depreciation, personnel, tax and other expenses. However, because the costs of operating a hydroelectric power plant are stable and predictable, our fair cost and fair return on capital are based on assumptions and estimates made at the time a power plant is constructed, and in general do not change unless our fees are renegotiated due to substantial changes in our actual operating costs or actual cost of capital. The assumed tax costs for our hydroelectric power plants include a water usage charge paid to the Government of Japan in connection with our use of a public resource to generate power. 23
Unlike most of our coal-Ñred thermal power plants, the estimated depreciation cost included in the fee calculation for our hydroelectric power plants is calculated pursuant to the straight-line method. Because the expense amounts used in determining our fees are assumed, they may vary from the actual expenses of running the power plant. The amount of the fair return on capital is determined by multiplying a fair rate of return, which is based on the long-term average cost of capital for all of our operations, including both a negotiated return on equity and an assumed interest rate on our debt, by the cost of constructing the power plant, rather than by the current book value as is the case with our coal-Ñred thermal power plants. In negotiating the return on equity, we take into account, among other things, the average returns on equity among a broad range of public and private companies in Japan over several recent Ñscal years. We negotiate the assumed interest rate on our debt by reference to the average interest rate on our debt. The fees for each of our conventional hydroelectric power plants consist of a Ñxed portion and a variable portion. The Ñxed portion of our fee is typically set to be equal to approximately 80% of the total fees for the power plant in a year with average streamÖow. Because we determine the assumed depreciation costs for our hydroelectric power plants pursuant to the straight-line method and calculate the fair return based on construction costs and not book value, the operating revenues from the Ñxed portion of our fees from conventional hydroelectric power plants are essentially Ñxed from year to year, unless we renegotiate them as described below. The variable portion of the fees for each of our conventional hydroelectric power plants is based upon the volume of electricity sold multiplied by a price per unit of electricity. The price per unit is determined so that in years in which the streamÖow in the watershed for the relevant power plant is 100% of the 30-year historical average streamÖow for the relevant power plant at the time it commenced operations, the variable portion of our fee will precisely cover the remaining 20% of our fair cost and fair return on capital. In years in which streamÖow exceeds the average, we receive a variable portion of fees larger than the amount necessary to recover our costs and return on capital. In years in which the streamÖow is less than the average amount, our fees do not fully recover our estimated costs and return on capital. For every 1% change in stream Öow, we typically experience a change of about Í100 million to Í200 million in operating revenues. In general, we operate our hydroelectric power plants to maximize power generation using all of the available water, and the EPCOs purchase all of the electricity that we generate. Thus, streamÖow, not demand, determines operating revenues from our conventional hydroelectric power plants. StreamÖow is determined by snow and rainfall, which are dependent upon weather patterns and vary from year to year. The aggregate streamÖow for our conventional hydroelectric power plants generally varies between 90% and 110% of the historical average. The aggregate average streamÖows with respect to all our conventional hydroelectric power plants to our dams were 92%, 91% and 109% of the historical average in the years ended March 31, 2002, 2003 and 2004, respectively. We would sell 9,700 million kWh of electricity a year generated at our currently existing conventional hydroelectric power plants under historical average streamÖow conditions. The following table summarizes the components of the fair cost and fair return on capital and of the variable and Ñxed portions of our fees for our conventional hydroelectric power plants: Fair cost and fair return on capital components underlying fee Variable costs
None.
Fixed costs Depreciation
Calculated based on the straight-line method.
Maintenance costs
Assumed expenses required to operate the facility, including assumed personnel and repair expenses and other miscellaneous costs. An allocated portion of assumed expenses relating to headquarter and branch office operations. Assumed property tax and enterprise tax. Water usage charge.
Headquarters costs Taxes Return on capital
Overall fee Variable portion of fee (20% in a year with average streamflow)
Fixed portion of fee (80% in a year with average streamflow)
Calculated by multiplying construction costs for the power plant by a fair rate of return.
We and the relevant EPCOs renegotiate the assumed fair cost and fair return on capital for our conventional hydroelectric power plants when there are substantial changes in our actual operating costs or actual cost of capital due, for example, to substantial shifts in interest rates or signiÑcant inÖation or deÖation. In such cases, we generally revise the fee arrangements with respect to all of our hydroelectric power plants, including pumped-storage hydroelectric power plants, and our transmission facilities simultaneously. In the 1970s and 1980s, we increased our hydroelectric power plant fees and transmission fees Ñve times to reÖect 24
increased costs of capital and increased personnel and other expenses. More recently, following discussions with our EPCO customers, we reduced our hydroelectric fees and transmission fees by an average of 3.4% in April 2001 and by an average of 6.5% in April 2003, reducing our fair return on capital to reÖect lower costs of capital. Pumped-storage hydroelectric power and transmission fees. The fee structures for pumped-storage hydroelectric power and for electric power transmission are similar. Our pumped-storage hydroelectric power plants utilize surplus electricity, during nights and weekends, to pump water from reservoirs at lower elevations to reservoirs at higher elevations so that more electricity can be generated during peak periods. As the electricity required to pump water to the higher elevation reservoirs is provided by our EPCO customers free of charge, our cost of operating pumped-storage hydroelectric power plants is stable and predictable. The fees for our pumped-storage hydroelectric power plants are based entirely on a Ñxed fee calculated to recover all costs of maintenance and operation and fair return on capital in the manner described for conventional hydroelectric power plants above. There is no variable portion within our fees for pumped-storage hydroelectric power plants. Our transmission facilities are mostly used for transmission of electricity within the network of a given EPCO or as trunk lines to connect two or more EPCOs' networks. The EPCOs pay us fees to use our transmission facilities. As with our fees for supplying electricity from our pumped-storage hydroelectric power plants, our transmission facilities fees consist only of a Ñxed portion and are calculated on a fair cost plus fair return on capital basis and determined by arrangements with the EPCOs that used our transmission facilities. The calculation of fair cost and fair return on capital for our transmission facilities is substantially similar to that used in calculating the fees for our hydroelectric power plants. As such, operating revenues related to fees from pumped-storage hydroelectric power plants and transmission facilities are essentially Ñxed from year to year, although they can change due to renegotiations of the applicable fees, in substantially the same manner as discussed above with respect to conventional hydroelectric power plants. The following table summarizes the components of the fair cost and fair return on capital and of the fees for our pumped-storage hydroelectric power plants and transmission facilities: Fair cost and fair return on capital components underlying fee Variable costs
None.
Overall fee Fixed
Fixed costs Depreciation
Calculated based on the straight-line method.
Maintenance costs
Assumed expenses required to operate the facility, including assumed personnel and repair expenses and other miscellaneous costs. An allocated portion of assumed expenses relating to headquarter and branch office operations. Assumed property tax and enterprise tax. Water usage charge.
Headquarters costs Taxes Return on capital
Calculated by multiplying construction costs for the power plant by a fair rate of return.
Because the fees for our pumped-storage hydroelectric power plants and transmission facilities are based on assumptions regarding costs and return that are similar to those governing our conventional hydroelectric power plants, we generally adjust the fees for our pumped-storage hydroelectric power plants and transmission facilities at the same time we adjust them for our conventional hydroelectric power plants. As noted above with respect to conventional hydroelectric power plants, we reduced our fees for our hydroelectric power plants and transmission facilities in April 2001 and 2003. Other Electric Power Segment Revenues Our electric power segment operating revenues also include operating revenues from an IPP thermal power plant. We make investments in a variety of electricity supply businesses that we have developed to take advantage of the deregulation of the Japanese electricity industry. We have made investments in two IPPs with thermal power plants, three companies with gas-Ñred thermal power plants to provide electricity to PPSs and a number of wind power plant projects. The prices for the electricity sold by these power plants are determined based on bids or negotiated contracts executed prior to the time the power plant begins to operate. 25
One of the IPP thermal power plants that we invested in became a consolidated subsidiary and contributed operating revenues to our electric power segment for the Ñrst time in the year ended March 31, 2004. All of the other businesses were operated by non-consolidated subsidiaries and aÇliates that did not contribute to our operating revenues. We expect to consolidate six wind power subsidiaries for the Ñrst time in the year ending March 31, 2005. We expect that some of our other non-consolidated subsidiaries will also be consolidated in the coming years as we plan to begin consolidating non-consolidated subsidiaries as they commence operation of their power plants and begin to generate revenues. See ""Ì Other Factors AÅecting Results Ì Scope of Consolidation and Equity Method Accounting''. Others Segment We generate operating revenues from electric power-related businesses, such as construction, fuel coal supply, maintenance and other services related to the electricity industry. Most of our revenues from our electric power-related businesses are from intersegment sales of services in our electric power segment, although we also generate revenues from the provision of such services to third parties. Although most of our diversiÑed businesses involve investments in non-consolidated subsidiaries and non-equity method aÇliates, as well as overseas independent power producers that are accounted for as equity method aÇliates, we derive some operating revenues from service fees earned by the engineering and consulting business included in the diversiÑed businesses portion of our others segment. Operating Expenses Most of our operating expenses are associated with our electric power segment, which accounted for 88.3% of our total consolidated operating expenses of Í437,715 million in the year ended March 31, 2004. The most important components of the operating expenses of the electric power segment are depreciation and amortization costs, fuel costs, personnel expenses and repair expenses. As part of our eÅorts to address the deregulation of the Japanese electricity industry, we are making eÅorts to decrease our actual costs of constructing, maintaining and operating our electric power plants, such as personnel, fuel, repair and maintenance costs. Our basic policy is to maintain suÇcient safety levels in our power plants while making structural cost-reduction eÅorts to improve our proÑtability, and to the extent reduced cost is reÖected in our fees, cost competitiveness. Electric Power Segment Depreciation and Amortization Costs Depreciation and amortization is our largest operating expense, accounting for 34.5%, 32.9% and 33.2% of our electric power segment operating expenses in the years ended March 31, 2002, 2003 and 2004, respectively. In general, we apply the declining-balance method for the depreciation of buildings, structures and machinery related to our power plant and the straight-line method for other equipment. However, we apply the straight-line method of depreciation to most of the assets associated with our Tachibanawan and Matsuura thermal power plants, and the declining-balance method only for their environmental protection equipment. We depreciate our power plants and related equipment over the number of years determined in accordance with Japanese corporate income tax laws. When we Ñnance our investment in a new power generation project through the incurrence of debt, we capitalize the interest payments made on the borrowed funds during the period prior to commencement of operation pursuant to accounting standards established by the EUIL. We later include the aggregate capitalized interest amount in determining the amount of depreciation with respect to the asset constructed with the borrowed funds. Although a portion of our electric power segment capital expenditures for the construction of power plants are funded by construction and research and development grants received from the Government of Japan and others, we do not include the value of investments funded through construction and research and development grants in the carrying value of our assets, so the value of such investments is not reÖected in our depreciation and amortization costs. After our Tachibanawan No. 1 and No. 2 thermal power plants commenced commercial operation in July and December 2000, and our Isogo New No. 1 thermal power plant began test operations in October 2001, depreciation and amortization costs increased from Í96,846 million in the year ended March 31, 2000 to Í123,479 million in the year ended March 31, 2001 and Í145,676 million in the year ended March 31, 2002. We have had no major power plants commencing operation since April 2002, and our depreciation and 26
amortization costs decreased to Í134,043 million in the year ended March 31, 2003 and Í128,395 million in the year ended March 31, 2004. Fuel Costs Fuel costs accounted for 22.0%, 21.2% and 22.2% of our electric power segment operating expenses in the years ended March 31, 2002, 2003 and 2004, respectively. Fuel costs consist mostly of the cost of coal to fuel our coal-Ñred thermal power plants, most of which we purchase from overseas suppliers. We primarily rely on one-year and longer-term coal supply contracts and supplement our fuel supply needs with spot purchases. As one means of establishing stable supplies at reasonable prices, we have invested in two coal mines in Australia, and we purchase the coal produced from them through long-term coal purchase agreements. We currently have a contract lasting through the year ending March 31, 2010 with Blair Athol Coal Pty. Ltd. and a contract lasting through the year ending March 31, 2012 with Ensham Coal Sales Pty. Ltd. The coal from these sources together accounted for roughly 40% of the total volume of coal we purchased in each of the three years ended March 31, 2004. Personnel Expenses Personnel expenses accounted for 12.9%, 12.3% and 10.9% of our electric power segment operating expenses in the years ended March 31, 2002, 2003 and 2004, respectively. We have been making eÅorts to decrease our personnel expenses. For example, we have been decreasing our total number of employees through an early retirement program and through reduced hiring. From March 31, 2001 to March 31, 2004, we decreased our total number of employees on a consolidated basis from 7,434 to 5,871. Charges incurred in the years ended March 31, 2003 and 2004 with respect to future incentive payments to be paid in connection with special early retirement programs for which applications were required by the end of those years are included in other income (expenses), net. Repair Expenses Repair expenses accounted for 7.2%, 8.9% and 7.4% of our electric power segment operating expenses in the years ended March 31, 2002, 2003, and 2004, respectively. We must support our power plants and transmission facilities by repairing equipment that becomes old, worn or obsolete. In connection with our cost control eÅorts, we are developing new computer systems to control maintenance and repair costs. While in the past we routinely replaced old parts based on an established schedule, we are now focusing on determining the true useful lives of various parts and equipment and developing a system to replace them only when they require replacement. Because our maintenance cycle in recent years repeats every two years, our repair expenses have tended to be larger in Ñscal years ending in an odd year, such as the year ended March 31, 2003. Other Operating Expenses Our consignment costs accounted for 5.4%, 6.2% and 6.8% of our electric power segment operating expenses in the years ended March 31, 2002, 2003 and 2004, respectively. We delegate some of the daily operation, maintenance, repair and inspection activities associated with operating our power plants to some of our consolidated subsidiaries, and to a lesser extent, to third parties. Our consignment costs represent the cost to our subsidiaries of performing such activities and the outsourcing expenses incurred in connection with payments to third parties for such activities. Generally, our consignment costs do not vary much from year to year, but they increase upon the introduction of new power plants or transmission facilities. Consignment costs also increase when we introduce major new computer software programs for internal use because we recognize the development expenses as part of our consignment costs. Our taxes and duties accounted for 5.6%, 5.7% and 6.2% of our electric power segment operating expenses in the years ended March 31, 2002, 2003 and 2004, respectively. The primary components of our taxes and duties are our property taxes and our enterprise taxes. Almost all of our property taxes relate to our power generation and transmission assets. With respect to enterprise taxes, because the Company and ITOIGAWA POWER, Inc. are electric utilities, we generally pay enterprise taxes for our electric power segment on our operating revenues, not on our operating income. The enterprise tax portion of our taxes and duties in the year ended March 31, 2004 was Í6,845 million. 27
Others Segment Operating expenses of our others segment are generally cost of sales that vary with revenues. Our businesses that provide construction and maintenance services for power plants and telecommunications facilities, for example, incur cost of sales such as the costs of raw materials and parts used in construction and maintenance activities. Our fuel supply businesses incur costs for the acquisition of fuel. Selling, general and administrative expenses of our others segment consist primarily of personnel expenses. We have been making an eÅort to reduce the personnel expenses of our others segment in recent years. Operating Income Our most important source of operating income is the income we earn in connection with the supply and transmission of electricity for EPCOs pursuant to long-term electricity supply and transmission arrangements. The income mostly arises from the fair return on capital which is included in the calculation of the fees paid to us for the supply of thermal and hydroelectric power and the transmission of electricity. We may also earn additional operating income in connection with the variable portion of our conventional hydroelectric power sales if the streamÖow in a given year is larger than the historical average. Alternatively, we may have lower operating income in connection with the variable portion of our conventional hydroelectric power sales if the streamÖow is lower than the historical average, although the eÅect of annual variances in streamÖow on our overall operating income is small. In addition, because the costs covered by our fees are assumed costs, we may earn additional operating income if our actual costs are lower than the assumed costs, and we have been working to reduce our actual operating expenses to achieve that result. While a decrease in assumed interest rates used in the calculation of our fair return on capital results in a decrease in operating revenues, a decrease in our actual interest expense is reÖected in other income (expenses), net and not in our operating expenses. As a result, an increase or decrease in the assumed interest rates included in the calculation of our return on capital directly impacts our operating income while that impact is typically oÅset at the income before income taxes and minority interest level by an increase or decrease in our actual interest expenses. Increases or decreases in our actual interest expenses are typically larger than the impact of increases or decreases in the assumed interest rates because the assumed interest rates are negotiated by reference to the actual average interest rate on our debt and are not automatically adjusted to match the actual rate. In the year ended March 31, 2004, for example, we reduced our fees for hydroelectric power plants and transmission facilities to reÖect lower costs of capital based in part on lower assumed interest rates. We also reduced the fees for our thermal power plants, in part to reÖect lower costs of capital due to lower assumed interest rates, as well as to reÖect lower book values of our power plants, and lower depreciation and operating costs. As a result of these fee reductions, our operating income for the year declined to Í132,138 million from Í134,201 million for the previous year, despite an increase in the amount of electricity we supplied to the EPCOs. On the other hand, due in part to a decline in our actual interest expenses, our income before income taxes and minority interests increased to Í43,757 million in the year ended March 31, 2004 compared with Í35,522 million in the previous year. Assuming that the present low interest-rate environment in Japan continues, we expect operating income will decline further as low interest rates are reÖected in the assumptions used in our return on capital calculations included in our fees. However, we believe any such decline in operating income will generally be oÅset by decreases in our actual interest expenses. Other Income and Expenses Interest Expense The most signiÑcant portion of our other income and expenses is interest expenses on our long-term debt. In order to improve our long-term cost competitiveness and proÑtability, we have been prepaying our outstanding debt to the Government of Japan and decreasing the amount of our outstanding bonds through debt assumption agreements, despite the increase in short-term costs associated with prepayment premiums. See ""Ì Liquidity and Capital Resources Ì Liquidity''. Our interest expenses for the years ended March 31, 2002, 2003 and 2004 were Í68,160 million, Í87,136 million and Í83,519 million, respectively. These amounts include amounts paid as prepayment premiums in connection with our early redemption of relatively high interest rate loans from the Government of Japan and, with respect to the year ended March 31, 2002, payments made to cover the present value of all future interest payments with respect to bonds for which we entered into debt assumption arrangements. For further information regarding our interest expenses and our repayment of borrowings from the Government of Japan, see ""Liquidity and Capital Resources Ì Liquidity''. 28
Other In recent years, another signiÑcant source of other expenses has been expenses associated with impairment charges on equipment and facilities at electric power plants under construction, either because of the termination of, or changes in, the construction plans. In the three years ended March 31, 2004, we recorded an aggregate of approximately Í14,000 million of such expenses in connection with changes in the construction plans at Ñve power plant sites. For further information regarding our expenses in connection with changes in power plant construction projects, see ""Investment Considerations Ì Risks Related to Our Business Ì Declining growth in electricity demand and other changes in conditions may force us to delay or discontinue our current power plant construction, leading to additional costs and possible losses''. Other Factors AÅecting Results Scope of Consolidation and Equity Method Accounting We have investments in a number of non-consolidated subsidiaries and non-equity method aÇliates. As permitted by Japanese GAAP, we do not consolidate the results of non-consolidated subsidiaries because we have concluded, after a review of their assets, operative revenues, net income, retained earnings and other Ñnancial information, that in the aggregate they do not have a signiÑcant eÅect on our consolidated Ñnancial condition and results of operations. Our non-consolidated subsidiaries generally do not have a signiÑcant eÅect on our Ñnancial condition and results of operations because they operate businesses that are peripheral to our main wholesale electricity supply business or are start-up businesses in alternative energy and related Ñelds and have comparatively small amounts of assets and operating revenues. We consolidate new subsidiaries as their eÅect on our consolidated Ñnancial position and results of operations becomes signiÑcant. In the year ended March 31, 2004, we began consolidating our subsidiaries ITOIGAWA POWER Inc., a coal-Ñred thermal power IPP, and J-Power Investment Netherlands B.V., a holding company for some of our overseas independent power producer investments. In the year ending March 31, 2005, we expect to begin consolidating the results of six wind power plant subsidiaries and a liqueÑed natural gas, or LNG, thermal power plant subsidiary, the latter of which sells electricity to a PPS. We are currently contemplating consolidating all of our subsidiaries by the year ending March 31, 2007. Pursuant to the requirements of Japanese GAAP, non-consolidated subsidiaries and aÇliates that do not have a signiÑcant eÅect on our consolidated net income and retained earnings are not accounted for by the equity method. Most of our aÇliates are overseas independent power producers or alternative energy businesses. Prior to the year ended March 31, 2003, we had no equity-method aÇliates. In the year ended March 31, 2003, we started accounting for our investments in seven overseas independent power producers by the equity method because the eÅect on our consolidated net income and retained earnings of these investments became signiÑcant. In the year ended March 31, 2004, we started accounting for our investments in four additional overseas independent power producers by the equity method. Such additional consolidation and accounting for aÇliates by the equity method have not had, and we believe will not have, a material eÅect on our Ñnancial condition and result of operations, although we expect such entities will contribute to our Ñnancial condition and results of operations to diÅering degrees in the future. Seasonality Our operating revenues and income are typically higher in the Ñrst half of our Ñscal year than in the second half of our Ñscal year for the following reasons: ‚
we have increased revenues from coal-Ñred thermal power plants in the summer months due to higher customer demand for electricity to run air conditioners;
‚
the streamÖow for our conventional hydroelectric power plants is typically greater in the Ñrst half of the year, spring and summer, than in the second half of the year, fall and winter, resulting in higher operating revenues and operating income from our conventional hydroelectric power plants; and
‚
our expenses have generally been larger in the second half of the year because more periodic maintenance expenses have been incurred in the second half of the Ñscal year as we generally perform maintenance during periods of lower seasonal electricity demand. 29
Critical Accounting Policies and Estimates We prepare our consolidated Ñnancial statements in accordance with accounting standards generally accepted in Japan. Note 2 of the notes to our consolidated Ñnancial statements includes a summary of the signiÑcant accounting policies used in the preparation of our consolidated Ñnancial statements. Some of our signiÑcant accounting policies are particularly sensitive because of their signiÑcance to our reported results and because they require our management to make estimates and judgments about future events that are inherently uncertain. We believe that among our signiÑcant accounting policies, the following policies particularly require our critical judgment and require us to make estimates regarding events that are subject to change.
Interest Payments During Construction Period Pursuant to accounting regulations applicable to electricity suppliers in Japan, interest payments made on funds borrowed to Ñnance the construction of Ñxed assets in relation to our electric power business and paid prior to the commencement of the use of such Ñxed assets are capitalized and included in the acquisition cost of such assets. The amount included in the value of our assets on our balance sheet, the amount of interest payments during construction, is computed by multiplying the average monthly interest rate by the compound monthly construction cost of the project. Internal funds used and funds borrowed during the preceding three years, including the current Ñscal year, are included in the deÑnition of borrowed funds for the purpose of the calculation. The reason for using the three year period is based on our estimate that the principal construction period for electric power-related Ñxed assets is three years.
Allowance for Retirement BeneÑts We calculate the cost and obligations related to retirement beneÑts for our employees based on estimates determined by actuarial calculations. Estimates include the discount rate and the expected rate of return on plan assets. We set the discount rates based on the recent market yields for Japanese government bonds. We base the expected rate of return on plan assets on the amount of proÑt reasonably expected for each Ñscal year on pension assets at the beginning of the Ñscal year. Cost recognized and obligations provided in future periods are generally aÅected if actual results diÅer from preconditions or the preconditions are changed. Such amortized amount decreased to Í4,145 million for the year ended March 31, 2004 from Í8,942 million for the year ended March 31, 2003. The amount of amortization for the following year depends on the economic environment.
Impairment of Investment Securities Most of the investment securities we hold fall under the ""other securities'' category established by accounting standards applicable to Ñnancial products in Japan. When the fair value for investment securities categorized as other securities without a market price drops more than 50% compared to book value, we recognize an impairment in the book value of the security down to the fair value. We generally calculate the fair value by multiplying the shareholders' equity per share of the relevant investment entity by the number of shares held, based on principles of calculation taking into account diÅerences in revaluation amounts based on market price standards for assets, using the most recent Ñnancial statements available before the end of each Ñscal year. When the market price for other securities with a market price drops more than 50% or drops 50% to 30% for two consecutive Ñscal years compared to book value at the end of the Ñscal period, we recognize the impairment in the book value of the security down to such market price at the end of the Ñscal year. However, in the following cases, we do not take an impairment even when the conditions for impairment above are met: ‚
in the case of other securities without a market price, when it can be demonstrated on a reasonable basis that the fair value will likely recover quickly and to a level substantially close to the book value and that the decline in the fair value is deemed to be temporary.
‚
in case of other securities with a market price, when it can be demonstrated on a reasonable basis that the market price at the end of the Ñscal year will likely recover to a level close to book value within one year from the end of Ñscal year. 30
Hedge Accounting for Derivatives We conduct hedging activities based on internal regulations relating to derivative transactions in order to mitigate currency and interest rate Öuctuation risks, and we do not engage in speculative transactions. We hedge the principal and interest payments on foreign currency denominated bonds and borrowings. We basically conduct hedging activities for almost all of our foreign currency bonds and borrowings as described above, but we may not necessarily enter into a hedging transaction for certain payments after considering the level of risk associated with them. We apply hedge accounting to all of these hedging activities. Outlook The Year Ending March 31, 2005 We expect that our operating revenues will decline in the year ending March 31, 2005 compared to the year ended March 31, 2004. We expect that our operating revenues will decline because we do not have any major new power plants, or any major expansion of generation capacity for an existing power plant, that will begin supplying electricity and producing additional revenue in the current Ñscal year and because we have lowered our fees for electricity generated at our coal-Ñred thermal power plants in the current Ñscal year. In April 2004, in connection with the biennial review of the long-term supply arrangements for most of our coal-Ñred thermal power plants, we agreed to reduce the fees we charge to EPCOs for the electricity generated at those power plants. SpeciÑcally, we reduced the cost assumptions related to the Ñxed portion of our fees for such power plants to reÖect lower actual costs, mainly depreciation and amortization costs, and we reduced the rate of return used to calculate the return on capital included in the Ñxed portion of our fees for such power plants, primarily to reÖect lower actual interest rates on our debt. In addition, the reduction in operating revenues also reÖects a decrease in the return on capital portion of the Ñxed fees for most of our coal-Ñred thermal power plants due to declining book values of those power plants resulting from ongoing depreciation. The adverse eÅect on revenue caused by the reduction of our Ñxed fees from coal-Ñred thermal power plants will be oÅset in part by an increase, eÅective April 1, 2004, in the assumed fuel costs used to determine the variable portion of our fees under each of our coal-Ñred thermal power plant electricity supply contracts, including those for which we did not conduct the biennial review in the current Ñscal year. We anticipate that our overall operating expenses will increase in the year ending March 31, 2005 compared to the previous Ñscal year due to increased fuel costs, reÖecting increases in coal prices, as well as to increases in repair expenses and consignment costs. We expect our repair expenses to increase in the current Ñscal year due to increased cyclical costs related to the periodic inspection, maintenance and repair of equipment at many of our coal-Ñred thermal power plants in the current Ñscal year, including biennial boiler maintenance and quadrennial turbine maintenance, and our consignment costs to increase due to the development and introduction of our new computerized maintenance control system. We expect that these increases will be oÅset in part by a decline in depreciation and amortization costs and personnel expenses. As a result of the foregoing, we expect our operating income to decline signiÑcantly in the year ending March 31, 2005. On the other hand, we expect our net income in the year ending March 31, 2005 to remain stable in comparison with the previous year. This is because we expect our interest expenses to decline signiÑcantly in the current Ñscal year, even after the incurrence of prepayment premiums or other payments in connection with our prepayments of long-term borrowings from the Government of Japan and debt assumption arrangements that we have entered into, and may additionally enter into, during the current Ñscal year, as a result of our continuing eÅorts to reduce our long-term debt with comparatively high interest rates.
31
The Six Months Ending September 30, 2004 The following table shows our operating revenues, operating income and net income for the six months ended September 30, 2002 and 2003:
Operating revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating incomeÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Six months ended September 30, 2002 2003 (millions of yen) Í286,604 Í276,908 74,739 76,426 28,092 19,328
We expect that our operating revenues and operating income in the six months ending September 30, 2004, compared to our operating revenues and operating income in the six months ended September 30, 2003, will decline in a manner generally consistent with, and for the same reasons as, the declines in our expected operating revenues and operating income for the year ending March 31, 2005 compared to the previous year. However, our operating revenues in the six months ending September 30, 2004 may not decline in comparison with our operating revenues in the six months ended September 30, 2003, as the variable portion of our fees from our thermal power plants may be larger than our current expectations primarily due to increased demand for electricity as a result of an unusually hot summer. Any such additional variable fees for the six months ending September 30, 2004, however, would be oÅset by additional variable costs related to the variable fees, primarily fuel costs, and would not materially aÅect our expectations for operating income for the same period. We expect that our net income will be lower in the six months ending September 30, 2004 than in the six months ended September 30, 2003, because we expect the amount of the decrease in operating income to be larger in the Ñrst half of the current Ñscal year than in the second half as a result of the increased repair expenses in the Ñrst half of the current Ñscal year. The foregoing statements are forward-looking statements based upon the assumptions and beliefs of our management regarding the demand from the EPCOs for electricity generated by us, the fees we charge, our ability to decrease our expenses through cost reduction eÅorts, streamÖow and other factors, and are subject to the qualiÑcations described under ""Forward-Looking Statements''. Our actual results of operations could vary signiÑcantly from those described above as a result of unanticipated changes in the factors described above, or other factors, including those described in ""Ì Factors AÅecting Our Results of Operations'' and ""Investment Considerations''.
32
Results of Operations The following table sets forth consolidated statement of income data for the periods indicated:
2002
Statement of Income Data: Operating revenues: Electric power ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OthersÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total operating revenues ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating expenses: Electric power ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Depreciation and amortization costs ÏÏÏÏÏÏÏÏÏ Fuel costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Personnel expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Repair expensesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Consignment costs ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Taxes and duties ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OthersÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ OthersÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total operating expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Operating income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other income(expenses), net: Interest expenses ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Loss on sale of Ñxed assets ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Unrealized loss on securities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Reversal of (provision for) reserve for Öuctuation in water levels ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Other, netÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total other income(expenses), net ÏÏÏÏÏÏÏÏ Income before income taxes and minority interests ÏÏ Income taxes: Current ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deferred ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Minority interests ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net income ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Year ended March 31, 2003 2004 2004 (millions of yen) (thousands of U.S. dollars)
Í547,333 46,010 593,343
Í545,824 38,297 584,122
Í522,922 46,931 569,854
$4,947,702 444,047 5,391,750
421,816 145,676 92,876 54,230 30,366 22,958 23,754 51,953 51,937 473,753 119,590
407,131 134,043 86,438 49,923 36,189 25,126 23,312 52,097 42,789 449,920 134,201
386,463 128,395 85,927 42,220 28,652 26,193 23,984 51,089 51,251 437,715 132,138
3,656,579 1,214,833 813,012 399,471 271,103 247,832 226,931 483,393 484,922 4,141,502 1,250,248
(68,160) (7,894) (5,951)
(87,136) Ì Ì
(83,519) Ì Ì
(790,234) Ì Ì
349 (7,407) (89,064) 30,526
Ì (11,543) (98,679) 35,522
(689) (4,172) (88,381) 43,757
(6,524) (39,474) (836,234) 414,014
16,386 (3,899) 400 Í 17,638
20,850 (6,480) 426 Í 20,725
16,222 (309) 220 Í 27,623
153,494 (2,931) 2,085 $ 261,365
The Year Ended March 31, 2004 Compared to the Year Ended March 31, 2003 Operating Revenues. Total operating revenues in the year ended March 31, 2004 decreased by 2.4%, or Í14,268 million, to Í569,854 million compared with Í584,122 million in the year ended March 31, 2003, reÖecting declines in operating revenues from our electric power segment. Total electricity sales volume (excluding pumped-storage) in the electric power segment increased 9.0% from the previous year to 59,305 million kWh. Thermal electricity sales volume increased by 6.4% to 48,455 million kWh, due to improvements in the load factor of our coal-Ñred thermal power plants and the addition of revenues from our newly consolidated IPP subsidiary, ITOIGAWA POWER. Hydroelectric electricity sales volume (excluding pumped-storage) increased 21.9% in the year ended March 31, 2004 from the previous year to 10,850 million kWh due to the expansion of the Okutadami and Otori power plants and higher-than-average streamÖow (109% of historical average) compared to lower-than-average streamÖow (91% of historical average) in the previous year. Despite these increases in the volume of electricity sold, however, total operating revenues from the electric power segment decreased by 4.2%, or Í22,902 million, to Í522,922 million in the year ended March 31, 2004 compared with Í545,824 million in the previous year. The decline 33
in total operating revenues despite increased capacity and sales of electricity reÖected decreases in our thermal and hydroelectric electricity and transmission fees. The thermal electricity fees were lowered to reÖect lower depreciation costs, lower personnel expenses, lower fuel costs and lower repair costs, as well as a reduction in our fair return on capital, which resulted from declining book values and declining actual interest rates, due in part to our repayments of debt with higher interest rates, and our hydroelectricity and transmission fees declined due to a reduction in our fair return on capital to reÖect lower costs of capital. Operating revenues from the others segment increased 22.5%, or Í8,633 million, to Í46,931 million compared with Í38,297 million in the previous year due primarily to increased sales of construction services in Japan, mostly with respect to construction services provided to our nonconsolidated wind power subsidiaries. In addition, in the year ended March 31, 2004, the others segment included the revenues of our domestic engineering consulting business, which were previously included in our electric power segment. Operating Expenses. Total operating expenses in the year ended March 31, 2004 decreased by 2.7%, or Í12,205 million, to Í437,715 million compared with Í449,920 million in the previous year. Operating expenses in the electric power segment decreased by 5.1%, or Í20,667 million, to Í386,463 million in the year ended March 31, 2004 compared with Í407,131 million in the year ended March 31, 2003 due to lower repair expenses as our repair expenses tend to be greater in years ending in odd numbers due to our maintenance schedule, lower personnel expense as a result of our eÅorts to reduce personnel and lower depreciation costs due to the lack of major new projects. Operating expenses of the others segment increased by 19.8%, or Í8,462 million, to Í51,251 million in the year ended March 31, 2004 compared with Í42,789 million in the year ended March 31, 2003, reÖecting the increase in revenues oÅset in part by our cost-reduction eÅorts. Operating Income. Operating income decreased by 1.5%, or Í2,062 million, to Í132,138 million in the year ended March 31, 2004 compared with Í134,201 million in the previous year, reÖecting a decline in the fair return on capital included in our fees, mainly due to a decrease in the assumed interest expenses incorporated in cost of capital, as well as to a decline in the book value of our thermal power plants, which oÅset increased operating income from our conventional hydroelectric power plants due to excess streamÖow of 109% of the historical average and lower operating expenses resulting from our eÅorts to reduce costs. Other Income (Expenses), Net. Other expenses, net decreased 10.4%, or Í10,297 million, to Í88,381 million in the year ended March 31, 2004 due to a decrease in other, net and interest expenses. Other, net decreased to expenses of Í4,172 million in the year ended March 31, 2004 from expenses of Í11,543 million in the previous year. The decline reÖected the absence of expenses related to changes in construction plans, a lower provision for severance payments for early retirement and lump-sum payments to transferees and a small increase in income from equity method aÇliates, mostly overseas independent power producers. Interest expenses decreased 4.2% or Í3,617 million, reÖecting our eÅorts to decrease our outstanding debt. A substantial portion of the interest expenses recorded in the year ended March 31, 2004 were related to prepayment premiums associated with our prepayment of borrowings from the Government of Japan. For further information regarding our interest expenses and our repayment of borrowings from the Government of Japan, see ""Ì Liquidity and Capital Resources Ì Liquidity''. Income Before Income Taxes and Minority Interests. Income before income taxes and minority interests grew 23.2% or Í8,234 million, to Í43,757 million in the year ended March 31, 2004 compared with Í35,522 million in the previous year as a result of the above factors. Income Taxes. Current income taxes decreased 22.2%, or Í4,627 million, to Í16,222 million compared with Í20,850 million in the year ended March 31, 2003. Deferred income taxes decreased 95.2%, or Í6,170 million, to Í309 million compared with Í6,480 million in the year ended March 31, 2003 due to diÅerences between the timing of the recognition of expenses, such as expenses associated with provisions for losses, under Japanese tax laws and accounting rules. As a result, net income taxes increased Í1,542 million, or 10.7%, to Í15,912 million. Net Income. Net income increased 33.3% or Í6,897 million, to Í27,623 million in the year ended March 31, 2004 compared with Í20,725 million in the previous year as a result of the above factors. 34
The Year Ended March 31, 2003 Compared to the Year Ended March 31, 2002 Operating Revenues. Total operating revenues in the year ended March 31, 2003 decreased by 1.6%, or Í9,221 million, to Í584,122 million compared with Í593,343 million in the year ended March 31, 2002, reÖecting declines in total operating revenues from the others segment and the electric power segment. Total electricity sales volume (excluding pumped-storage) of the electric power segment increased 8.0% over the previous year to 54,429 million kWh. Thermal electricity sales volume increased 9.6% to 45,527 million kWh as the Isogo New No. 1 thermal power plant commenced operation, and hydroelectric electricity (excluding pumped-storage) sales volume increased 0.3% from the previous year ended March 31, 2002. Despite increased volume of electricity sales, total operating revenues from the electric power segment decreased by 0.3%, or Í1,509 million, to Í545,824 million in the year ended March 31, 2003 compared with Í547,333 million in the previous year. We had lower total operating revenues despite increased electricity sales volume because we lowered our thermal electricity fees to reÖect reduced prices for coal and lower depreciation expenses. Total operating revenues of the others segment decreased 16.8%, or Í7,712 million, to Í38,297 million compared with Í46,010 million in the previous year due primarily to less demand in Japan for construction and engineering services. Operating Expenses. Total operating expenses in the year ended March 31, 2003 decreased by 5.0%, or Í23,832 million, to Í449,920 million compared with Í473,753 million in the previous year. Operating expenses in the electric power segment decreased by 3.5%, or Í14,684 million, to Í407,131 million in the year ended March 31, 2003 compared with Í421,816 million in the previous year. We incurred higher repair expenses for thermal power plants due to an increase in maintenance expenses reÖecting our two-year maintenance cycle, and an increase in consignment cost expenses due to increased expenses associated with the licensing and development of internal computer systems, but these increases were more than oÅset by declines in depreciation and amortization cost, a reduction in fuel costs and a decrease in personnel expenses. Operating expenses in our others segment also decreased 17.6%, or Í9,147 million, to Í42,789 million in the year ended March 31, 2003 compared with Í51,937 million in the previous year, reÖecting decreased total operating revenues and our cost-reduction eÅorts. Operating Income. Operating income increased by 12.2%, or Í14,611 million, to Í134,201 million compared with Í119,590 million in the previous year, reÖecting mainly increased returns on capital associated with the commencement of commercial operations at the Isogo New No. 1 coal-Ñred thermal power plant, as well as a decline in our operating expenses due to our eÅorts to control costs. Other Income (Expenses), Net. Other expenses, net increased 10.8%, or Í9,615 million, to Í98,679 million in the year ended March 31, 2003, due to increases in interest expenses and other expenses. Interest expenses increased 27.8%, or Í18,975 million, due to increased prepayment premiums related to prepayments of our borrowings from the Government of Japan as we increased our eÅorts to decrease our outstanding debt. For further information regarding our interest expenses and our repayment of borrowings from the Government of Japan, see ""Ì Liquidity and Capital Resources Ì Liquidity''. In the year ending March 31, 2002, other expenses, net included a loss on the sale of Ñxed assets of Í7,894 million in connection with the sale of our head oÇce building in a sale-and-leaseback transaction and an unrealized loss on securities of Í5,951 million related to a valuation loss on our investment in the Japan Nuclear Cycle Development Institute in connection with our adoption of impairment accounting for Ñnancial instruments. Other, net increased to expenses of Í11,543 million in the year ended March 31, 2003 from expenses of Í7,407 million in the previous year. The increase in net expenses reÖected an increase in expenses related to changes in construction plans, as well as the charges incurred in connection with severance payments for early retirement and lump-sum payments to transferees, which more than oÅset the inclusion of income from equity-method aÇliates, mostly overseas independent power producers. Income Before Income Taxes and Minority Interests. Income before income taxes and minority interests grew 16.4%, or Í4,996 million, to Í35,522 million compared with Í30,526 million in the previous year as a result of the above factors. Income Taxes. Current income taxes increased 27.2%, or Í4,464 million, to Í20,850 million compared with Í16,386 million in the previous year due to an increase in income before income taxes and 35
minority interests. Deferred income taxes increased 66.2%, or Í2,580 million, to Í6,480 million compared with Í3,899 million in the year ended March 31, 2002 due to diÅerences between the timing of the recognition of expenses, such as expenses associated with provisions for losses, under Japanese tax laws and accounting rules. As a result of the foregoing, net income taxes increased 15.1%, or Í1,883 million, to Í14,370 million. Net Income. Net income increased 17.5%, or Í3,086 million, to Í20,725 million in the year ended March 31, 2003 compared with Í17,638 million in the previous year as a result of the above factors. Cash and Capital Requirements Our cash and capital requirements mainly relate to capital expenditures, investments and debt service for our long-term debt. Because our capital expenditures declined following the completion in March 2002 of our most recent large-scale power plant construction project, the 600 MW Isogo New No. 1 thermal power plant, we were able to make early repayments on our long-term debt, particularly our relatively high-interest long-term borrowings from the Government of Japan, in the years ended March 31, 2003 and 2004. Capital Expenditures The following table sets forth our total capital expenditures, calculated on an accrual basis, for the three years ended March 31, 2004: Year ended March 31, 2002 2003 2004 (millions of yen) Electric power segment: New projects: Thermal power ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hydroelectric power ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Nuclear power ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Others (maintenance/upgrades) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total electric power segment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Others segment ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ EliminationsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í 88 Í 79 Í 2,582 11,264 14,939 4,667 2,418 10,844 8,858 65,016 29,024 28,789 78,787 54,885 44,896 1,802 1,347 3,837 (3,947) (2,790) (2,531) Í76,641 Í53,443 Í46,202
Note: The amounts of our total capital expenditures shown in the above table include expenditures funded through construction grants and capitalized interest incurred during the construction period in connection with borrowings used to Ñnance the construction of power plants. We received construction grants of Í11,883 million, Í3,958 million and Í3,124 million in the years ended March 31, 2002, 2003 and 2004, respectively.
Substantially all of our capital expenditures relate to our electric power segment. Total capital expenditures in our electric power segment have decreased from Í78,787 million in the year ended March 31, 2002 to Í54,885 million and Í44,896 million in the years ended March 31, 2003 and 2004, respectively. Our capital expenditures for ""others'' within electric power segment capital expenditures, which mainly consist of capital expenditures related to the maintenance and upgrade of our power plants (including capital expenditures related to initial construction that continues after the commencement of operation of a power plant) have been the most signiÑcant component of our total capital expenditures in the past three Ñscal years. Its decrease from Í65,016 million in the year ended March 31, 2002 to Í29,024 million and Í28,789 million in the years ended March 31, 2003 and 2004, respectively, was the main reason for the decrease in total capital expenditures over the previous three Ñscal years. The amount of such capital expenditures declined signiÑcantly between the years ended March 31, 2002 and 2003 mainly because in the year ended March 31, 2002 we made signiÑcant capital expenditures associated with payments for the Isogo New No. 1 thermal power plant made after commencement of its operations. Capital expenditures related to new hydroelectric power plants decreased signiÑcantly in the year ended March 31, 2004 to Í4,667 million, from Í14,939 million in the previous year, due mainly to the commencement of operations of the 287 MW expansion in the generation capacity of the Okutadami and Otori hydroelectric power plants, for which there were expenditures in the year ended March 31, 2003. We also incurred capital expenditures for preparatory construction related to the Oma nuclear power plant, for which construction is scheduled to commence in 2006, and we will 36
continue incurring related capital expenditures through the power plant's completion, scheduled to occur in 2012. While capital expenditures related to new thermal power plants were insigniÑcant in the years ended March 31, 2002 and 2003 because of the lack of major new projects, they increased to Í2,582 million in the year ended March 31, 2004, due mainly to an increase in expenditures associated with the preparatory construction of the Isogo New No. 2 thermal power plant. We had no capital expenditures related to new transmission facilities during the previous three Ñscal years. A portion of our electric power segment capital expenditures for the construction of power plants are funded by construction grants received from the Government of Japan and others. For more information on these grants, see ""Ì Liquidity and Capital Resources Ì Liquidity''. The following table sets forth our expected capital expenditures for the electric power segment for each of the two years ending March 31, 2006: Year ending March 31, 2005 2006 (millions of yen) Electric power segment: New projectsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Others (maintenance/upgrades) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í38,481 31,867 Í70,349
Í40,239 29,632 Í69,872
Note: The amounts of our total capital expenditures shown in the above table include expenditures we expect to fund through grants and capitalized interest we expect to incur during the construction period in connection with borrowings used to Ñnance the construction of power plants.
We started construction of the Tokuyama hydroelectric power plant project in 1997. Although it was originally scheduled to commence commercial operation in the year ending March 31, 2009, we and Chubu Electric Power Company, our project partner, have decided, based on a proposal by the Government of Japan to reduce the amount of water used for the generation of electricity, to change the structure and capacity of the hydroelectric power plant from a 400 MW pumped-storage hydroelectric power plant to a 153 MW conventional hydroelectric power plant, and we expect to delay commencement of operation until the year ending March 31, 2015. We are currently working to obtain the concurrence of the local government and community to these changes. We originally planned a total investment for the Tokuyama project of Í119,680 million. We have not yet determined what the total investment will be under the new plan. We are scheduled to start construction of our Isogo New No. 2 coal-Ñred thermal power plant and our Oma nuclear power plant in 2006, and we expect to start operation of the power plants in the years ending March 31, 2010 and 2012, respectively. In relation to the Oma nuclear power plant project, we have invested approximately Í104,453 million (including research and development grants) as of July 31, 2004, mainly related to preparatory construction, out of an estimated expected total investment of Í469,000 million. We expect that we will be able to fund our capital expenditures through our operating cash Öow for the next few years, prior to the commencement of the main construction activities in connection with the Oma and Isogo New No. 2 power plants. Thereafter, we expect that our operating cash Öow will not be suÇcient to cover our capital expenditures in each of the Ñve years ending March 31, 2012, and we will need to Ñnance the construction of our Oma and Isogo New No. 2 power plants. Investments and Advances We make investments in various domestic and foreign electric power-related and other companies and make advances generally in the form of loans to non-consolidated subsidiaries and aÇliates on an ongoing basis. In the years ended March 31, 2002, 2003 and 2004, we made investments and advances of Í15,403 million, Í42,207 million and Í22,250 million, respectively. The investments and advances made during these three years were primarily for overseas IPP projects in Thailand and Taiwan, three domestic IPP projects, three projects to supply electricity to domestic PPSs and a number of domestic wind power generation projects. We expect to continue making investments and advances in the future as opportunities and needs arise.
37
Debt Service and Repayments The following table summarizes the annual maturities of our long-term and short-term debt outstanding as of March 31, 2004: April 1, 2004 to March 31, 2005
April 1, 2005 to March 31, 2006
Í138,040
Í111,173
April 1, 2006 to March 31, 2007
April 1, 2007 to March 31, 2008 (millions of yen) Í162,645 Í196,145
April 1, 2008 to March 31, 2009
After April 1, 2009
Total
Í199,827
Í785,075
Í1,592,908
Short-Term Loan Obligations. Our short-term loan obligations as of March 31, 2004 consisted of Í40,466 million in short-term borrowings from private Ñnancial institutions, Í40,000 million of commercial paper, Í32,574 million in current portion of long-term borrowings and Í25,000 million of the current portion of long-term bonds. Long-term Debt Obligations. Our long-term debt obligations (excluding current portion) as of March 31, 2004 consisted of Í829,751 million in long-term bonds, of which Í121,240 million are held by government Ñnancial institutions, Í638,511 million are government-guaranteed bonds and Í70,000 million are non-guaranteed corporate bonds, and Í625,116 million in long-term borrowings, of which Í603,996 million are borrowings from private Ñnancial institutions and Í21,120 million are borrowings from the Government of Japan. We shifted to issuing only non-guaranteed corporate bonds beginning in the year ended March 31, 2003. For further information regarding our interest-bearing liabilities and their interest rates, see ""Ì Liquidity and Capital Resources Ì Liquidity''. All of our assets are subject to statutory liens to secure payment of our bonds issued prior to the repeal of the J-POWER Law. The corporate bonds we issued thereafter are unsecured. As of March 31, 2002, 2003 and 2004, the outstanding amounts of our bonds that were secured by the statutory liens were Í863,261 million, Í849,761 million and Í824,751 million, respectively. All of our borrowings are unsecured. Lease Obligations Future lease payments under all Ñnance leases as of March 31, 2004 were as follows: As of March 31, 2004 Due within one year Due after one year (millions of yen) Finance leases ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Í2,215 Í2,862 Note: Future lease payments under Ñnance leases include the imputed interest expenses portion.
We have Ñnance leases other than those which are deemed to transfer ownership of the leased property to the lessee, and as permitted under Japanese GAAP, we account for the payments on these leases as expenses without recording the leased assets on our balance sheet. Lease payments related to these Ñnance leases are included in the above table. We sold our headquarters building through a sale-and-leaseback transaction in 2001, and we entered into a lease contract to use the headquarters for the next seven years, with an obligation to make monthly rental payments totaling Í2 billion per year. OÅ-Balance Sheet Transactions and Contingent Liabilities As of March 31, 2004, we had contingent liabilities in the form of Í10,127 million in guarantees for borrowings mainly of non-consolidated subsidiaries and aÇliates, Í6,589 million in guarantees in relation to employee housing and retained liability under debt assumption arrangements with respect to Í50,120 million in aggregate debt assumed by bank counterparties. In July 2004 we entered into additional debt assumption 38
arrangements under which we have retained liability for an additional Í50,250 million in debt assumed by bank counterparties. We are obligated to lease our headquarters facility for a term of seven years from the time the lease was signed in 2001. If we terminate the lease early, we must pay an early termination penalty that declines over time. As of March 31, 2004, the early termination penalty would have been Í3,497 million yen. Liquidity and Capital Resources Liquidity In the past, our funding needs have been satisÑed mainly through issuing bonds to the Government of Japan, issuing government-guaranteed bonds and by long-term borrowings, mostly from the Government of Japan. In light of our planned privatization, we have in recent years increasingly been satisfying our funding needs through borrowings from private Ñnancial institutions and issuances of non-guaranteed corporate bonds, and we started relying exclusively on private funding sources for new funds beginning in the year ending March 31, 2003. We started issuing non-guaranteed bonds during the year ended March 31, 2003, and the aggregate outstanding amount of such bonds as of March 31, 2004 was Í70,000 million. Our borrowing costs did not increase as a result of this shift to private Ñnancing because we have been able to maintain a high credit rating for our bonds. The table below shows the net amount of new debt raised annually from various sources during the periods indicated, as well as the total amounts outstanding in each category as of March 31, 2004:
1995
1996
1997
Year ended March 31, 1998 1999 2000 2001 (billions of yen)
2002
Government Sources: Governmentguaranteed bonds ÏÏ Í 59.5 Í 79.9 Í 30.1 Í 65.5 Í150.6 169.3 158.0 Í 35.0 Government-funded bonds ÏÏÏÏÏÏÏÏÏÏÏÏ 25.0 43.7 44.0 33.6 Ì Ì Ì Ì Government borrowings ÏÏÏÏÏÏÏÏ 105.0 93.5 106.1 99.9 Ì Ì Ì Ì Total government sources ÏÏÏÏÏÏÏÏÏ Í189.5 Í217.1 Í180.2 Í199.0 Í150.6 Í169.3 Í158.0 Í 35.0 Private Sources: Private borrowings(1) Corporate bonds ÏÏÏÏÏ Total private sources ÏÏÏÏÏÏÏÏÏ
2003
2004
As of March 31, 2004
Ì
Ì
Í 638.5
Ì
Ì
146.2
Ì
Ì
23.2
Ì
Ì
Í 807.9
Ì Ì
Ì Ì
Ì Í 23.0 Í242.4 Í 74.0 Í 85.0 Í 90.9 Í298.9 Í229.0 Ì Ì Ì Ì Ì Ì 20.0 50.0
Í 700.1 70.0
Ì
Ì
Ì Í 23.0 Í242.4 Í 74.0 Í 85.0 Í 90.9 Í318.9 Í279.0
Í 770.1
Total external funding sources ÏÏÏÏÏÏÏÏÏÏÏÏÏ Í189.5 Í217.1 Í180.2 Í220.0 Í393.0 Í243.3 Í243.0
125.9 Í318.9 Í279.0
Í1,578.0
Note: (1) Amounts listed under private borrowings include both long-term borrowings and short-term borrowings and commercial paper. As we do not have consolidated data for the years ended March 31, 1995 through 2000, the information in this table presents only the interest-bearing debt of the Company on a non-consolidated basis.
We rely on short-term borrowings, including commercial paper, to satisfy our working capital requirements. We have a bank overdraft facility of Í10,000 million which we had not drawn on as of March 31, 2004. We have borrowing relationships with several commercial banks, trust banks, local banks, insurance companies and other Ñnancial institutions from which we receive loans from time to time. In the year ended March 31, 2004, we issued commercial paper for the Ñrst time, and the outstanding amount at March 31, 2004 was Í40,000 million. We are currently able to issue up to a total of Í40,000 million in commercial paper based on our current commercial paper credit rating. We also rely on long-term debt Ñnancing, both to Ñnance the construction of new power plants and to reÑnance existing debt. 39
We also Ñnance a portion of the amounts we invest in the construction of power plants through construction grants and research and development grants received from the Government of Japan and others. We received such grants worth Í11,883 million, Í3,958 million and Í3,124 million in the years ended March 31, 2002, 2003 and 2004, respectively. The total amounts of such grants we had received and deducted from the value of our property, plant and equipment on our balance sheet as of March 31, 2002, 2003 and 2004, were Í99,719 million, Í97,719 million, and Í98,128 million, respectively. We consider the reduction of our Ñnancing costs through the reduction of debt obligations with higher interest rates a key management objective. We have particularly focused on the prepayment of borrowings from the Government of Japan with comparatively high interest rates. The early repayment of government loans requires the approval of the Minister of Finance, or the MOF. Upon the grant of such approval by the MOF, we began to prepay some of our borrowings from the government, starting in the year ended March 31, 1999, and we have paid prepayment premiums in connection with some of the prepayments. We repaid or prepaid most of the remaining balance of our borrowings from the government in the two years ended March 31, 2004, utilizing our operating cash Öow and the cash received in our recapitalization in December 2003. As of March 31, 2004, we had Í23,200 million in long-term borrowings from the government outstanding. We have also reduced our long-term debt in the form of bonds by entering into debt assumption agreements with certain banks whereby the banks undertake to make payments of interest and principal on the subject debt in consideration for our payment of an amount equal to the net present value of the outstanding principal balance of the debt and future interest payments on such debt. Such debt assumption arrangements are means by which we eÅectively defease obligations with respect to the bonds and remove them from our balance sheet, although we remain contingently liable for such debt. The amount of long-term debt removed from our balance sheet by way of debt assumption in the two years ended March 31, 2002 totaled Í50,120 million. In the three years ended March 31, 2004, our total scheduled repayments and prepayments of government borrowings amounted to Í869,806 million. In the year ended March 31, 2002, we also engaged in debt assumption arrangements with respect to Í20,050 million of our bonds. As a result of these repayments and prepayments and debt assumption arrangements, our total outstanding long-term debt, including the current portion of long-term debt, declined from Í1,910,567 million as of March 31, 2002 to Í1,837,185 million as of March 31, 2003 and Í1,512,442 million as of March 31, 2004. The weighted average interest rate per annum of our long-term debt, including the current portion, declined from 3.18% as of March 31, 2002 to 2.50% as of March 31, 2003 and to 2.00% as of March 31, 2004. In recent years, our total amount of short-term loans has been smaller, with lower average applicable interest rates, compared to our long-term debt, and accordingly, the amount of interest expenses on our shortterm loans has been signiÑcantly smaller than for our long-term debt. We had an outstanding amount of shortterm loans of Í96,919 million with a weighted average interest rate per annum of 0.54% as of March 31, 2002, Í56,717 million with a weighted average interest rate of 0.50% as of March 31, 2003 and Í40,466 million with a weighted average interest rate of 0.38% as of March 31, 2004. We will continue to consider using prepayments and debt assumption or similar measures in the future as a means of lowering our interest expense burden as we deem appropriate in light of prevailing capital market conditions and the surrounding economic environment. In July 2004, we entered into debt assumption arrangements for Í50,250 million in government-guaranteed bonds, and we also prepaid all of our remaining government loans amounting to Í23,200 million. In the near term, we expect any additional debt assumption arrangements or similar measures to be more limited than in the most recent two Ñscal years. We also raised capital by issuing common stock in December 2003 to J-POWER Privatization Fund Co., Ltd., or the Fund, an entity formed in connection with our planned privatization, in order to strengthen our Ñnancial position. We received Í163,699 million in equity capital from the Fund. The funds raised have been used mainly to repay and prepay our debt. We currently have no plan to issue new shares in the current or subsequent Ñscal year.
40
Cash Flows The following table shows our cash Öow data for the years ended March 31, 2002, 2003 and 2004:
Cash and cash equivalents at the beginning of the yearÏÏÏÏÏÏÏÏÏÏÏ Net cash provided by operating activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net cash used in investing activitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net cash provided by (used in) Ñnancing activities ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ EÅect of exchange rate changes ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Net increase (decrease) in cash and cash equivalents ÏÏÏÏÏÏÏÏÏÏÏÏ Increase in cash from the addition of consolidated subsidiaries ÏÏÏÏ Cash and cash equivalents at the end of the yearÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Year ended March 31, 2002 2003 2004 (millions of yen) Í 23,186 Í 21,128 Í 59,787 200,708 167,368 179,948 (77,248) (11,030) (64,507) (125,572) (117,709) (147,516) 54 29 (184) (2,057) 38,658 (32,260) Ì Ì 147 Í 21,128 Í 59,787 Í 27,673
The Year Ended March 31, 2004 Compared to the Year Ended March 31, 2003 For the year ended March 31, 2004, the net decrease in our cash and cash equivalents was Í32,260 million, or 54.0%, compared to an increase in cash and cash equivalents of Í38,658 million for the previous year due to an increase in net cash used in investing activities and net cash used in Ñnancing activities. Net cash provided by operating activities was Í179,948 million, an increase of Í12,580 million, or 7.5%, from Í167,368 million in the previous year due mainly to an increase in others, consisting mainly of payments from the EPCOs for the EPCOs' portion of expenses related to halting the Yunotani pumpedstorage hydroelectric power plant construction project, an increase in income before income taxes and minority interests and an increase, as opposed to a decrease in the previous year, in notes and accounts payable oÅset in part by a decrease in depreciation. Net cash used in investing activities was Í64,507 million, an increase of Í53,477 million, or 484.8%, from Í11,030 million in the previous year due mainly to a signiÑcant decrease in proceeds from sales of property, plant and equipment reÖecting the signiÑcant proceeds in the prior year from the sale of our assets related to the Hitachinaka thermal power plant construction project, oÅset in part by a decrease in payments for purchase of property, plant and equipment and a decrease in payments for investments and advances. Net cash used in Ñnancing activities was Í147,516 million, an increase of Í29,807 million, or 25.3%, from Í117,709 in the previous year due to an increase in repayment of long-term loans, relating mostly to repayment and prepayment of our long-term borrowings from the Government of Japan, increase in repayment of short-term loans and a decrease in proceeds from long-term loans, oÅset in part by proceeds from the issuance of stock to the Fund, proceeds from short-term loans and proceeds from the issuance of commercial paper. Cash and cash equivalents at the end of the year were Í27,673 million, a decrease of Í32,113 million from the beginning of the year. The Year Ended March 31, 2003 Compared to the Year Ended March 31, 2002 For the year ended March 31, 2003, our cash and cash equivalents increased Í38,658 million to Í59,787 million, or 183.0%, due mainly to a substantial decrease in cash used in investment activities. Net cash provided by operating activities was Í167,368 million, a decrease of Í33,340 million, or 16.6%, from Í200,708 million in the previous year. This was due mainly to a decrease in others, which in turn was due mainly to an impairment of investment securities and consumption tax payments that aÅected operating cash Öow in the prior year, and a decrease in depreciation oÅset in part by an increase in interest expenses due to payment of prepayment premiums in connection with prepaying our outstanding long-term debt. 41
Net cash used in investing activities was Í11,030 million, a decrease of Í66,217 million, or 85.7%, from Í77,248 million in the previous year. This was due mainly to the eÅect of an increase in proceeds from sales of property, plant and equipment related mainly to the proceeds from the sale of our assets related to the Hitachinaka thermal power plant construction project and a decrease in payments for purchase of property, plant and equipment oÅset in part by an increase in payment for investments and advances related mainly to purchases of investment securities. Net cash used in Ñnancing activities was Í117,709 million, a decrease of Í7,863 million, or 6.3%, from Í125,572 in the previous year due mainly to an increase in proceeds from long-term loans, consisting mostly of borrowings from private Ñnancial institutions, a decrease in repayment of short-term loans and a decrease in redemption of bonds oÅset in part by an increase in repayment of long-term loans and a decrease in proceeds from short-term loans. Market Risk We are exposed to market risks from changes in interest rates and foreign currency exchange rates, as well as changes in equity security prices. We use swaps and derivatives to manage a portion of these risks. We apply hedge accounting to these swaps and derivatives, and gains and losses on the swaps and derivatives are deferred until the maturity of the hedged transactions. A description of our accounting policies for derivative instruments is included in notes 2 and 14 to our consolidated Ñnancial statements included in this oÅering circular. We consider our hedge accounting to be one of our critical accounting policies, see ""Ì Critical Accounting Policies and Estimates''. We use swaps and derivatives for hedging purposes only, and counterparties for our swaps and derivatives are limited to creditworthy Ñnancial institutions. The following discussion summarizes the market risks we face and the swaps and derivatives we use to manage some of them. Our interest-bearing debt includes both Ñxed-rate and Öoating-rate debt. We manage our exposure to the risk of interest rate Öuctuations by entering into interest rate swap agreements with creditworthy Ñnancial institutions to convert, in eÅect, a portion of our Öoating-rate debt to Ñxed rate debt. Portions of our long-term debt and short-term loans are Öoating-rate debt. By utilizing interest rate swap agreements, we eÅectively converted all of this long-term Öoating-rate debt to Ñxed-rate debt. We apply hedge accounting to the interest rate swap agreements. We are subject to exchange rate risks with respect to our foreign currency denominated debt and our investments overseas in independent power producers, coal supply businesses and other entities. As of March 31, 2004, we had a total of Í64,391 million of foreign currency-denominated bonds and Í13,080 million of foreign currency-denominated borrowings outstanding. We hedge the exchange rate risks related to all of these bonds and borrowings with foreign currency swap arrangements for which we apply hedge accounting. We are also subject to exchange rate risks with respect to our foreign currency-denominated payables and receivables, as well as dividends from foreign aÇliates in which we have an interest. As the amounts of such payables or receivables subject to exchange rate risk are not material to our consolidated results of operations, however, we do not hedge such exchange rate risks with foreign currency forward contracts. We are also subject to market risk with respect to marketable investment securities we hold for which market prices are available. As of March 31, 2004, we held marketable equity securities with an aggregate market value of Í12,860 million, which included an unrealized gain of Í5,795 million over the purchase cost of the securities. Additionally, we held non-marketable securities for which no market price was available with a total carrying value of Í22,231 million as of March 31, 2004, of which Í17,084 million was unlisted equity securities of domestic companies and Í2,138 million was unlisted equity securities of foreign companies. In addition to the market risks described above, we are subject to the risk of Öuctuations in the market price for fuel commodities, mostly coal, used in our thermal power plants. Increases in coal prices will generally have the eÅect of increasing both our operating revenues and operating expenses and thus have a minimal eÅect on our operating income. However, large short-term Öuctuations in coal prices could adversely aÅect our results of operations. See ""Investment Considerations Ì Risks Related to Our Business Ì Our results of operations could be adversely aÅected by large short-term Öuctuations in coal prices''. Recent Accounting Pronouncement in Japan In August 2002, the Business Accounting Deliberation Council issued a new accounting standard under Japanese GAAP for impairment of long-lived assets that will become eÅective for Ñscal periods starting on or after April 1, 2005 (with optional earlier implementation available for Ñscal periods starting on or after 42
April 1, 2003). The new standard requires that tangible and intangible Ñxed assets be carried at cost less depreciation and be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Companies would be required to recognize an impairment loss in their income statements if certain indicators of asset impairment exist and the book value of an asset exceeds the undiscounted sum of future cash Öows of the asset. The standard states that impairment losses should be measured as the excess of the book value over the higher of (i) the fair market value of the asset net of disposition costs and (ii) the present value of future cash Öows arising from ongoing utilization of the asset and from disposal after asset use. The standard covers land, factories, buildings and other forms of property, plant and equipment as well as intangible assets. Fixed assets would be grouped at the lowest level for which there are identiÑable cash Öows that are independent of cash Öows of other groups of assets. Our power generation assets account for almost all of our tangible Ñxed assets. Because we have long-term electricity supply arrangements that provide for a return on each of our generation assets, we do not presently anticipate that any of our material tangible Ñxed assets will require impairment pursuant to the new standard in the short to medium term.
43
THE ELECTRICITY INDUSTRY IN JAPAN Demand for Electricity in Japan Historical Demand There has been a steady increase in the demand for electricity in Japan over the past several decades. Manufacturing and other industrial users consumed the majority of electricity in the 1950s, 60s and 70s, but by the 1980s, the commercial and residential sectors became the largest consumers of electricity in Japan. More widespread use of electric appliances and the increased size and sophistication of these appliances, as well as advances in the use of information technology in recent decades, have prompted signiÑcant increases in the demand for electricity in the commercial and residential sectors. Within the industrial sector, growth in electricity consumption declined as companies introduced energy-saving technologies in response to increased oil prices in the 1970s and as industrial growth shifted from energy-intensive industries such as steel and chemicals to less energy-intensive industries such as automobile and electronics manufacturing. Overall demand for electricity in Japan outpaced real GDP growth in the 1990s, growing at an average compound annual growth rate of 2.4% from the year ended March 31, 1991 to the year ended March 31, 2000. Over the short term, annual electricity demand Öuctuations are due mainly to diÅerences in weather conditions. In the Ñve years ended March 31, 2004, while the general trend has been a gradual increase in demand, demand fell slightly in the years ended March 31, 2002 and March 31, 2004, as compared with the respective previous years primarily due to milder weather conditions that discouraged the use of air conditioning and heating equipment. The following table provides information regarding demand for electricity in Japan for each of the Ñve years ended March 31, 2004, dividing the market into large-load customers (generally large manufacturers and large retail or oÇce buildings) for which rates have been deregulated since the year ended March 31, 2000, and customers other than large-load customers, for which rates remained regulated. The information regarding demand in this table shows electricity sold by the EPCOs and omits information regarding demand for electricity provided by PPSs and self-generators. For more information regarding these diÅerent electricity suppliers, see ""Ì The Structure of Japan's Electricity Industry''.
Historical Electricity Demand in Japan 2000 Electricity Increase amount (decrease)
Large-load customer demand(1) (under speciÑed contracts) ÏÏ Demand by customers other than large-load customers:(1) Household use ÏÏÏÏ Commercial use(2) Total ÏÏÏÏÏÏÏÏÏÏ
2001 Electricity Increase amount (decrease)
Year ended March 31, 2002 Electricity Increase amount (decrease) (100 million kWh)(%)
2003 Electricity Increase amount (decrease)
2004 Electricity Increase amount (decrease)
2,142
1.3%
2,198
2.6%
2,114
(3.8)%
2,157
2.0%
2,151
(0.3)%
2,482 3,545
3.0 2.3
2,546 3,635
2.6 2.5
2,545 3,582
(0.0) (1.5)
2,634 3,623
3.5 1.1
2,597 3,595
(1.4) (0.8)
8,169
2.2
8,379
2.6
8,241
(1.6)
8,415
2.1
8,343
(0.9)
Notes: (1) Large-load customer demand is deÑned as that of customers consuming 2 MW or more with voltages of 20,000 volts or more. (2) Consists of small and medium-sized manufacturers, small and medium-sized retailers, and others consuming less than 2 MW. Source: The Federation of Electric Power Companies of Japan, Electricity Demand; Agency for Natural Resources and Energy, ""Outline of Electricity Supply Plan for FY 2004''.
Outlook for Electricity Demand Each of Japan's ten EPCOs and two wholesale electric utilities, including us, is required by the EUIL to Ñle an electricity supply plan with the METI before the commencement of each Ñscal year. This plan 44
describes the outlook for electricity supply in the utility's supply region over the next ten years, construction plans for electricity generation and transmission facilities and related matters. Based on the plans submitted in 2004, the Agency for Natural Resources and Energy under the Ministry of Economy, Trade and Industry announced its ""Outline of Electricity Supply Plan for FY 2004'' on March 31, 2004. Based on the plans of the EPCOs, the Agency expects total annual electricity demand to grow from 832,000 million kWh in the year ended March 31, 2003 to 941,100 million kWh in the year ending March 31, 2014, representing an average compound annual growth rate of 1.1%. The following table provides information regarding projected demand for electricity in Japan for the years ending March 31, 2005, 2009 and 2014, based on the Agency's report. Due to additional deregulation in April 2004, the deÑnition of large-load customers is broadened, compared to the prior table, to include customers consuming 0.5 MW or more with voltages of 6,000 volts or more (generally medium-sized manufacturers, supermarkets and medium-sized oÇce buildings) for 2005 and customers consuming 0.05 MW or more with voltages of 6,000 volts or more (including some small manufacturers and smaller oÇce buildings) for 2009 and 2014. The shift in demand over time from customers other than large-load customers to large-load customers reÖects mainly these changes in the deÑnition of large-load customer. Similarly to the previous table, the information regarding demand in the report reÖects expected demand for electricity from the ten EPCOs and omits information regarding demand for electricity provided by PPSs and self-generators.
Outlook for Electricity Demand in Japan Year ending March 31, 2005 2009 2014 Increase Increase Annual growth Electricity (decrease) Electricity (decrease) Electricity Increase rate from 2003 amount from 2004 amount from 2005 amount from 2009 through 2014 (100 million kWh)(%) Large-load customer demand(1)(under speciÑed contracts) ÏÏÏ Demand by customers other than large-load customers(1): Household use ÏÏÏÏÏ Commercial use(2) ÏÏ TotalÏÏÏÏÏÏÏÏÏÏÏÏ
3,298
54.3%
5,445
65.1%
5,794
6.4%
2,666 2,443 8,407
2.1 (31.9) 0.8
2,836 529 8,810
6.4 (78.3) 4.8
3,052 565 9,411
7.6 6.8 6.8
1.5%(3) Ì 1.1(3)
Notes: (1) Large-load customer demand is deÑned as that of customers consuming 0.5 MW or more with voltages of 6,000 volts or more (except for The Okinawa Electric Power Company, Incorporated, for which the relevant threshold is 2 MW or more with voltages of 20,000 volts or more) for 2005 and 0.05 MW or more with voltages of 6,000 volts or more for 2009 and 2014 (except for The Okinawa Electric Power Company, Incorporated for which the relevant threshold is 2 MW or more with voltages of 20,000 volts or more). (2) Consists of commercial use, small customers, and others consuming less than 0.5 MW in the year ending March 31, 2005 and those consuming less than 0.05 MW thereafter. (3) Unusually warm weather had a signiÑcant impact on demand for electricity in the year ended March 31, 2003. These Ñgures represent the growth rate assuming normal weather conditions in that year. The average compound annual growth rates for the period from March 31, 2003 to March 31, 2014 become 1.3% for household use and 1.0% for total use without the adjustment. Source: Agency for Natural Resources and Energy, ""Outline of Electricity Supply Plan for FY 2004''.
The Agency expects peak load, or the highest amount of electricity consumed on any day in a given annual period, to grow by 11.5% from 172,640 MW in the year ending March 31, 2005 to 192,420 MW in the year ending March 31, 2014. As peak available capacity is expected to grow more slowly than peak load in the short to medium term, the reserve margin, which measures the diÅerence between peak load and peak available capacity as a percentage of peak load, is expected to drop to 10.2% in the year ending March 31, 2014 from 13.9% in the year ending March 31, 2005. The load factor, which compares average load to peak load, is a measure of power plant eÇciency. A high load factor indicates that electricity usage is relatively constant. A low load factor indicates that there is a 45
large diÅerence between periods of high demand and low demand. With a low load factor, generation capacity is idle during periods of low demand, imposing higher costs on the system. In Japan, the load factor is expected to remain stable at approximately 59% for the entire Japanese electricity industry, a Ñgure that is roughly equal to that of the United States and relatively low in comparison to 74.5% and 70.8% for the electricity industries of Germany and the United Kingdom, respectively. The following table shows the outlook for electricity capacity in Japan through 2014: Outlook for Electricity Capacity in Japan Year ending March 31, 2009 Increase Electricity (decrease) amount from 2005 (MW) (%) 180,690 4.7% 198,290 0.8 9.7% (30.2) 58.9% 0.2
2005 Electricity amount Peak load ÏÏÏÏÏÏÏÏÏÏÏÏ Peak capacity(1) ÏÏÏÏÏÏÏ Reserve margin ÏÏÏÏÏÏÏ Load factor(2) ÏÏÏÏÏÏÏÏÏ
172,640 196,700 13.9% 58.8%
Increase (decrease) from 2004 5.3% 4.1 (8.6) (3.9)
2014 Electricity amount 192,420 212,080 10.2% 59.1%
Increase from 2009 6.5% 7.0 5.2 0.3
Notes: (1) Peak capacity represents actual usable electricity generation capacity during the relevant year, excluding power plants that are expected to temporarily suspend operations for maintenance or other reasons and also excluding electric power consumed at power plants. (2) Load factor is the ratio of average load to peak load during the year. Source: Agency for Natural Resources and Energy, ""Outline of Electricity Supply Plan for FY 2004''.
In June 2004, the Subcommittee on Energy Demand of the Advisory Committee for Natural Resources and Energy issued its preliminary report on the outlook for electricity demand through the year ending March 31, 2031. The Subcommittee projected that, in a base case scenario assuming no major changes in electricity consumption patterns, demand for electricity would grow at a compound annual growth rate of about 0.9% over the period from the year ended March 31, 2001 to the year ending March 31, 2031. Under an energy-saving scenario, in which the Subcommittee assumed a decrease in demand for electricity due to the introduction of more energy-saving devices and products utilizing new information technology, the Subcommittee projected a compound annual growth rate of about 0.3%, with demand for electricity in Japan peaking in the year 2025 and declining thereafter. The Structure of Japan's Electricity Industry Japan's electricity industry consists of: ‚
Ten regional general electric utilities, or EPCOs;
‚
Two wholesale electric utilities, J-POWER and the Japan Atomic Power Company, Ltd.;
‚
Wholesale suppliers, including public utilities, joint venture utilities and independent power producers, or IPPs; and
‚
Power producers and suppliers, or PPSs.
46
In addition, there are special electric utilities and self-generators. For further information, see ""Regulation Ì Electricity Suppliers''. The following diagram shows the structure of Japan's electricity industry as of April 1, 2004: (As of April 1, 2004)
Power Producers and Suppliers (PPSs) (13) Power Generation
Supply electricity to large-load customers.
General Electric Utilities (EPCOs) (10) Supply electricity to general retail customers. Generate and buy electricity from wholesale electric utilities and wholesale suppliers.
Wholesale Suppliers
Wholesale Electric Utilities (2)
Public utilities, Joint venture utilities (52)
. J-POWER . Japan Atomic Power Have total output capacity of more than 2,000 MW and supply electricity to EPCOs.
Transmission
Independent Power Producers (IPPs) (30) Wholesalers other than EPCOs
Self-Generators
Special Electric Utilities (6)
Self-consumption
Specific customers within designated locations
Commissioned Transmission Retail-Commissioned Transmission
Distribution
Last Resort Supply Large-Load Customers Consume 0.5MW or more with voltages of 6,000 volts or more.
Customers
Note: Figures in parentheses represent the number of companies in each category as of March 31, 2004.
The following table illustrates the generation capacity of various entities in the Japanese electricity industry as of March 31, 2004. Statistics for the electricity industry in Japan are typically reported on a nonconsolidated basis. The Ñgures for total generation capacity and electricity sales volume for electricity companies in Japan included in this description of the electricity industry in Japan are based on the nonconsolidated Ñgures of the relevant electricity companies unless otherwise indicated. Electricity Generation Capacity of Japanese Electricity Companies
Source
EPCOs
Hydroelectric
J-POWER
33,767 (1,159) Thermal(3)ÏÏÏ 121,312 (178) Nuclear ÏÏÏÏÏ 43,125 (14) Others(4) ÏÏÏÏ 4 (5) Total ÏÏÏ 198,208
8,551 (59) 7,825 (8) Ì Ì Ì Ì 16,375
(1,356)
(67)
As of March 31, 2004(1) Public Japan utilities Atomic and Power others IPPs(1) PPSs(2) (MW) (number of power plants) Ì 2,878 Ì 37 Ì (365) Ì (2) Ì 10,923 4,407 3,839 Ì (17) (28) (49) 2,617 Ì Ì Ì (2) Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì Ì 2,617 13,801 4,407 3,876 (2)
(382)
28
(51)
Special electric utilities
Total
1 (2) 253 (4) Ì Ì Ì Ì 254
45,234 (1,587) 148,559 (284) 45,742 (16) 4 (5) 239,538
(6)
(1,892)
Notes: (1) Figures for the EPCOs, J-POWER, Japan Atomic Power, public utilities and others, PPSs and special electric utilities are from the Ministry of Economy, Trade and Industry. Figures for IPPs are from the Japan Electric Power
47
Survey Committee. Figures for total generation capacity for electricity companies in the above table are based on the non-consolidated Ñgures of the relevant electricity companies. (2) Figures for PPSs include capacity controlled by self-generators but used to supply electricity to PPSs. (3) Figures for thermal include coal-, oil- and gas-Ñred power plants as well as geothermal power plants. (4) Others include fuel cell and wind power generation capacity.
General Electric Utilities (EPCOs) Nine EPCOs were established in Japan in 1951. These consisted of Hokkaido Electric Power Company, Tohoku Electric Power Company, The Tokyo Electric Power Company, Chubu Electric Power Company, Hokuriku Electric Power Company, The Kansai Electric Power Company, The Chugoku Electric Power Company, Shikoku Electric Power Company and Kyushu Electric Power Company. With the return of Okinawa to Japan from the United States in 1972, a tenth EPCO, The Okinawa Electric Power Company, Incorporated was established. Under the EUIL, each of the ten EPCOs serves as the main retail supplier and supplier of last resort within its own service area and operates power plants, transmission and distribution networks and substations. Until the partial deregulation of the retail electricity market in March 2000, the EPCOs held monopolies over the retail electricity markets within their respective service areas. As of March 31, 2004, the ten EPCOs collectively had 198,208 MW of generation capacity. The EPCOs collectively recorded Í15.0 trillion in sales for the year ended March 31, 2004. Under the EUIL, the METI has regulatory authority over the EPCOs. The following map shows the service areas and the location of headquarter oÇces of the ten EPCOs:
Hokkaido Electric Power Sapporo
Tohoku Electric Power Sendai
Hokuriku Electric Power Toyama
Tokyo
Chugoku Electric Power
Nagoya Osaka
Hiroshima Takamatsu Fukuoka
Shikoku Electric Power Kyushu Electric Power
Kansai Electric Power
Tokyo Electric Power
Chubu Electric Power
Urasoe
Okinawa Electric Power
An amendment to the EUIL that became eÅective in March 2000 opened retail competition to largeload customers, originally deÑned as customers that consume 2 MW or more and which are connected to the electricity network through transmission lines with voltages of 20,000 volts or more. As of April 1, 2004, this customer class was redeÑned to include customers that consume 0.5 MW or more with voltages of 6,000 volts or more. As of April 1, 2005, retail competition will be extended to customers that consume 0.05 MW or more with voltages of 6,000 volts or more. The Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy has stated that it will be appropriate to begin considering full retail deregulation in or around April 2007 subject to an examination of the eÅectiveness of prior deregulation. See ""Ì Electricity Industry Deregulation in Japan'' with respect to future retail electricity deregulation.
48
As a result of the March 2000 amendment, PPSs can serve large-load customers, and the EPCOs themselves can supply power to large-load customers outside their service areas. The EPCOs generally source electricity from their own power plants located inside or outside their service areas, power plants of other EPCOs and wholesale electric utilities such as us.
Wholesale Electric Utilities Wholesale electric utilities are electricity companies which sell their output to EPCOs and have a generation capacity of more than 2,000 MW. There are currently two wholesale electric utilities: us and the Japan Atomic Power Company Ltd. The latter was established by us and nine of the EPCOs to promote the development and use of nuclear power and it currently operates two nuclear power plants. As of March 31, 2004, wholesale electric utilities had a total of 18,992 MW of generation capacity.
Power Producers and Suppliers (PPSs) Since an amendment to the EUIL introduced retail competition to the Japanese electricity industry in March 2000, PPSs have been selling electricity to large-load customers. Most of the PPSs in Japan have been established by large trading companies, gas utilities and large industrial manufacturers. The PPSs generally purchase electricity from other suppliers, but some of them also have their own power plants and resell the electricity they generate to their customers. The individual generation capacities of PPSs range from 47 MW to 1,234 MW, with a majority having generation capacities less than 300 MW. PPSs are classiÑed under the EUIL as speciÑed-scale electric utilities. See ""Regulation Ì Regulatory Outline''. Most PPSs supply electricity to large buildings, department stores and hotels in Japan's big cities. PPSs use the transmission and distribution facilities of the EPCOs to supply electricity to their customers. As of March 31, 2004, there were ten PPSs operating in Japan, with a combined generation capacity of 3,876 MW.
Wholesale Suppliers Other entities also supply wholesale electricity in Japan. They include IPPs, public utilities and joint venture utilities which engage in wholesale electricity supply to the EPCOs, but have generation capacities lower than those of wholesale electric utilities. All of these entities are classiÑed under the EUIL as wholesale suppliers. They are not subject to most of the licensing, approval, notiÑcation and other requirements imposed on other participants in the Japanese electricity industry. See ""Regulation Ì Regulatory Outline''. IPPs emerged after a 1995 amendment to the EUIL allowed companies to bid for long-term electricity supply contracts with the EPCOs. Several IPPs have been awarded projects since the Ñrst bids were solicited in 1996, and many of them have started operations. IPPs have typically been established by large industrial companies. The generation capacities of the IPPs range from 2.4 MW to 1,318 MW, with a majority having generation capacities less than 200 MW. There have been no signiÑcant IPP contracts awarded in Japan since the year ended March 31, 2000 because the EPCOs have not solicited any signiÑcant new bids. New entrants in the electricity market now typically become PPSs. As of March 31, 2004, there were 28 IPPs operating in Japan, with a combined generation capacity of 4,407 MW. Various prefectures and cities in Japan own public utilities that generate electricity for sale to EPCOs for resale to the local community. Most of the public utilities were established in the 1950s and 1960s. The generation capacities of these public utilities range from 5 MW to 354 MW, but most of them have generation capacities lower than 100 MW. As of March 31, 2004, there were 33 public utilities operating in Japan, with a combined generation capacity of 2,565 MW. Some of the EPCOs have engaged in joint venture projects with industrial companies and others to establish additional sources of wholesale electricity for the EPCOs. Most of these joint venture utilities were established in the 1960s and 1970s. The generation capacities of these joint venture utilities range from 7.9 MW to 2,000 MW, with a majority having generation capacities between 200 MW and 700 MW. As of March 31, 2004, there were 19 such joint venture utilities operating in Japan with a combined generation capacity of 11,236 MW. Such public utilities and joint venture utilities are treated as wholesale electric utilities if certain conditions are met under the EUIL. See ""Regulation Ì Electricity Suppliers''. 49
Self-Generators In addition to the suppliers described above, self-generators generate electricity for their own consumption as well as, in some cases, for supply to PPSs. Self-generators consist mainly of large industrial companies. As of March 31, 2004, there were 3,135 self-generator operated power plants with generation capacity of 1 MW or more in Japan, with a collective generation capacity of 36,645 MW, including capacity used to supply electricity to PPSs. Because the Ministry of Economy, Trade and Industry classiÑes IPPs together with self-generators for statistical record-keeping purposes, this Ñgure also includes the capacity of IPPs.
Transmission The high-voltage transmission lines in Japan's electricity grid are mostly owned and operated by the EPCOs and by us. Participants in the nation's electricity industry supply electricity to each other to stabilize supplies and for eÇciency. The EPCOs can operate facilities and develop power plants beyond their own service areas and are required to provide each other with electricity to sustain services following accidents or outages or to cover peaks in demand. We and the EPCOs, with the exception of The Okinawa Electric Power Company, are members of the Central Electric Power Council. There are also three regional electricity cooperation councils, and we are a member of each of these three councils. These councils are responsible for overseeing and coordinating broadarea electricity transmission and distribution. The frequency of alternating current electricity used in Japan is split between 50Hz used in Eastern Japan, including Tokyo, and 60Hz used in Western Japan. In 1965, the 50Hz and 60Hz electricity supply areas were connected for the Ñrst time by our Sakuma Frequency Converter Station. In December 1977, The Tokyo Electric Power Company completed construction of another converter station to further facilitate the provision of electricity between the 50Hz and 60Hz areas. We constructed extra high-voltage transmission lines that connect the island of Honshu to the islands of Hokkaido, Shikoku and Kyushu. These transmission lines connect Japan's four main islands, and in combination with our other transmission lines and the transmission lines owned by the nine EPCOs, these lines complete a transmission and distribution network linking almost all of Japan's electricity generation capacity with almost all of its electricity customers.
Rates System The rates and fees charged by the EPCOs, wholesale electric utilities and IPPs to supply electricity to their customers are provided in the terms and conditions of electricity supply that are subject to regulation by the EUIL. For information regarding the regulation of the terms and conditions of our electricity supply by the METI, see ""Regulation Ì Wholesale Electric Utilities Ì Regulation of Terms and Conditions of Wholesale Electricity Supply''. PPSs are free from all regulation regarding rates.
EPCOs General Customers Rate The EUIL requires that the retail rates charged to customers other than large-load customers be calculated on a fair cost plus fair return on capital basis. The law stipulates the manner of calculation and the allocation of cost and return on capital. The law requires the EPCOs to calculate their costs pursuant to a comprehensive cost system, which means costs used as a basis for calculating pricing include the assumed operating expenses, taxes and duties for the EPCOs as a whole. Return on capital is calculated by multiplying the aggregate cost of Ñxed assets used for electricity supply, construction in progress, certain research and development and deferred assets and the book value of working capital by percentages prescribed in regulations promulgated under the EUIL. The calculated total cost and return on capital is allocated to general customers in the relevant supply area. 50
Selective Service Rate As a result of the introduction of ""selective terms and conditions'' in December 1995 as part of the ongoing deregulation of the Japanese electricity industry (see ""Ì Electricity Industry Deregulation in Japan Ì Amendments to the Electricity Utilities Industry Law EÅective December 1995 Ì EPCOs Selective Terms and Conditions''), EPCOs are permitted to establish diverse rate schedules to provide, for example, discounts for weekend use. This enables the EPCOs to better match rate schedules with general electricity usage patterns. Supplier of Last Resort Terms and Conditions To help insure that large-load customers have the choice of purchasing electricity from PPSs, the EUIL requires each EPCO to set and Ñle with the METI ""supplier of last resort terms and conditions'' for large-load customers. Under these terms and conditions, EPCOs must provide electricity in the event PPSs are unable to meet the demand from their large-load customers. Retail Electricity Rate Trends In recent years, the EPCOs have been reducing their rates in response to pressure in the deregulated environment. In October 2000, the EPCOs lowered their general customer rates by an average of 5.4%. Between April and October 2002, they lowered them further by between 5.2% and 7.1%. The Tokyo Electric Power Company, Chubu Electric Power Company and Tohoku Electric Power Company have announced further rate reductions to take eÅect in our current Ñscal year. Deregulated Rate Since March 2000, the EPCOs have been able to establish selective rates for speciÑc large-load customers without being subject to any Ñling or approval requirement under the EUIL. See ""Ì Electricity Industry Deregulation in Japan Ì Amendments to the Electricity Utilities Industry Law EÅective March 2000 Ì Partial Deregulation of Electricity Retailing''. Wholesale Electric Utilities General The EUIL stipulates that fees for wholesale electricity supply be calculated on a fair cost plus fair return on capital basis. Unlike the regulation applicable to the retail rates of the EPCOs, the regulations applicable to wholesale electricity fees do not provide any speciÑc method for allocating cost among customers. Our Fees Our fees are calculated on a fair cost plus fair return on capital basis. Our fee system diÅers from the comprehensive cost system of the EPCOs, however, in that we separately compute the fees for each power plant. Under this approach, we reÖect the cost characteristics of each power plant in our fees. For further discussion of our fees, see ""Management's Discussion and Analysis of Financial Condition and Results of Operations Ì Factors AÅecting Our Results of Operations Ì Operating Revenues Ì Electric Power Segment Ì Electricity Fees''. Under the EUIL, wholesale electric utilities are required to Ñle notiÑcations with the METI with respect to setting and changing the fees they charge for electricity. Under the Law Partially Amending the Electricity Utilities Industry Law and the Gas Utilities Industry Law, while we are not required to Ñle such a notiÑcation with respect to our fees that were approved by the METI prior to the repeal of the J-POWER Law in October 2003, we are required to provide notiÑcation of any changes in those fees. In determining such changes we are permitted to calculate fair cost and fair return on capital in the manner in which our fees had previously been approved by the METI under the J-POWER Law, subject to the conditions that, as of the date of repeal of such law, (i) we had electricity supply agreements with the relevant EPCOs, and (ii) the terms and conditions of our wholesale electricity supply pursuant to those agreements had already been approved by the METI under the J-POWER Law. For the terms and conditions of wholesale electricity 51
supply which do not meet the requirements of either (i) or (ii) above, for example, with respect to our anticipated wholesale supply of electricity generated at the Isogo New No. 2 thermal power plant and the Oma nuclear power plant, we will be required to calculate our fees in accordance with the rules promulgated under the EUIL relating to calculation of fees for wholesale electricity. Such rules do not prevent us from calculating our fees on the basis of each power plant as approved by the METI under the J-POWER Law. Accordingly, we anticipate that we will be able to continue to set and change our fees in a manner substantially similar to that applied by us prior to the repeal of the J-POWER Law. IPPs and PPSs The manner in which IPPs and PPSs set their fees is not regulated. The fees charged by IPPs to supply electricity to the EPCOs are established pursuant to a bidding system. The fees charged by PPSs to supply electricity to large-load customers are established pursuant to bids or negotiated contracts. The fees charged by IPPs and PPSs are not generally made public and are subject to change pursuant to agreements with their customers. Transmission Rates and Fees Transmission by the EPCOs Electricity cannot be stored, but it can be moved over electric transmission lines from the place of generation to another place to supply a need for electricity. ""Commissioned transmission'' refers to the electricity supply process by which an entity that has received electricity at one location supplies the same volume of electricity at a diÅerent location. Commissioned transmission services may be provided by an EPCO or by more than one EPCO, if required, to any other entity, including another EPCO. At present, PPSs are not permitted to own transmission lines under the EUIL and need to receive commissioned transmission services from EPCOs in order to supply electricity to their customers. This is referred to as ""retail-commissioned transmission''. When a PPS supplies electricity using an EPCO's transmission lines to a customer located in that EPCO's supply area, and the volume of electricity supplied by the PPS is less than the volume required by the customer's demands, the EPCO must supply the shortfall volume at a rate prescribed in the EUIL, subject to a prescribed volume limitation. If the electricity required to be supplied by the EPCO to the PPS to meet such shortfall is in excess of the volume limitation due to an accident, the EPCO will supply the necessary volume of electricity, but at a higher rate. These rates are subject to the regulations promulgated under the EUIL. The rates for commissioned transmission and retail-commissioned transmission must be notiÑed to the METI and are subject to the METI's power to issue an order to change. The rate calculations are based on the assumption that burdens are fair to each EPCO and PPS and are calculated on a fair cost plus fair return on capital basis. Transmission by Others, Including Us We own transmission facilities, such as trunk lines, substations and converter stations. The EPCOs pay us Ñxed fees to use our transmission facilities, and these fees are calculated on a fair cost plus fair return on capital basis. For a further explanation of our transmission fees, see ""Management's Discussion and Analysis of Financial Condition and Results of Operations Ì Factors AÅecting Our Results of Operations Ì Operating Revenues Ì Electric Power Segment Ì Electricity Fees''. Electricity Industry Deregulation in Japan Amendments to the Electricity Utilities Industry Law EÅective December 1995 In April 1995, the EUIL was amended to achieve two main goals. The Ñrst was to cut costs and reduce electricity rates by introducing competitive principles. The second was to have entities other than the EPCOs generate electricity to help meet future growth in demand. The amended law came into eÅect in December 1995. 52
Introduction of Wholesale Deregulation The 1995 amendments provided a market opportunity for IPPs by eliminating the licensing requirement for wholesale suppliers with a generation capacity of 2,000 MW or less. Moreover, these companies did not need to seek approval for the rates at which they sell electricity to the EPCOs. These changes integrated IPPs into the electricity industry, enabling them to provide wholesale electricity to EPCOs without licensing or approval requirements. Since 1996, the EPCOs have sought electricity supply from IPPs through bidding procedures for new power plants. Since March 31, 2000, however, the EPCOs have not solicited any signiÑcant new bids from IPPs, and new entrants in the Japanese electricity industry since that time have generally been PPSs. EPCOs Selective Terms and Conditions The 1995 amendments to the EUIL also introduced ""selective terms and conditions'' for EPCOs. Selective terms and conditions were designed to encourage EPCOs to enhance their management eÇciency and thereby promote competition among EPCOs. Selective terms and conditions may, for example, provide diÅering rate schedules by season and time of day or may oÅer discounts at night and on weekends and holidays. EPCOs are permitted to establish selective terms and conditions for their electricity supply, which are diÅerent from the terms and conditions approved by the METI, provided that such selective terms and conditions will contribute to the eÇcient use of the EPCOs' facilities for general electric power supply or will otherwise enhance its management eÇciency. Customers may now choose whether or not to receive electricity supply based upon such selective terms and conditions. EPCOs must notify the METI of the establishment of and any amendment to selective terms and conditions. The METI may order the relevant EPCO to change any proposed selective terms and conditions if they are prejudicial to general customers, are not clearly stipulated, or lead to discriminatory treatment of any person. Special Electric Utility Business The 1995 amendments to the EUIL also provided for the introduction of special electric utilities to the Japanese electricity industry. A special electric utility is an entity that can supply electricity directly to designated locations without using the transmission lines of any other supplier. Electricity supplied by special electric utilities is used in manufacturing plants, oÇces and other local facilities. The special electric utility system was designed to facilitate retail electricity supply from utilities other than the EPCOs by subjecting such utilities to less stringent regulations. For instance, some special electric utilities engage in cogeneration activities, providing both heat and electricity to industrial customers in local areas. As of March 31, 2004, Ñve entities were licensed under this system. Amendments to the Electricity Utilities Industry Law EÅective March 2000 In January 1999, the Electricity Utility Industry Council, a consultative body of the Minister of the Ministry of International Trade and Industry (the predecessor to the METI), issued a report recommending partial deregulation of the retail electricity market beginning in 2000. In response to this report, in May 1999, the National Diet of Japan, or the Diet, passed a bill amending the EUIL. The amendment went into eÅect in March 2000. Partial Deregulation of Electricity Retailing The retail electricity market was deregulated for large-load customers consuming 2 MW or more supplied at 20,000 volts or more, such as large factories, oÇce buildings, hotels and department stores. These customers accounted for approximately 30% of total electricity demand. This change, in principle, eliminated barriers to entry and eliminated rate regulation for such large-load customers. Suppliers, including both EPCOs and PPSs, negotiate rates with customers and the parties may determine the rates themselves. As of March 31, 2004, 13 companies have applied to become PPSs, of which ten have begun supplying electricity. On the demand side, more central and local government authorities have started to purchase electricity through competitive bid processes. In August 2000, immediately after its administrative restructuring, the Ministry of International Trade and Industry (now the Ministry of Economy, Trade and Industry) began holding bids for its electricity needs. Various other government organizations followed suit, including 53
city and prefectural authorities, and in the year ended March 31, 2004, central and local governments held a large number of bids for electricity supply. Many new market participants waived participation in these bids because they lacked supply capacity or could not provide electricity economically. Local electricity companies were thus sole bidders in almost half of the bid processes. As new market participants increase their capacity, however, they will likely bid more aggressively and be able to secure more customers. Amendments to the Electricity Utilities Industry Law EÅective December 2003 and April 2005 The Electricity Industry Committee of the Advisory Committee for Natural Resources and Energy, or the Committee, compiled a framework for restructuring the industry in December 2002, and after Ñelding public comments, submitted its formal recommendations to the METI in February 2003. In June 2003, the Diet passed the latest amendment to the EUIL based on the Committee's report and repealed the J-POWER Law. The following is a brief description of the deregulation of the electricity industry contained in the latest amendment to the EUIL, a part of which became eÅective on December 17, 2003 and the remainder of which will become eÅective on April 1, 2005. Retail Electricity Supply to Large-Load Customers The amended EUIL gives the METI the power to engage in further deregulation of the retail electricity industry through the issuance of ministerial ordinances. In a ministerial ordinance amended on March 16, 2004, the METI expanded the scope of large-load customers to whom PPSs may supply electricity, starting April 1, 2004, to include customers consuming 0.5 MW or more, supplied at 6,000 volts or more. EÅective April 1, 2005, the scope will be expanded further to include customers consuming 0.05 MW or more with voltages of 6,000 volts or more. These changes will increase the scope of the deregulated market from approximately 30% of total demand to approximately 60% of total demand. Reform of Transmission Rate Systems A key issue in industry structural reform is establishing a system to ensure fair access to transmission lines to allow for a more eÇcient and competitive electricity generation and supply infrastructure. As restructuring expands, it has become important to increase neutrality and transparency in transmission and network operation management in order to guarantee fair competition between PPSs and the EPCOs. At the same time, network operation management plays a central role in stabilizing electricity supplies, so it is essential to preserve this element. Under the amended EUIL, the EPCOs will be required to put legal guarantees regarding Chinese walls in place by April 2005 and establish separate accounting systems for generation and transmission operations (which they currently voluntarily maintain). The amended EUIL also provides that a neutral entity having power to formulate and monitor network management rules may be designated by the METI. Such a neutral entity, the Electric Power System Council of Japan, was so designated in June 2004. When an entity supplies electricity generated in the supply area of one EPCO (""EPCO A'') to a customer located in the supply area of another EPCO (""EPCO B''), that entity must receive commissioned transmission services from EPCO A and retail-commissioned transmission services from EPCO B, unless the entity has its own transmission lines in the relevant service areas. In addition, if EPCO B's service area is not adjacent to EPCO A's service area, the supplier needs to receive commissioned transmission services from the EPCOs situated between EPCO A and EPCO B. In these cases, each of the EPCOs providing commissioned transmission services or retail-commissioned transmission services charged cumulative rates to the supplier. The Committee's reports proposed to terminate such cumulative charging of rates, known as ""pancaking'', in order to promote electricity supply across diÅerent EPCO service areas to make it possible to supply electricity economically from one region to another. Following the termination of cumulative charging of rates by EPCOs, only the EPCO that provides electricity to the end customer (EPCO B in the above example) will charge a transmission rate to the supplier, and part of the rate paid to the EPCO will be distributed by it to the other EPCOs providing commissioned transmission services.
54
Establishment of Transmission and Distribution Support Organization The Committee's reports stated that in order to expand the scope of deregulation in the retail electricity supply market to make a wider range of electricity sources available and ensure the stable supply of electricity, it will be necessary to secure fairness and transparency in the transmission and distribution of electricity. To achieve these objectives, the Committee has found it appropriate to establish a neutral nonproÑt organization to establish rules applicable to the transmission and distribution of electricity, supervise compliance with such rules by market participants and resolve disputes among market participants. The Electric Power System Council of Japan was designated as such organization on June 15, 2004. Under the amended EUIL, it has created rules governing systems access and operations and the formation of distribution facilities. It will also arbitrate disputes and disclose information on transmission activities. Establishment of Wholesale Electricity Exchange The Committee's reports also proposed that a wholesale electricity exchange be established for the purpose of assisting electricity suppliers in managing the risk associated with the purchase and sale of electricity. It was the Committee's belief that the wholesale electricity exchange should be established as a neutral, non-proÑt and self-regulated corporation that would be open to a wide range of suppliers of electricity. The Committee has also stated that trading on the exchange should be executed on the basis of actual demand. As part of the structural reforms, nine of the EPCOs and nine PPSs have established the Japan Electric Power Exchange, which is scheduled to commence electricity trading on April 1, 2005 and will operate objectively through open membership and fair organization. We have invested in, and became a member of, the exchange. The exchange will provide a price index to facilitate investment decision making and will enable spot transactions and forward transactions. The EPCOs are expected to make a portion of their generation capacity available to the exchange to ensure transaction liquidity. We also plan to sell electricity on the exchange. The Electricity Industry Committee report issued in 2003 states that we are also expected to play an important role in the wholesale electricity exchange.
55
The following diagram illustrates the timeline for deregulation of the retail electricity market in Japan: Deregulation of the Retail Electricity Market: Timeline
March 2000 Deregulated sector
April 2005
April 2004 Deregulated sector
Full-scale deregulation may begin to be considered in or around April 2007
Deregulated sector
Extra high voltage for industry use (above 2 MW): large scale plants
Extra high voltage for industry use (above 2 MW): large scale plants
Extra high voltage for industry use (above 2 MW): large scale plants
Extra high voltage for commercial use (above 2 MW): department stores, office buildings Electricity volume: 26%
Extra high voltage for commercial use (above 2 MW): department stores, office buildings
Extra high voltage for commercial use (above 2 MW): department stores, office buildings
High voltage for commercial use (between 0.05 and 2 MW): supermarkets, mid- to smallsized buildings
High voltage for commercial use (above 0.5 MW): supermarkets, mid- to smallsized buildings
High voltage for commercial use (above 0.05 MW): supermarkets, mid- to smallsized buildings
High voltage for industry use (between 0.05 and 2 MW): mid- to small-sized plants
High voltage for industry use (above 0.5 MW): mid-sized plants
High voltage for industry use (above 0.05 MW): mid- to small-sized plants
Electricity volume: 38%
Electricity volume: 40%
Electricity volume: 63%
High voltage for commercial use (below 0.5 MW) High voltage for industry use (below 0.5 MW): small-sized plants Electricity volume: 23%
Low voltage (below 0.05 MW): small-sized plants, convenience stores
Low voltage (below 0.05 MW): small-sized plants, convenience stores
Low voltage (below 0.05 MW): small-sized plants, convenience stores
Electricity volume: 5%
Electricity volume: 5%
Electricity volume: 5%
Lighting: households
Lighting: households
Lighting: households
Electricity volume: 31%
Electricity volume: 31%
Electricity volume: 31%
Notes: (1) Electricity volume Ñgures reÖect the percentage of total electricity demand represented by each sector of customers as of March 31, 2002. (2) Extra-high voltage refers to voltages of 20,000 volts or more. High-voltage refers to voltages less than 20,000 volts and 6,000 volts or more. Low voltage refers to voltages below 6,000 volts. (3) Between March 2000 and March 2004, the class of deregulated customers for The Okinawa Electric Power Company consisted of customers consuming 20 MW or more with voltages of 60,000 volts or more. The current class of deregulated customers for The Okinawa Electric Power Company consists of customers consuming 2 MW or more with voltages of 20,000 volts or more.
General Description of Power Plant Types Because electricity generally cannot be stored and demand is constantly changing, the supply of electricity must be constantly adjusted. Electricity generation sources can be divided into three types: base sources, peak sources and middle sources. Among various types of power generation, those with a constant output level are called base sources, and those that can promptly respond to changes in demand and provide 56
electricity to meet peak demand are called peak sources. Middle sources have characteristics of both base sources and peak sources. The following table illustrates some basic characteristics of various types of power plants: Type of Power Plant Thermal: Oil
Characteristics ‚ ‚ ‚ ‚
Superior in meeting changes in load Relatively low construction costs High fuel costs Generally used as peak source
Coal
‚ Inferior in meeting changes in load relative to other thermal ‚ Relatively high construction costs as harbor construction and anti-pollution related capital investment is necessary ‚ Low fuel costs ‚ Used as base source
LiqueÑed Natural Gas
‚ Superior in meeting changes in load ‚ Relatively high construction cost in cases where there is no existing infrastructure ‚ Fuel costs comparable to oil, but cost eÇciency is increasing ‚ Generally used as middle source
Hydroelectric: Conventional(1) and Pumped-Storage
Natural Flow
Nuclear:
New energy: Wind and Photovoltaic
‚ Most eÇcient in meeting changes in load ‚ No fuel costs ‚ Pumped-storage hydroelectric power plants use excess electricity during low demand periods to pump additional water behind the dam to generate more electricity during periods of peak demand ‚ Used as peak source ‚ ‚ ‚ ‚
No water storage capacity; must run constantly No fuel costs Amount of electricity supplied at a given time depends entirely on stream Öow Used as base source
‚ ‚ ‚ ‚
Relatively high construction costs Low fuel costs DiÇcult to turn on and oÅ quickly Used as base source
‚ ‚ ‚ ‚
Not easily adaptable to changes in load as they are low in energy density Decrease burden on environment Development supported by the government By Japanese law, EPCOs, PPSs and special electric utilities are required to obtain a certain amount of electricity from renewable energy sources
Note: (1) Conventional hydroelectric power plants consist of reservoir-type and natural Öow with dam-type hydroelectric power plants.
57
General Description of Transmission Facilities Transmission lines are generally divided into backbone lines and area supply lines according to the levels of voltage. Almost all transmission lines are alternating-current based, and there are only two direct current transmission lines in Japan, each of which we constructed and own, one of which we own jointly with an EPCO. AC/DC converter stations convert electricity between alternating current and direct current. AC/ DC converter stations are located at both ends of each of the two existing direct current transmission lines. Frequency converter stations link areas with diÅering frequencies, for example, Eastern Japan's 50Hz area and Western Japan's 60Hz area. There are only two frequency converter stations in Japan, one owned and operated by us and the other by The Tokyo Electric Power Company.
58
BUSINESS Introduction As the largest supplier of wholesale electricity in Japan, we develop and operate power plants and transmission facilities throughout the country. To date, we have been a government-controlled entity primarily engaged in the wholesale supply and transmission of electricity. Our main customers are Japan's ten EPCOs, the regional general electric utilities which supply electricity to general retail customers. Our core business consists of supplying electricity generated at our coal-Ñred thermal and hydroelectric power plants and providing transmission facilities, in both cases through long-term arrangements pursuant to which our fees are calculated on a fair cost plus fair return on capital basis. As of March 31, 2004, these activities and the generation activities of one coal-Ñred thermal power plant owned by a consolidated subsidiary accounted for approximately 92% of our consolidated operating revenues. We are the leading supplier of coal-Ñred thermal power in Japan, with eight power plants. We are also one of the leading suppliers of hydroelectric power, with 59 power plants. Our total generation capacity of 16,509 MW as of March 31, 2004 represented approximately 7% of the total generation capacity used by the EPCOs. We also own transmission facilities, including 2,404 kilometers of transmission lines, some of which connect the island of Honshu with the islands of Kyushu, Shikoku and Hokkaido. Our privatization resulting from the oÅerings will occur in the context of increasing deregulation in the electricity industry in Japan. Currently, deregulation of the retail electricity market is proceeding incrementally for large-load customers, and in or around April 2007, a consultative body to the METI will begin to consider whether the entire retail electricity market should be opened to full competition. In response to increased pricing pressure resulting from deregulation, we have been implementing measures to increase our eÇciency and enhance our proÑtability. We are also focused on leveraging our knowledge and experience in the electricity industry to expand our other businesses. As a result, we have been seizing new business opportunities, making investments in IPPs and companies that supply electricity to PPSs. Additionally, we have been making investments in overseas power generation businesses and domestic clean energy source businesses such as wind power. History We were established by the Government of Japan as a joint stock corporation in 1952 under the J-POWER Law to promote large-scale power plant development, to increase Japan's electricity supply and to improve transmission and conversion facilities. We began with an immediate focus on large-scale hydroelectric power generation, bringing the 350 MW Sakuma Power Plant online in 1956. This was soon followed by the 380 MW Tagokura and the 360 MW Okutadami hydroelectric power plants. In the 1960s, we constructed the Sakuma Frequency Converter Station connecting Eastern Japan's 50Hz electricity system with Western Japan's 60Hz electricity system, and began constructing transmission lines linking the EPCOs' service areas. During this period, we also began our international consulting business. We continued constructing hydroelectric power plants into the 1970s as other suppliers constructed oil-Ñred thermal and nuclear power plants. During this period we developed large-scale pumped-storage hydroelectric power plants which allow us to pump water from lower to upper reservoirs and increase electricity generation in peak demand periods. We also undertook the construction of large-capacity transmission lines. After the oil price shocks of the 1970s, in response to Japan's need to diversify its electricity production, we began developing large-scale coal-Ñred thermal power plants. During the 1980s, we developed our 1,000 MW Matsushima Thermal Power Plant, the Ñrst coal-Ñred thermal power plant in Japan using imported coal, followed by the 700 MW Takehara No. 3 and the 1,000 MW Matsuura No. 1 power plants. Since the 1990s, in response to the increasing demand for electricity in Japan, we have developed large-scale coal-Ñred thermal power plants such as our 2,100 MW Tachibanawan thermal power plant. Presently, we are undertaking investments in IPPs and companies supplying electricity to PPSs, new business opportunities created as a result of deregulation. In addition, we have been actively investing in overseas independent power producers, utilizing the experience we gained through our overseas consulting business. We are also pursuing the development of clean energy sources in Japan such as wind power. 59
Based on the Japanese government's decision to pursue our privatization, the J-POWER Law, which governed our establishment and subjected us to special regulations, was repealed in October 2003, and we became a regular wholesale electric utility regulated under the EUIL. In the same month, the Fund was established to strengthen our shareholders' equity through a recapitalization and to ensure the smooth sale of our shares held by the Government of Japan. All of our shares held by the Government of Japan, which represented 66.69% of our then outstanding shares, were transferred to the Fund in November 2003. In December 2003, through the issuance of additional shares to the Fund, the Fund became the owner of 83.06% of our outstanding shares. Strengths We believe our main competitive strengths are the following: We have a unique position in the Japanese electricity industry as a large-scale wholesale electric utility. We are the only electricity company in Japan with large-scale power plants in every region of the country. We have operations in each of the ten areas in which the EPCOs supply retail electricity, and we own major transmission facilities inter-connecting many of these service areas. The EPCOs are our major customers. As of March 31, 2004, we held approximately 7% of the generation capacity used by the EPCOs, with approximately 22% of total coal-Ñred thermal and approximately 19% of total hydroelectric generation capacity used by the EPCOs. As the Ñfth largest producer of electricity in the country in terms of total generation capacity as of March 31, 2004, we are one of the key players in the Japanese electricity industry. We possess attractive assets supporting our core business. We are the leading supplier of coal-Ñred thermal power. We specialize in coal-Ñred thermal electricity generation, a highly cost-competitive source. We own the largest share of coal-Ñred thermal generation capacity in Japan by a signiÑcant margin. We are a pioneer in constructing large-scale coal-Ñred thermal power plants in Japan, and our specialization has enabled us to accumulate a large body of expertise in coal-Ñred thermal power plants. Larger power plants enjoy economies of scale, and because we constructed large power plants earlier than other electricity suppliers, our power plants are generally more cost-competitive due to advanced depreciation. With proper maintenance and servicing, we expect that our existing power plants will be able to produce electricity well into the future, and we believe our competitive advantage will continue. Because coal is widely and abundantly available worldwide, supply is relatively stable. Despite recent price increases, the price of coal per caloriÑc unit is by far the lowest among fossil fuels suitable for use in power generation, such as heavy oil and LNG. This price advantage generally enables us to generate electricity competitively in comparison with, for example, electricity generated by the EPCOs at their own thermal power plants. Although future increases in generation costs due to increases in the price of coal or environmental initiatives could occur, we believe that a moderate rise in fuel costs or environmental countermeasure costs would not signiÑcantly aÅect our cost advantage. We are one of the leading suppliers of hydroelectric power in Japan. Our hydroelectric power plants currently represent approximately 19% of the total hydroelectric power generation capacity used by the EPCOs, and we are one of the leading suppliers of hydroelectric power in Japan. Because we started constructing large-scale hydroelectric power plants in Japan before other producers and concentrated on the development of large-scale hydroelectric power plants, the average generation capacity of our power plants is larger than that of the hydroelectric power plants owned by the EPCOs and other electricity suppliers in Japan. This larger capacity gives our hydroelectric power plants superior ability to respond to peak loads, the principal way in which hydroelectric power is utilized in Japan. In addition, most of our conventional hydroelectric power plants utilize dams with large water storage capacity, which increases the amount of electricity that can potentially be generated over a Ñxed period of time. 60
Hydroelectric power generation is a particularly important electricity source in Japan because it is the only major source of electricity which does not require the use of fuel, almost all of which the country needs to import from foreign suppliers, and because it has the ability to adjust Öexibly to Öuctuating electricity demand. In addition, hydroelectric power is an ideal means of power generation to address environmental concerns such as global warming. We believe we will retain our leading position in hydroelectric power generation given the scarcity of remaining sites in Japan suitable for building large-scale hydroelectric power plants and given that with appropriate maintenance and service, our existing power plants will be able to produce electricity well into the future. We own transmission lines which connect neighboring EPCOs' service areas. We own transmission lines that inter-connect EPCOs in neighboring areas, including those interconnecting each of Japan's four main islands, Hokkaido, Honshu, Shikoku and Kyushu. We also own one of only two frequency conversion facilities that connect Eastern Japan's 50Hz electricity system with Western Japan's 60Hz electricity system. These facilities constitute key transmission infrastructure in the Japanese electricity network. We believe the importance of these facilities will further increase as electricity distribution across longer distances becomes more widespread with the continuing deregulation of the electricity industry in Japan. We have a stable source of income and ample operating cash Öow. Together with our unique position in the Japanese electricity industry and our attractive assets supporting our core business, our Ñnancial position is supported by long-term supply arrangements with the EPCOs. Because our fees under these long-term supply arrangements are calculated on a fair cost plus fair return on capital basis, we enjoy a stable source of proÑts and ample operating cash Öow. Our income before income taxes and minority interests has steadily increased from Í23,305 million in the year ended March 31, 2000 to Í43,757 million in the year ended March 31, 2004. We had signiÑcant operating cash Öow in each of the three Ñscal years through March 31, 2004. The ample operating cash Öow we generate combined with the equity infusion we received in December 2003 in connection with our privatization has enabled us to prepay our debt with higher interest rates and gives us the Öexibility to make investments in new power plants and other facilities and to pursue new business opportunities and investments. We have extensive experience in the electricity generation Ñeld. We have accumulated expertise in many areas of electricity development, engineering and construction, particularly related to coal-Ñred thermal and hydroelectric power plants. This expertise contributes to our cost advantage when we develop new power plants while also enabling us to utilize eÇcient and environmentally sensitive technologies. Our experience also extends to our other businesses. We have experience in both wind and geothermal power generation, and through our investments in related projects, we are diversifying our power generation businesses. Our expertise in various Ñelds, combined with over forty years of experience in consulting on foreign electricity development projects, gives us an advantage in our overseas consulting and independent power producer businesses. Strategy We intend to increase proÑts by further strengthening our competitiveness in our core business and further strengthening our Ñnancial position. We intend to pursue growth by capturing new business opportunities by quickly responding to the changing business environment: Reduce costs to increase proÑts and strengthen cost competitiveness. In light of the ongoing deregulation of the Japanese electricity industry, we believe that further improving our cost-competitiveness is one of the keys to improving our proÑtability. We aim to improve costcompetitiveness in our core business through improved organizational and operational eÇciency. We seek to increase our cost-competitiveness mainly by reducing personnel and maintenance costs. 61
We are reducing personnel. We are in the process of reducing our group employees, consisting of the Company's employees, employees and directors of our consolidated subsidiaries as of March 31, 2001 and employees seconded to other companies, to 6,000 by March 31, 2006. Through our reduction plan, we are seeking to reduce personnel, principally in our head oÇce, through a major reform of our operations, the restructuring of our corporate organization and the reorganization of our principal subsidiaries. To achieve these personnel reductions, we have reduced new hires and introduced an early retirement program. As of July 31, 2004, we had made signiÑcant progress towards achieving our target number of group employees, with a total of 6,374 group employees, a decrease of 1,664 from 8,038 as of July 31, 2000. We are increasing the eÇciency of our maintenance activities. We introduced a new computerized maintenance management system to control maintenance and repair costs. While in the past we routinely replaced old parts based on an established schedule, we now determine the true useful lives of various parts and equipment on a case-by-case basis and replace them only when they require replacement. Strengthen our overall Ñnancial position. Our shareholders' equity was signiÑcantly enhanced in December 2003 due to our issuance and sale of Í163,699 million in new shares to the Fund, which increased the ratio of our shareholders' equity to total assets to 17.3% as of March 31, 2004 compared to 7.7% as of March 31, 2003. We aim to further improve our Ñnancial position as follows so that we may maintain our current high credit ratings and the Öexibility that high ratings provide us in Ñnancing future projects that require signiÑcant amounts of capital: We are reducing our debt. We will continue to prepay our debt with higher interest rates to further reduce our overall debt by utilizing our ample cash Öow. Through these prepayments, we will be able to reduce our interest expenses and lower the average interest rate on our outstanding debt. We are improving our asset eÇciency. To improve our asset eÇciency, we are making eÅorts to reduce assets that are less productive or are not yet productive, particularly with respect to construction plans for power plants expected to be considerably delayed due to decreased growth in electricity demand. In such cases, we have in the past decided to suspend construction plans or to transfer the project to other developers, thereby reducing future investments and construction-in-progress assets on our balance sheet and improving our asset eÇciency. In September 2001 we suspended construction on the Yunotani pumped-storage hydroelectric power plant, and in March 2002 we transferred the development rights for the Hitachinaka thermal power plant to our partner, The Tokyo Electric Power Company. While the suspension and transfer of projects entails loss on removal in the short term, in the long term, it eliminates inactive assets, thereby leading to stronger asset eÇciency businesswide, and to earlier recovery of invested capital. We plan to continue to be selective in our development plans with respect to power plant projects and with respect to improvements to existing power plants. Finally, we securitized our oÇce quarters in September 2001 to reduce our non-electric power facility assets. Take advantage of new business opportunities in a changing business environment. By taking advantage of new business opportunities that arise, we aim to develop new revenue sources. Such opportunities include the following: We are capturing new business opportunities presented by the ongoing deregulation of the Japanese electricity industry. Deregulation is progressing in the Japanese electricity industry. In anticipation of new business opportunities arising from deregulation, we are expanding our business in three areas. First, we have made investments in IPPs. Currently, two power plants are in operation and an additional power plant is under 62
construction and is scheduled to commence operation in April 2005. Second, we have made investments in power plants intended to supply electricity to PPSs. Currently, three power plants are under construction, one scheduled to commence operation in October 2004 and the remaining two scheduled to commence operation during the year ending March 31, 2006. Finally, we are making plans to participate in the wholesale electricity exchange expected to commence trading in April 2005. These are business opportunities through which we believe we can generate proÑt by eÇciently utilizing the know-how and management resources we have in electricity generation, our core business. Electricity supply to PPSs and participation in the wholesale electricity exchange will position us to expand into new sales channels in the deregulated environment.
We are investing in overseas power generation businesses. To capitalize on the higher growth in demand for electricity overseas, particularly in Asia, we plan to expand our investments in overseas power generation businesses to the extent we are able to Ñnd attractive opportunities. We are leveraging the expertise and credibility we have gained in engineering and construction consulting in a total of 59 countries for over 40 years by continuing to invest in overseas power generation businesses. We are currently participating in 15 projects, mainly in Asia. We aim to increase the proÑtability of our overseas generation businesses while minimizing risks associated with overseas investments by carefully selecting our business partners, by entering into long-term sales contracts and by using project Ñnancing models.
We are diversifying our domestic generation businesses. We are working to diversify our domestic generation business as we pursue new business opportunities in the Ñeld. We already have a track record for wind power and waste-fueled power generation, and we are actively engaged in developing power sources based on renewable energy technology. We aim to expand our business beyond power generation into diÅerent areas by utilizing the expertise we have gained in operating our core business.
Electric Power Business Our electric power business focuses on the generation and sale of electricity on a wholesale basis, mostly to the EPCOs. We have also made investments in domestic IPPs, power plants that supply energy to PPSs and wind power plants. As of March 31, 2004, we owned and operated 68 power plants in Japan with an aggregate generation capacity of 16,509 MW, including capacity owned by a consolidated subsidiary in the IPP business. The following table shows our power plants operated by our electric power segment, including a consolidated subsidiary, as of March 31, 2004: Number of power plants
Electric power segment Hydroelectric power plants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thermal power plantsÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ IPP (contracted maximum electricity)(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ TotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Note: (1) Operated by a consolidated subsidiary.
63
59 8 1 68
Approved installed capacity (MW) 8,551 7,825 134 16,509
The following table shows our other power plants operated by non-consolidated subsidiaries and aÇliates not accounted for by the equity method as of March 31, 2004: Number of power plants
Electric power segment Wind power plants(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ IPP (contracted maximum electricity)(2) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ TotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
4 1 5
Approved installed capacity (MW) 78 238 316
Notes: (1) As of March 31, 2004, two wind power plants were operated by non-consolidated subsidiaries and two were operated by aÇliates not accounted for by the equity method. As of July 2004, one of the aÇliates became a non-consolidated subsidiary. All three non-consolidated subsidiaries are expected to become consolidated subsidiaries during the year ending March 31, 2005. (2) Operated by an aÇliate not accounted for by the equity method, which is expected to become an equity-method aÇliate during the year ending March 31, 2005.
Wholesale Supply of Electricity to the EPCOs The core of our electric power business is the supply of wholesale electricity to the EPCOs pursuant to long-term electricity supply arrangements. We supplied 58,787 million kWh in the year ended March 31, 2004, or 7% of the total electricity sold by the EPCOs. Because developing new power plants requires considerable time and capital investment, before beginning construction we obtain the agreement of the EPCOs regarding the construction costs, generation capacity and the fair cost plus fair return on capital basis on which our electricity fees will be calculated. These terms are reÖected in basic agreements with them or, in the case of our earlier projects, in minutes of meetings with the EPCOs. Pursuant to these arrangements, we agree to supply to the relevant EPCOs, and the EPCOs agree to take, all of the electricity generated by the relevant power plant. Prior to commencing operation at a power plant, we enter into an electricity supply agreement with them that lists the terms and conditions of our supply of the electricity, including the fees we will charge, which are determined based on our prior agreements with the EPCOs. We formulate yearly and monthly electricity supply plans in cooperation with the EPCOs, make preparations based on the plans, and provide electricity based on ongoing communication with the EPCOs regarding actual demand. We supply all the electricity we produce to the EPCOs, excluding electricity needed for generation or lost in transmission. We generally provide electricity to the EPCOs at our power plants or at EPCO substations which are linked to our power plants by transmission lines we have constructed. Our electricity fees are calculated separately for each power plant on a fair cost plus fair return on capital basis. Thermal power fees are reviewed by the parties and adjusted every two years to reÖect changes in costs and other factors. Our hydroelectric power and transmission fees are generally Ñxed, reÖecting relatively low Öuctuations in costs. For further information on our fees, see ""Management's Discussion and Analysis of Financial Condition and Results of Operations Ì Factors AÅecting Our Results of Operations Ì Operating Revenues Ì Electric Power Segment Ì Electricity Fees''. The following table illustrates our total generation capacity for the diÅerent types of power plants we operate: Our Electricity Generation Capacity
2000 Capacity of power plants: Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ 64
8,261 5,655 13,915
As of March 31, 2001 2002 2003 (MW) 8,261 7,755 16,015
8,261 7,825 16,085
8,261 7,825 16,085
2004
8,551 7,825 16,375
The following table illustrates the amount of electricity we generated and supplied and the amount of operating revenues we received from the wholesale supply of electricity in the Ñscal years ended March 31, 2000, 2001, 2002, 2003 and 2004:
Our Wholesale Electricity Generation and Supply
2000
Year ended March 31, 2001 2002 2003 (million kWh)
2004
Amount of electricity generated by us: Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
12,596 32,406 45,003
12,550 41,945 54,495
11,333 44,544 55,877
10,624 48,679 59,303
12,103 51,238 63,341
Amount of electricity supplied by us: Hydroelectric(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
9,786 30,041 39,827
9,929 38,986 48,915
8,873 41,530 50,403
8,902 45,527 54,429
10,850 47,937 58,787
Í144,114 241,604 62,287
(millions of yen) Í144,100 Í137,901 Í138,195 281,084 339,947 335,371 67,095 67,183 66,739
Í135,758 317,719 63,398
Í448,006
Í492,280
Í516,877
Operating revenues from wholesale supply of electricity: Hydroelectric ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Thermal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Transmission ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total operating revenues from wholesale supply of electricityÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í545,032
Í540,307
Note: (1) The amount of electricity described in this table as supplied by our hydroelectric power plants does not include electricity supplied by our pumped-storage hydroelectric power plants.
Thermal Generation We began developing coal-Ñred thermal power plants in the 1960s, utilizing domestic coal. In the 1970s, as part of an eÅort to decrease Japan's reliance on foreign oil, we began planning for additional power plants utilizing more abundant and cheaper foreign coal, and in the 1980s, we commenced operations at the nation's Ñrst thermal power plants fueled by imported coal. By maximizing use of the expertise and technology we had gained as pioneers in the Ñeld, we continued to develop a number of large-scale coal-Ñred thermal power plants. We have been the industry forerunner in coal-Ñred thermal power generation capacity. We have also been steadily increasing our per power plant generation capacity, from 500 MW in 1981, to 700 MW in 1983 and to 1,000 MW in 1990. Currently, our Tachibanawan coal-Ñred thermal power plant which commenced operations in 2000 has the highest generation capacity among coal-Ñred thermal power plants in Japan with a generation capacity of 1,050 MW, and we own four of the top twelve coal-Ñred thermal power plants as measured by generation capacity. As of March 31, 2004, in connection with our wholesale supply of electricity to EPCOs, we operated seven coal-Ñred thermal power plants in our electric power business segment with an aggregate generation capacity of 7,812 MW and one geothermal power plant with a generation capacity of 13 MW. We specialize in coal-Ñred thermal power plants, with an approximately 22% share of the total coal-Ñred thermal generation capacity used by the EPCOs, making us the largest coal-Ñred thermal power producer in Japan by a signiÑcant margin.
65
The following table illustrates the capacity and utilization of our coal-Ñred thermal power plants:
Capacity and Load Factor of Our Coal-Ñred Thermal Power Plants
Name
Location (2)
Operation commenced
Isogo No. 1 No. 2(2) New No. 1
Kanagawa
May 1967 September 1969 March 2002
Takasago No. 1 No. 2
Hyogo
July 1968 January 1969
Takehara No. 1 No. 2 No. 3
Hiroshima
Tachibanawan No. 1 No. 2
Maximum capacity (MW)
Load factor of coal-Ñred generation capacity For the year ended/ending March 31, 2002 2003 2004 2005(1)
530
28%
Ì
Ì
600
39(3)
81%
85%
(67)%
500
44
61
75
(22)
July 1967 June 1974(4) March 1983
1,300
52
69
59
(59)
Tokushima
July 2000 December 2000
2,100
74
69
85
(58)
Matsushima No. 1 No. 2
Nagasaki
January 1981 June 1981
1,000
60
72
61
(61)
Matsuura No. 1 No. 2
Nagasaki
June 1990 July 1997
2,000
80
72
78
(56)
Ishikawa No. 1 No. 2
Okinawa
November 1986 March 1987
312
76
79
72
(70)
All coal-Ñred thermal power plants(5) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
66% (63)%
71% (56)%
75% (57)%
Ì
(57)%
Notes: (1) Planned. (2) Isogo No. 1 and Isogo No. 2 ceased operations in November 2001. (3) Operated on a trial basis during this period. (4) Converted from heavy oil-fueled boiler to coal-fueled Öuidized boiler in June 1995. (5) Upper row shows actual, lower row in parentheses shows planned.
EÇciency for coal-Ñred thermal power plants is dependent on high turbine temperatures. We have three of the seven turbines in Japan that can reach a turbine temperature of 600oC. In addition to reducing the amount of CO2 emissions, thermal eÇciency has the added advantage of reducing generation costs. Our power plants utilize the most advanced emission controls for sulfur oxides and nitrous oxides, both of which contribute to air pollution and acid rain. We installed one of the Ñrst desulfurization and denitration facilities in commercial coal-Ñred thermal power plants in Japan. We are one of the world leaders in environmental technology related to coal-Ñred thermal power generation and have been active in introducing these technologies in Japan and overseas. For further information regarding our environmental practices and policies, see ""Ì Environmental Matters''. Because the price of coal per caloriÑc unit is low compared to other fossil fuels, coal-Ñred thermal power enjoys a cost advantage over other forms of thermal power. Coal-Ñred thermal power is used, along with nuclear power, as a base source in Japan. Because our thermal power is virtually all coal-Ñred, we enjoy a higher load factor in comparison to other thermal power producers. As we are Japan's largest owner of coal-Ñred thermal power plants, we are the largest purchaser of overseas fuel coal in Japan, importing over 10 million metric tons of overseas coal annually. We procure coal from diverse international sources and we have spot, one-year and longer-term contracts to ensure stability and economy. We have invested in coal development eÅorts overseas to further stabilize long-term access. See ""Ì Fuel''.
66
Hydroelectric Generation We engaged in the development of hydroelectric power plants immediately following our establishment and since that time have continued to develop large-scale hydroelectric power plants throughout Japan. Because of this, our average generation capacity per power plant is signiÑcantly higher compared to that of other hydroelectric power producers, giving us the ability to respond to peak load requirements, the major role for hydroelectric power in Japan. As of March 31, 2004, our 59 hydroelectric power plants had a total generation capacity of 8,551 MW, which represented approximately 19% of total the hydroelectric generation capacity used by the EPCOs. We are one of the leading suppliers of hydroelectric power in Japan. We own and operate two diÅerent types of hydroelectric power plants, conventional and pumpedstorage. Our conventional hydroelectric power plants consist of reservoir-type and natural Öow with dam-type. Reservoir-type conventional power plants are able to adjust Öow volume over relatively long periods of time, storing water when it is abundant and releasing it when needed for generation. Natural Öow with dam-type conventional power plants are also able to adjust Öow volume, but over a shorter period of time, generally less than a week. Pumped-storage power plants use surplus power from nights, weekends and other periods of low electricity demand to pump water from lower to upper reservoirs, making this water available when needed for generation during periods of peak demand. A number of our hydroelectric power plants are adjacent to largescale dams. We own power plants at eight of the top ten dams in Japan as measured by water storage capacity. We operate 54 conventional hydroelectric power plants with a combined generation capacity of 4,151 MW. The following table illustrates the capacity of our conventional hydroelectric power plants with generation capacity over 200 MW and the combined capacity of our remaining conventional hydroelectric power plants: Conventional Hydroelectric Power Plants
Power plant
Location
Okutadami Tagokura Sakuma Ikehara
Fukushima Fukushima Shizuoka Nara
Main dam
Operation commenced
Okutadami December 1960 Tagokura May 1959 Sakuma April 1956 Upper: Ikehara September 1964 Lower: Nanairo Tedorigawa I Ishikawa Tedorigawa August 1979 Nagano Fukui Upper: Kuzuryu May 1968 Lower: Washi Miboro Gifu Miboro January 1961 47 other power plants ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
67
Maximum capacity (MW) 560 380 350 350 250 220 215 1,826 4,151
Our remaining Ñve hydroelectric power plants are large-scale pumped-storage power plants. The following table illustrates the generation capacities of our Ñve pumped-storage hydroelectric power plants: Pumped-Storage Hydroelectric Power Plants
Power plant Shintoyone
Location
Dam
Operation commenced
Maximum capacity (MW)
Aichi
Upper: Shintoyone November 1972 Lower: Sakuma Shimogo Fukushima Upper reservoir: Ouchi April 1988 Lower reservoir: Okawa Okukiyotsu Niigata Upper: Kassa July 1978 Lower: Futai Numappara Tochigi Upper: Numappara June 1973 Lower: Miyama Okukiyotsu II Niigata Upper: Kassa June 1996 Lower: Futai TotalÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
1,125 1,000 1,000 675 600 4,400
Because hydroelectric power is used as a peak source in Japan, it is imperative that our power plants are able to respond quickly to spikes in demand. On the operational front, we maintain high eÇciency by controlling operations at our 59 power plants from four regional control centers. Based on dispatch orders from our central load dispatching center, each regional control center controls the operation of each individual power plant in its area as illustrated in the following diagram: Dispatch Order Control
North Regional Center
10 hydroelectric power plants
East Regional Center
18 hydroelectric power plants
Central Regional Center
24 hydroelectric power plants
West Regional Center
7 hydroelectric power plants
Central Load Dispatching Center
We have constructed various types of hydroelectric power plants, from small-, mid- and large-scale conventional to large-scale pumped-storage hydroelectric power plants. We believe we are the most experienced developer and operator of hydroelectric power plants in Japan. We have sophisticated technological skills in areas such as the construction of dams and large-scale subterranean facilities. For example, we increased our Okutadami hydroelectric power plant's original 360 MW generation capacity by an additional 200 MW without changing the water level of the existing dam by boring a hole in the existing dam and expanding the underground power plant. This construction was completed without interrupting the power supply. As our hydroelectric power plants are widely distributed throughout Japan, we minimize the risk of unfavorable weather conditions such as drought. More than half of our hydroelectric power plants have been in operation for over 30 years. We are conducting appropriate maintenance and servicing of our power plants, and we believe we can maintain the power plants in sound operating condition into the foreseeable future. Additionally, as few locations remain in Japan for the development of large-scale hydroelectric power plants, we expect the relative value of our hydroelectric power to further increase, including as a method for coping with global environmental issues.
68
Transmission We originally developed our transmission facilities in order to transmit the electricity we generated at our power plants. Currently, however, portions of our facilities play a much more important role in the overall functioning of the electricity system in Japan. As of March 31, 2004, we maintained 2,404 kilometers of transmission lines nationwide and a total of three substations, one frequency converter station and four alternating current/direct current, or AC/DC, converter stations. Generally, we own most of our transmission facilities independently, although we own a small number of them jointly with one or more EPCOs. The following tables illustrate our principal transmission facilities:
Principal Transmission Facilities Transmission lines with routes greater than 100 kilometers Tadami Trunk Line Tokachi Trunk Line Sakuma East Trunk Line Kitahon HVDC Link (DC section) Honshi Interconnecting Line Nahari Trunk Line Miboro Trunk Line Sakuma West Trunk Line
Substations Minamikawagoe Nagoya Nishi Tokyo
Frequency converter stations Sakuma
AC/DC converter stations Kihoku Anan Hakodate Kamikita
Operation commenced
Route length (km)
May 1959 January 1956 April 1956 December 1979 July 1994 June 1960 November 1960 April 1956
215.9 214.3 194.3 167.4 127.0 119.9 108.6 107.7
Operation commenced May 1959 April 1956 April 1956 Operation commenced October 1965
Voltage (kV) 275-500 187 275 DCP250 500 187 275 275
Authorized capacity (kVA) 1,542,000 1,400,000 1,350,000 Authorized capacity (MW) 300
Operation commenced
Authorized capacity (MW)
June 2000 June 2000 December 1979 December 1979
1,400 1,400 600 600
Our Sakuma frequency converter station built in 1965 linked, for the Ñrst time, the 50Hz electricity system of Eastern Japan with the 60Hz electricity system of Western Japan. Currently, there are only two frequency converter stations in Japan, including our Sakuma Station. We constructed and own extra high voltage transmission lines connecting the island of Honshu with the islands of Hokkaido, Kyushu and Shikoku, as well as transmission lines connecting Tokyo to the Tohoku area and the Chubu and Hokuriku areas to the Kansai area. The Honshu-Hokkaido and Honshu-Shikoku connections are constructed with submarine cables operating on direct current, which allows for eÇcient long distance transmission. Although we conduct maintenance and management of our transmission facilities, their usage is managed on a day-to-day basis by the EPCOs. 69
Future Development In order to secure stable proÑts and cash Öows from long-term supply arrangements, we will continue to develop new power plants to supply electricity to the EPCOs. We currently have six projects in development for which we have entered into basic agreements with the relevant EPCO, with total planned generation capacity of 2,187 MW. Three of these, with a combined generation capacity of 2,000 MW, are scheduled to start commercial operation by the year ending March 31, 2014. They consist of a 600 MW coal-Ñred thermal power plant, a 1,383 MW nuclear power plant and a 17 MW hydroelectric power plant. At March 31, 2014, we expect to have 18,345 MW total capacity, including accounting for a temporary loss of approximately 30 MW from a hydroelectric power plant which is to be replaced. This is an increase of 12% compared to 16,380 MW at March 31, 2004. Under the electricity supply plan for the year ending March 31, 2005 which we submitted to the METI, we included commencement of operation at our 400 MW Tokuyama hydroelectric power plant in the year ending March 31, 2009. However, we recently agreed with Chubu Electric Power Company, to alter our construction plans for the Tokuyama hydroelectric power plant based on a proposal by the Ministry of Land, Infrastructure and Transport to decrease the amount of water dedicated to the generation of electricity, reÖecting a delay in the construction project, and weaker than anticipated demand for electricity. The proposed new plan calls for the power plant to be changed from a 400 MW pumped-storage hydroelectric power plant to a 153 MW conventional hydroelectric power plant, and the power plant is expected to commence operations in the year ending March 31, 2015. We are currently in the process of obtaining the concurrence of the local government and community to these changes. As power plant development requires long periods of time and substantial long-term investments, prior to commencing construction we enter into basic agreements with relevant EPCOs specifying such terms as estimated construction costs and an agreement to purchase, based on a fair cost plus fair return on capital basis, all electricity that is to be generated. Actual electricity fees are determined by long-term electricity supply agreements entered into with the relevant EPCOs just prior to the commencement of the operation at the power plant. The following table sets forth our future power plant development plans:
Power plant name
Generation capacity (MW)
Operation commencing
Customer(s)
Hydroelectric: Isawa I (Conventional)
18
Year ending March 31, 2015
Tohoku Electric Power Company
Sagara (Conventional)
17
March 2011
Kyushu Electric Power Company
Shin Katsurazawa (Conventional)
17
After the year ending March 31, 2015
Hokkaido Electric Power Company
153
Year ending March 31, 2015
Chubu Electric Power Company
600
July 2009
The Tokyo Electric Power Company, Tohoku Electric Power Company
March 2012
9 EPCOs
Tokuyama (Conventional)(1) Coal-Ñred Thermal: Isogo Thermal New No. 2
Nuclear: Oma
1,383
Note: (1) Though originally planned as a 400 MW pumped-storage power plant, we are in discussions with the local government to make this a conventional hydroelectric power plant and reduce the generation capacity to 153 MW and also to delay the start of operation from the year ending March 31, 2009 to the year ending March 31, 2015.
70
Our most important major construction projects over the next ten years are the Isogo New No. 2 coal-Ñred thermal power unit and the Oma nuclear power plant.
Isogo New No. 2 In order to address the aging of our Isogo coal-Ñred thermal power plant with two 265 MW units that commenced operations in 1967 and 1969 and to respond to increased electricity demand in Eastern Japan, we are replacing the old units with two new 600 MW units on the same site. The Ñrst of these, Isogo New No. 1, began operation in 2002. Because Yokohama is the second most populous city in Japan with leading industrial zones, it has one of the nation's strictest environmental standards. Our former units met these standards and operated for 35 years. Isogo New No. 1 and No. 2 will utilize the maximum available area on this site and have more than twice the capacity of their predecessors while the amount of sulfur oxides, nitrous oxides and certain other emissions will be reduced signiÑcantly by applying the latest coal-Ñred thermal power plant technology that we possess.
Oma Nuclear Power Plant The Oma nuclear power plant will be our Ñrst nuclear power plant. It will be constructed with support from the Government of Japan and the EPCOs. We are utilizing expertise gained through research we conducted in nuclear power development, combined with experience we gained through designing, constructing and operating the Fugen advanced thermal reactor, a project of the Japan Nuclear Cycle Development Institute (formerly known as the Power Reactor and Nuclear Fuel Development Corporation). We have received concurrence from the relevant local governments for this project. The Oma nuclear power plant will utilize an advanced boiling water reactor to be constructed based on boiling water reactor technology currently being utilized in more than 90 nuclear power plants worldwide. The power plant is responsive to the national policy promoting plutonium use and is designed to use full-MOX fuel, in contrast to light water reactors which are planned to operate using only up to one-third MOX. At the same time, the power plant is designed so that it can also be operated using uranium fuel alone to allow for Öexibility in fuel use. We have applied to the METI for approval to build the reactor core. After receiving this and other related approvals and permits, we will begin construction. We are making eÅorts to reduce the estimated Í469 billion construction costs, and we are receiving grants from the Government of Japan for the development of full-MOX technology. We regard this project, which will generate electricity while emitting no CO2, as an important part of our strategy to combat global warming. Other Electric Power Businesses In response to the ongoing deregulation of the electricity industry in Japan, we have begun investing in IPPs and in companies that supply electricity to PPSs. Because these electric power businesses are not operated pursuant to contracts based on a fair cost plus fair return on capital fee calculation basis, they diÅer from our wholesale supply of electricity to the EPCOs. We are also preparing to participate in the wholesale electricity exchange which is expected to commence trading in April 2005. In addition, we are pursuing wind power in an eÅort to further diversify the way we supply electric power in Japan.
IPP Business In 1995, contracts for supplying wholesale electricity to the EPCOs were opened up to IPPs. Through March 2000, the EPCOs solicited bids which resulted in the purchase of approximately 7,000 MW of capacity from IPPs. Although we did not bid at the time, we later responded to requests to invest in IPPs formed by companies such as Toa Oil Co., Ltd. and Taiheiyo Cement Corporation, and we are currently increasing the proÑtability and stability of these businesses by oÅering our abundant experience in electricity generation. We have invested in two IPPs which are already in operation, of which one is a consolidated subsidiary and the other is expected to become an equity-method aÇliate beginning in the year ending 71
March 31, 2005. We have also decided to participate in an additional project. The following table shows information regarding our investments in IPPs:
IPPs Company name (power plant type) ITOIGAWA POWER Inc.(1)(coal-Ñred) GENEX COMPANY, LIMITED(2) (oil) Tosa Power Inc. (coal-Ñred)
J-POWER ownership (%)
Generation capacity (MW)
Operation commenced/ commencing
Itoigawa
80
134
April 2003
Genex Mizue
40(3)
238
June 2003
Tosa
Ì(4)
150
April 2005
Plant name
Customer Tohoku Electric Power Company The Tokyo Electric Power Company Shikoku Electric Power Company
Notes: (1) Consolidated subsidiary. (2) AÇliate not accounted for by the equity method. (3) Held through 100% subsidiary, JPOWER GENEX CAPITAL Co., Ltd. (4) We have agreed to make a 45% equity investment in Tosa Power Inc. in March 2005.
Electricity Sales to PPSs PPSs sell electricity directly to large-load customers and use the EPCOs' transmission lines to supply purchased or generated electricity to these customers. We believe that we will be able to build on our expertise in electricity generation to exploit PPS opportunities. We currently have investments in three companies that are each constructing a gas-turbine combined cycle thermal power plant in the Tokyo Bay area, with combined capacity of approximately 300 MW. The Ñrst of these is expected to commence operation in October 2004, and the remaining two are scheduled to commence operation in April 2005 and October 2005, respectively. The following table illustrates our investments in companies with power plants that will supply electricity to PPSs. As these power plants are currently under construction, they are not yet being treated as consolidated subsidiaries or equity-method aÇliates in our consolidated Ñnancial statements. We expect that these subsidiaries will be consolidated, and this aÇliate will be treated as an equity-method aÇliate, when the power plants that they own commence operation.
PPS Power Plants Company name (power plant type) Bay Side Energy Co., Ltd.(1) (LNG) Ichihara Power Co., Ltd.(1) (LNG) Mihama Seaside Power Co., Ltd.(2)(LNG)
J-POWER ownership Plant name (%)
Generation capacity (MW)
Operation commencing
Customer (PPS) Diamond Power
Ichihara
100
100
April 2005
Ichihara
60
110
October 2004
Shinminato
50
100
Notes: (1) Non-consolidated subsidiary. (2) AÇliate not accounted for by the equity method.
72
Nippon Steel Corporation October 2005 Diamond Power
Participation in the wholesale electricity exchange Trading at the wholesale electricity exchange is scheduled to commence in April 2005. The exchange will be operated by the Japan Electric Power Exchange. We have invested in and become a member of the exchange. We plan to sell electricity on the exchange, although we do not expect the level of our trading activities to be signiÑcant in the near term. For further information on the wholesale electricity exchange, see ""The Electricity Industry in Japan Ì Electricity Industry Deregulation in Japan''.
Wind Power Generation We have been increasingly investing in companies that own and operate wind power plants in recent years. Since 2000, when operation commenced at our Ñrst wind power plant investment, a 31 MW wind power plant in Hokkaido which was the largest in Japan at that time, we have invested in three additional projects with a combined total generation capacity of 47 MW. We have Ñve other projects currently being developed. Three, with a combined total generation capacity of 55 MW, are expected to commence operation by March 2005, one 12 MW power plant is expected to commence operation in January 2006 and one 66 MW power plant is expected to commence operation in December 2006. This will bring the total generation capacity of wind power plants we invest in to 211 MW. For the year ended March 31, 2004, none of the companies that own and operate these wind power plants were consolidated or accounted for by the equity method for purposes of our consolidated Ñnancial statements. In the year ending March 31, 2005, we expect to begin consolidating the results of six wind power plant subsidiaries. The following table shows information regarding our wind power investments as of the date of this oÅering circular: Wind Power Plants
Company name
Plant name
Wind power plants currently in operation: Dream-Up Tomamae Co., Ltd.(1) Nikaho-kogen Wind Power Co., Ltd.(2) Green Power Kuzumaki Co., Ltd.(2) J-Wind Tokio Co., Ltd.(1)
Tomamae Winvilla Wind Power Nikaho-kogen Wind Power Green Power Kuzumaki Wind Power Tokyo Rinkai Wind Power Subtotal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Wind power plants currently being developed: J-Wind TAHARA Ltd.(2) Tahara Rinkai Wind Power Green Power Aso Aso Nishihara Wind Co., Ltd.(2) Power Nagasaki Shikamachi Wind Nagasaki Shikamachi Power Co., Ltd.(2) Wind Power Green Power Setana Setana Rinkai Wind (2) Co., Ltd. Power Green Power Koriyama Koriyama Nunobiki Kogen Wind Power Nunobiki Co., Ltd.(2) Subtotal ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
J-POWER Generation ownership capacity (%) (MW)
19
31
67
25
100
21
50
2
Operation commenced/ commencing
Customer
December 2000 Hokkaido Electric Power Company December 2001 Tohoku Electric Power Company December 2003 Tohoku Electric Power Company March 2003 The Tokyo Electric Power Company
78
66
22
81
18
70
15
100
12
100
66
March 2005
Chubu Electric Power Company February 2005 Kyushu Electric Power Company February 2005 Kyushu Electric Power Company January 2006 Hokkaido Electric Power Company December 2006 The Tokyo Electric Power Company
133 211
Notes: (1) AÇliate not accounted for by the equity method as of March 31, 2004. Dream-up Tomamae became a wholly-owned subsidiary in August 2004 when we increased our interest to 100%. (2) Non-consolidated subsidiary.
73
We are conducting feasibility studies for additional wind power generation projects in Japan. We develop new sites using environment research, scenic assessment techniques, precise analysis of wind synopsis, optimal equipment selection and operational and maintenance technologies. In April 1, 2003, the Renewable Portfolio Standard Law came into eÅect. Under this law, retail electricity suppliers, such as EPCOs and PPSs, are obligated to obtain a certain amount of electricity from renewable energy sources. The industry aggregate amount of electricity required to be so obtained will increase incrementally from 3,277 million kWh for the year ended March 31, 2004 to 12,200 million kWh for the year ending March 31, 2011. This aggregate amount is allocated among retail electricity suppliers in proportion to each electricity supplier's share of total electricity supply. As wind power generation is an energy source which meets the qualiÑcations of the Renewable Portfolio Standard Law, it has become an attractive electricity source for retail electricity suppliers. Other Businesses Electric Power-Related Our electric power-related businesses provide construction and maintenance services for power plants and telecommunications facilities, and supply fuels for power plants. Although most of our electric powerrelated revenues are from intersegment sales of services to our electric power segment, we also receive revenues from the provision of such services to third parties. DiversiÑed Businesses Engineering Business Over the past 50 years, we have accumulated expertise in areas such as power plant planning, construction, maintenance and operation. We have applied this expertise to energy, recycling, power system, infrastructure facilities, and use of underground facilities, principally for governmental agencies and local authorities. For example, we have applied techniques used to create large-scale underground sites for underground power plants to design and manage the construction of three domestic oil storage bases and two liqueÑed petroleum gas, or LPG, storage bases. We seek to increase revenues and earning opportunities in the years ahead by increasing order volumes while employing our engineering capabilities to develop new businesses. For example, we have begun to promote technologies and business opportunities related to coal ash. International Consulting Business Our prime role in international consulting is to provide technological advice for thermal and hydroelectric power plants, transmission lines, substations and other electricity related projects. We have been involved in international power development-related consulting since 1961. Through March 31, 2004, we have consulted on 226 projects in 59 countries and regions in the areas of thermal electric power and hydroelectric development, surveys, design, construction, supervision and management of transmission and substation facilities. We receive commissions from Japanese organizations such as the Japan International Cooperation Agency to conduct basic surveys related to the Government of Japan's technological assistance plans, feasibility studies and detailed designs for government-based contracts. We also receive commissions for contracts with foreign governments. In addition, we provide design, construction management and other services for private sector contracts. Investments in Overseas Independent Power Producers Due to ongoing structural reforms and privatization of national electricity industries around the world, markets for overseas independent power producers are expanding. We are making investments in these markets based on the expertise and knowledge we have accumulated in our international consulting business over the years as well as in our core business in Japan. Our overseas independent power producer operations include investments in geothermal, gas thermal, coal-Ñred, wind and waste-fueled generation projects. To date, we have been involved in 15 projects in six 74
countries of which 11 are under commercial operation with a combined output generation capacity of 2,107 MW. The following table shows our overseas independent power producer projects currently in operation and construction:
Overseas Independent Power Producers
Company name Independent Power (Thailand) Co., Ltd.(1) (gas thermal) Chiahui Power Corporation(1) (gas thermal) Samutprakarn Cogeneration Co., Ltd.(1) (gas cogeneration) Thaioil Power Co., Ltd.(1) (gas cogeneration) Nong Khae Cogeneration Co., Ltd.(1) (gas cogeneration) Gulf Cogeneration Co., Ltd.(1) (gas cogeneration) TLP Cogeneration Co., Ltd.(2) (gas cogeneration) SEC HoldCo , S.A.(1) (wind power)
ShanXi TianShi Power Generation Co., Ltd.(2) (waste coal-Ñred thermal) Roi-Et Green Co., Ltd.(2) (biomass) Ormat Leyte Co., Ltd.(8) (geothermal) Gulf Yala Green Co., Ltd.(1) (biomass)
J-POWER Generation interest capacity (%) (MW)
Operation commenced/ commencing
Customer
Country/ Territory
11(3)
700
August 2000
EGAT(7)
Thailand
40(4)
670
December 2003
Taiwan Power Company
Taiwan
49(5)
115
August 1999
EGAT(7)/companies located in industrial park
Thailand
19
114
April 1998
Thailand
49(5)
112
October 2000
EGAT(7)/oil reÑnery of Thai Oil Company Limited EGAT(7)/companies located in industrial park
49(5)
108
September 1998
EGAT(7)/companies located in industrial park
Thailand
20
116
January 2003
EGAT(7)/companies located in industrial park
Thailand
December 1999 September 2000 December 2000 (Unit No. 1) May 2001 (Unit No. 2)
Union Fenosa Distribution Spain
Shanxi Province Power
China
May 2003
EGAT(7)
Thailand
50(4)
64
24
50
25(6)
9
Thailand
10
49
October 1998
PNOC Ì EDC
Philippines
47(5)
20
August 2005
EGAT(7)
Thailand
Notes: (1) Equity-method aÇliate. (2) AÇliate not accounted for by the equity method. (3) Held through 19% equity-method aÇliate, Thaioil Power Co., Ltd. (4) Held through 100% consolidated subsidiary, J-Power Investment Netherlands B.V. (5) Held through 49% equity-method aÇliate, Gulf Electric Public Co., Ltd. (6) Held through 26% subsidiary, EGCO Green Energy Co., Ltd. (7) Electricity Generating Authority of Thailand. (8) Minority equity investment.
In order to minimize the risks inherent in international investments, we choose partners and projects after careful consideration of various aspects of the project. Furthermore, we continuously monitor ongoing projects. 75
Investments in Environmental and Energy Businesses Building on our expertise and knowledge accumulated in the generation business, we have made investments in environmental and energy related businesses, applying Private Finance Initiative and Public Private Partnership business models and other private sector techniques to public sector projects. Since December 2002, we have operated a waste-fueled generation business generating 21 MW of electricity. We utilize refuse-derived fuel produced by local governments, using waste from 28 cities, towns and villages located in the vicinity of Omuta, Fukuoka prefecture. We have begun to operate a cogeneration facility providing 12 MW of electricity and steam to the Tokyo Waterworks Department's water treatment power plant in Kanamachi. We have received a commission for the construction and operation of a wastewater processing facility in Samukawa, Kanagawa, and we plan to begin operation at this facility in April 2006. We will continue to address the needs of local governments and other customers in the environment and energy Ñeld and seek other new businesses. The following table shows our environment and energy aÇliates, none of which are accounted for by the equity method:
Environment and Energy AÇliates Company name Omuta Recycle Power Co., Ltd. (refuse derived fuel) Kanamachi PuriÑcation Plant Energy Service Co., Ltd. (cogeneration)
J-POWER Generation interest(%) capacity (MW) 35
21
20
12
Operation commenced
Customer
December 2002 Kyushu Electric Power Company October 2000 Tokyo Metropolitan Water Division
Other We have installed a network of Ñber optic cables over our transmission lines to assist in controlling the nationwide operation of our electric power facilities. Utilizing a portion of this network, together with other companies we began oÅering Ñber optic services in Tokyo, Nagoya and Osaka in April 2001. We have also begun to sell fertilizer products made from coal ash generated from our thermal power plants. These other businesses are operated by non-consolidated subsidiaries and aÇliates not accounted for by the equity method, and thus their business results have not been reÖected in our results of operations for the year ended March 31, 2004.
76
Customers Japan's ten EPCOs are our primary customers, purchasing almost all of the wholesale electricity we produce. The following table sets forth our operating revenues by customer and the facilities used to supply them:
Customer Hokkaido Electric Power Company
Tohoku Electric Power Company
Revenues from electricity sales Percentage of and transmission total revenues J-POWER facility(1) (year ended from electricity Generation facility (maximum capacity) March 31, sales and 2004) transmission Hydroelectric Thermal (billions of yen) Í 14.9 2.9% Nukabira (42MW) Ashoro (40MW) Meto II (28MW) Meto I (27MW) and other 6 power plants 27.4
5.3
The Tokyo Electric Power Company
118.4
22.7
Chubu Electric Power Company
36.2
Hokuriku Electric Power Company
Major transmission facility Kitahon HVDC Link Tokachi Trunk Line Hakodate AC/DC Converter Station Kamikita AC/DC Converter Station
Shimogo (1,000MW) Okutadami (560MW) Tagokura (380MW) Otori (182MW) and other 11 power plants
Isogo Thermal (600MW) Itoigawa Thermal (134MW) Onikobe Geothermal (13MW)
Kitahon HVDC Link Hakodate AC/DC Converter Station Kamikita AC/DC Converter Station Sakuma Frequency Converter Station
Shintoyone (1,125MW) Okukiyotsu (1,000MW) Shimogo (1,000MW) Numappara (675MW) and 13 other power plants(2)
Isogo Thermal (600MW)
Tadami Trunk Line Sakuma East Trunk Line Kitahon HVDC Link Numappara Line Hakodate AC/DC Converter Station Kamikita AC/DC Converter Station Sakuma Frequency Converter Station Minamikawagoe Substation Nishitokyo Substation
7.0
Shintoyone (1,125MW) Sakuma (350MW) Ikehara (350MW) Nagano (220MW) and other 12 power plants
Takasago Thermal (500MW)
Sakuma West Trunk Line Nagano Seki Line Sakuma Frequency Converter Station Nagoya Substation
11.3
2.2
Tedorigawa I (250MW) Nagano (220MW) Yugami (54MW)
Takasago Thermal (500MW)
Sakuma Frequency Converter Station
The Kansai Electric Power Company
101.1
19.4
Ikehara (350MW) Miboro (215MW) Nanairo (82MW) Totsugawa I (75MW) and other 6 power plants
Tachibanawan Thermal (2,100MW) Honshi Interconnecting Line Takasago Thermal (500MW) Anan Kihoku HVDC Link Miboro Trunk Line Kihoku AC/DC Converter Station Sakuma Frequency Converter Station
The Chugoku Electric Power Company
105.0
20.1
Futamata (72MW) Nagayama (37MW) Yanase (36MW)
Tachibanawan Thermal (2,100MW) Matsuura Thermal (2,000MW) Takehara Thermal (1,300MW) Matsushima Thermal (1,000MW)
Shikoku Electric Power Company
47.7
9.2
Futamata (72MW) Sameura (42MW) Nagayama (37MW) Yanase (36MW)
Tachibanawan Thermal (2,100MW) Honshi Interconnecting Line Matsuura Thermal (2,000MW) Nahari Trunk Line Matsushima Thermal (1,000MW) Anan AC/DC Converter Station Sakuma Frequency Converter Station
Kyushu Electric Power Company
47.5
9.1
Sendaigawa I (120MW) Setoishi (20MW) Sendaigawa II (15MW)
Tachibanawan Thermal (2,100MW) Matsushima Thermal Line Matsuura Thermal (2,000MW) Kanmon Interconnecting Line Matsushima Thermal (1,000MW) Sakuma Frequency Converter Station
The Okinawa Electric Power Company
11.1
2.1
Others Total
0.2 Í 521.3
0.0 100.0%
Shin-yamaguchi Trunk Line Shin-hiroshima Trunk Line Shin-okayama Trunk Line Shin-nishihiroshima Trunk Line Higashiyamaguchi Trunk Line Sakuma Frequency Converter Station
Ishikawa Coal Thermal (312MW) Nagayama (37MW)
Notes: (1) For hydroelectric power plants, the top four power plants according to output capacity are listed. For thermal and geothermal power plants, all power plants are listed including Itoigawa, a plant owned by a consolidated subsidiary. For transmission facilities, lines of 50km or more in length, as well as all substations, AC/DC converter stations and frequency conversion stations are listed. (2) The 13 other power plants referred to here include Okutadami (560 MW), Tagokura (380 MW), Otori (182 MW) and Sakuma (350 MW).
77
Maintenance Inspections of our coal-Ñred thermal power plants are conducted in accordance with the EUIL. Boilers are inspected every two years, and turbines are inspected every four years. We conduct smaller-scale inspections more frequently. Inspections required by the EUIL take approximately two to three months, and smaller-scale inspections take approximately two weeks. Inspections are conducted at a time agreed upon with the relevant EPCO. As inspections require suspension of generation, they are typically conducted during spring or autumn, when electricity demand is relatively low. We conduct inspections of our hydroelectric power plants in accordance with internal maintenance and security regulations. We overhaul turbines and generators approximately every 14 years, and we inspect penstocks approximately every six years. Between these inspections, we conduct smaller-scale inspections. Overhaul of the turbines and generators takes approximately two months, inspection of the penstocks takes approximately one month and smaller-scale inspections take approximately two to three days. We conduct these overhauls and inspections at a time agreed upon with the relevant EPCO. As overhauls and inspections require suspension of power generation, we carry them out during periods with less rain. Replacements and repairs necessary for the maintenance of facilities are done at the same time as these periodical inspections, to the extent possible. In order to reduce maintenance costs while maintaining the reliability of our electricity supply, we have introduced a computerized maintenance management system. The system enables us to track the status and history of maintenance work, permitting us to perform maintenance when it is most appropriate. Fuel We purchase coal to fuel our thermal power plants. We also purchase heavy and diesel oil to aid combustion at those power plants. The amount of coal we purchase generally corresponds to the amount we use to fuel our coal-Ñred thermal power plants which in turn is determined by the amount of electricity we supply to the EPCOs. In the year ended March 31, 2004, we purchased approximately 18 million tons of coal, an increase of 4.6% over the previous year, at an average purchase price of approximately Í4,600 per ton. Of that amount, 96.7% was imported. Compared to other types of fossil fuel, there are larger reserves and more stable supplies of coal, partly reÖecting general political stability in the major coal producing countries. The following table illustrates the price of fuel and the amount of fuel purchased for the three years ended March 31, 2002, 2003 and 2004: Year ended March 31, 2002 2003 2004 Coal: Amount purchased (ton) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Price (yen/ton) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Heavy oil: Amount purchased (kl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Price (yen/kl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Diesel oil: Amount purchased (kl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Price (yen/kl) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Í
15,225,226 5,960
Í
17,478,984 4,844
Í
18,280,138 4,586
Í
67,653 23,109
Í
49,652 23,530
Í
67,593 24,351
Í
38,941 27,699
Í
32,284 32,089
Í
27,272 34,459
Between March 31, 2002 and March 31, 2004, the average annual price of Australian coal declined 22%. In the current Ñscal year, annual contract prices for coal from Australia have risen by as much as 70% due to a decline in the availability of coal from China, among other things. Because our fees are calculated on a fair cost plus fair return on capital basis, and because they are renegotiated regularly, in most instances we are able to recover increases in fuel costs. In order to mitigate the eÅects of large short-term price Öuctuations and to secure a stable supply, we have one-year and longer-term contracts with suppliers in Australia, China and Indonesia. We incorporate buyer's options into our one-year and longer-term contracts, which gives us Öexibility to make purchases based on our variable demand. We also make limited purchases on the spot 78
market and utilize e-markets and direct transactions. In these transactions, we often specify grade rather than brand, enabling us to procure coal at lower prices. We have minority equity investments in the Blair Athol and Ensham mining projects in Australia to stabilize our coal supply. In each of the three years ended March 31, 2002, 2003 and 2004, these two sources provided approximately 40% of our coal. Our contract with Blair Athol will expire in March 2010, and our contract with Ensham will expire in March 2012. We are currently investigating other possible long-term arrangements for procuring coal. Our thermal power plants are located on the coast, facilitating the receipt of shipments of imported coal. On average, each of our coal-Ñred thermal power plants carries a reserve of coal to support its operation for approximately one to two months. Competition Our electric power business is based on long-term wholesale arrangements we formulate with the EPCOs before undertaking construction of new power plants. We and the Japan Atomic Power Company are the only two major suppliers of wholesale electricity in Japan, and the latter only engages in nuclear power generation. As a result, we currently do not experience signiÑcant direct competition. In the context of continued deregulation in the Japanese electricity industry, the EPCOs have responded to competition by lowering their prices. We generally renegotiate the fees that we charge to EPCOs every two years, in the case of coal-Ñred power plants, and when substantial changes in the economic environment lead to negotiated changes, in the case of hydroelectric and transmission fees. The EPCOs are continuing to experience signiÑcant price pressure, and they in turn are increasingly seeking to lower our fees. While we are currently only indirectly aÅected by signiÑcant competitive forces, in the future the scope of competition for wholesale electricity producers may increase. As part of ongoing industry deregulation, the Japan Electric Power Exchange has been established by nine of the EPCOs and nine PPSs and is scheduled to commence operation on April 1, 2005. The exchange is expected to provide a price index to facilitate investment decision making. The exchange will manage day-ahead spot transactions and long-term forward transactions. This may lead to increased competition in the wholesale market, although the eventual scope of such future competition is currently unclear. Property Our electric power facilities are generally located on land that we own independently, although some are located on land we co-own or lease. Our Isogo and Takasago thermal power plants are built on land leased from the EPCOs to which they provide electricity. Portions of our Tachibanawan thermal power plant are located on land we jointly own with Shikoku Electric Power Company and our Matsuura thermal power plant is located on land we jointly own with Kyushu Electric Power Company. A number of our hydroelectric power plants are located adjacent to dams that we jointly own, principally with national and prefectural government entities, or that are owned by other entities. Our Shintoyone hydroelectric power plant, for example, is located adjacent to a dam which we own jointly with another party, and our Shimogo hydroelectric power plant is located adjacent to a dam which is owned independently by another entity. Our transmission lines lie over land for which we have acquired rights of way. Additionally, some of our other transmission facilities, for example, our Shinyamaguchi trunk line and the Anan and Kihoku AC/DC converter stations and the lines that connect them, are jointly owned by us with the EPCOs that utilize them. Environmental Matters We acknowledge the environmental impact of our operations and view conservation as a key obligation to society. Accordingly, our corporate philosophy is to achieve harmony with the environment and earn local trust in our business activities. As part of our commitment to the environment, we conduct 79
environmental impact assessments before building power plants and implement antipollution measures in our power plants at all stages of operation, from planning and design to construction and operation. For example, we have installed various anti-pollution systems, such as electrical dust catchers and Öue gas desulfurization and denitration units, at our coal-Ñred thermal power plants to prevent air, water and soil pollution. As a result, our sulfur oxide and nitrous oxide emissions are signiÑcantly lower than those of many power producers in Europe and the United States. We are proactive in establishing and implementing policies to address global warming, and we view it as one of our most important challenges. Together with the other electric utilities in Japan, we have committed to reducing the amount of CO2 emitted per unit of electricity sales by approximately 20% of that in the year ended March 31, 1991, by the year ending March 31, 2011. We are taking several steps which will help us achieve this goal. We are maintaining and improving the eÇciency of our coal-Ñred thermal power plants, which is already among the world's highest, while developing technologies that allow us to burn coal even more eÇciently. We are making eÇciency enhancements at our hydroelectric power plants. We are currently developing a nuclear power plant that will emit no CO2. Finally, we are also developing and investing in wind, biomass and other renewable energy sources. We believe that a combination of the mechanisms of the Kyoto Protocol and domestic measures to suppress CO2 emissions is the most eÅective way to address global warming. We are developing projects that we seek to make eligible under the Clean Development Mechanism of the Kyoto Protocol and that would produce credits to oÅset our domestic CO2 emissions. Our initial developments include hydro-power, fuel switching, energy eÇciency, biomass-power and landÑll methane capturing and utilization projects in Latin America and Asia. By developing these projects as a key player in the Kyoto credits market, we are not only contributing to create a Öuid Kyoto credits market but also positioning ourselves favorably in that emerging market. We are also cutting waste by recycling and reusing resources. We actively reuse and recycle byproducts from our operations, including ash and gypsum from our coal-Ñred thermal power plants, driftwood from our hydroelectric dam reservoirs and concrete and rock from our construction and repair activities. All of our thermal power plants use recycled water, and we are working to reduce our use of chemicals, lubricants and other pollutants. Our oÇces use recycled paper and other recycled products, and we endeavor to reduce general waste. We have implemented environment maintenance systems in accordance with the ISO14001 standard, the international standard for environmental measures and environmental conservation activities. We provide employees with seminars and training to enhance their awareness of environmental issues. Our Environmental Management Committee works to improve environmental administration groupwide. Additionally, we have streamlined environmental management by introducing an environmental accounting system, and we publish annual environmental activity reports. Research and Development We have pursued advanced research and development in order to increase the eÇciency and competitiveness of our core electricity businesses. We will continue to emphasize the importance of research and development. Our research and development expenses for the years ended March 31, 2002, 2003 and 2004 were Í5,805 million, Í6,333 million and Í6,752 million, respectively. Almost all of these expenses were related to our electric power business. We expect that our future research and development expenses in the near term will be comparable to those incurred in the year ended March 31, 2004. Our research and development focuses on the following areas: Coal-Fired Thermal Power Generation We are developing a coal gasiÑcation electric power generation system that combines fuel cell, gasturbine and steam-turbine technologies to increase generating eÇciency. We are conducting research to eÅectively utilize coal gasiÑcation gas, develop technologies to economically manufacture and utilize this gas and develop a solid oxide fuel battery suitable for use in connection with power generation. 80
Other New Technologies for Power Generation In order to expand our use of pumped-storage hydroelectric power generation, we are developing technologies that would allow us to utilize seawater. We are also developing technologies for the mixed combustion of coal and waste fuel. Technologies EÅective for Reducing Costs In order to reduce our repair and improvement construction costs, we are developing methods to shorten construction periods and technologies to accurately assess facility deterioration. We are also developing technologies for advanced construction methods that may reduce construction costs and methods for increasing the capacity of our existing power plants. Other We are developing technologies to utilize coal ash generated from our coal-Ñred thermal power plants to stabilize soft land. This would reduce the cost of landÑlls. Employees We had a total of 5,871 employees as of March 31, 2004, of which 2,399 were employed in the electric power business and 3,472 were employed in other businesses. The retirement age for our employees is 60. As of July 31, 2004, we had a total of 6,076 employees. As of March 31, 2004, 3,327 of our employees were members of one of nine labor unions. Following the reorganization of our consolidated subsidiaries on April 1, 2004, our labor unions were reorganized into seven unions in June 2004. We have not had any major labor disputes in the past and consider our relations with labor unions to be excellent. We have an employee stock ownership plan. An employee can join the plan to purchase our shares with funds deducted from such employee's monthly salary, subject to a maximum of Í100,000 per month, and from bonus payments, subject to a maximum of Í500,000 per bonus. After our privatization and the listing of our shares on the Tokyo Stock Exchange, the plan administrator will begin making open-market purchases of our shares for the account of the plan on a monthly basis. We contribute approximately 5% of the amounts deducted from each participating employee's salary and bonus to the plan funds. In anticipation of our privatization and the listing of our shares, we commenced such deductions in September 1998. Insurance We maintain insurance policies against accidents and disasters with respect to facilities related to our electricity supply business. These policies include coverage against Ñres and a special provision covering certain direct damage from earthquakes. Legal Proceedings On March 16, 1999, 57 landowners Ñled a lawsuit with the Gifu District Court, naming the Minister of Construction (now the Minister of Land, Infrastructure and Transport) as defendant and seeking the nulliÑcation of its approval of our Tokuyama Dam project, which approval was given by the defendant based on the Land Expropriation Law. As the applicant for the approval, both the Water Resources Development Public Corporation (now the Japan Water Agency) and we are involved in this litigation, each participating in the proceedings as quasi-parties. A verdict in favor of the defendant was handed down on December 26, 2003, but the plaintiÅs appealed to the Nagoya High Court on January 7, 2004. Hearings in the case are currently ongoing. On June 18, 2003, we Ñled a lawsuit with the Aomori District Court against 64 co-owners of land constituting part of the planned site for the construction of our Oma nuclear power plant, requesting a division of the common land so we can utilize our share of the land in the construction of the power plant. Hearings in the case are currently ongoing. 81
REGULATION The Company was incorporated in 1952 as a joint stock corporation under the Electric Power Development Promotion Law, or the J-POWER Law. The J-POWER Law regulated the Company's business and operation until October 2, 2003, when it was repealed. During this period the Company was also regulated under the Electricity Utilities Industry Law, or the EUIL, to the extent that it was not inconsistent with the J-POWER Law. Since the repeal of the J-POWER Law, the Company has been regulated principally under the EUIL. The EUIL is the law regulating electricity suppliers in Japan, and the principal governmental authority responsible for the supervision of such electricity suppliers is the METI. This section includes a description of the regulations applicable to wholesale electric utilities, including the Company, under the EUIL and, where appropriate, of the regulations applicable to the Company under the J-POWER Law. See ""The Electricity Industry in Japan Ì Electricity Industry Deregulation in Japan'' with respect to deregulation of the electricity industry. This section also includes an outline of electricity industry regulations applicable to Japanese electricity suppliers. In addition, this section provides a description of environmental regulations applicable to electricity suppliers in Japan. Electricity Suppliers The EUIL classiÑes electricity suppliers into the following four categories: (i) general electric utilities, or the EPCOs, which engage in retail electricity supply to general customers, including large-load customers; (ii) wholesale electric utilities, including the Company, having electric power facilities with total output capacity of more than 2,000 MW, which engage in wholesale electricity supply to EPCOs for retail to general customers; (iii) special electric utilities, which engage in retail electricity supply only to a designated location without using the transmission lines of EPCOs; and (iv) speciÑed-scale electric utilities, or PPSs, which engage in retail electricity supply only to large-load customers. In addition, there are other entities engaging in wholesale electricity supply in Japan which the EUIL classiÑes as wholesale suppliers. Under the EUIL, wholesale suppliers are deÑned as persons, other than EPCOs and wholesale electric utilities, which are engaged in wholesale electricity supply to EPCOs (for retail to general customers) (a) at a volume of more than 1 MW and for a period of 10 years or longer or (b) at a volume of more than 100 MW and for a period of Ñve years or longer. So-called independent power producers, or IPPs, which are appointed as wholesale electricity suppliers to EPCOs through competitive bidding, are included in this category. Public utilities and joint venture utilities (see ""The Electricity Industry In Japan Ì The Structure of Japan's Electricity Industry'') are also included in this category, but are treated as wholesale electric utilities with respect to their wholesale electricity supply to EPCOs for retail to general customers, but only if and to the extent that, as of December 1, 1995, (i) such entity had a long-term electricity supply contract with the relevant EPCO and (ii) permission had been obtained from the Minister of International Trade and Industry (the precursor to the METI) with respect to the electric power facilities used for such supply. Further, there are numerous self-generators in Japan, entities engaging in electricity generation for their own use. In this ""Regulation'' section, the term ""electric power facilities'' means machinery, equipment, dams, waterways, reservoirs, transmission lines and other facilities for generation, transformation, transmission, distribution or use of electricity. Wholesale Electric Utilities Licensing Requirement to Engage in Wholesale Electricity Supply Business Any person who intends to become a wholesale electric utility must obtain a license from the METI to engage in the wholesale electricity supply business. Such person must submit a license application to the 82
METI specifying the EPCO to which the applicant will supply electricity. The application must also specify certain other matters, such as the electric power facilities to be used by the applicant for its wholesale electricity supply business, and must be accompanied by the applicant's business and Ñnancial plans and other prescribed documents. A license to be a wholesale electric utility may not be granted unless certain conditions are met, including that (i) the planned wholesale electricity supply will meet the expected demand, (ii) the applicant has suÇcient Ñnancial basis and technical capability to conduct the planned electricity supply business in an appropriate manner, and (iii) the applicant's business plan is reliable. The license granted by the METI speciÑes the EPCO to which the wholesale electric utility may supply electricity. Any change to such EPCO is subject to a similar licensing requirement. The METI has the authority to revoke this license if the relevant wholesale electric utility violates any provision of the EUIL or any order issued thereunder resulting, in the METI's judgment, in harm to the public interest. The METI may also revoke this license in certain other cases prescribed by the EUIL. Regulation of Corporate Reorganization Business Transfer or Acquisition, Consolidation, Merger and Corporate Split Transfer or acquisition of a wholesale electricity supply business in its entirety, as well as consolidation, merger or corporate split (but only where the wholesale electricity supply business is transferred in its entirety to another entity through corporate split), by a wholesale electric utility will not be eÅective unless such transaction is approved by the METI. The METI's approval may not be given unless the relevant transaction meets the same conditions described with respect to licenses in ""Ì Licensing Requirement to Engage in Wholesale Electricity Supply Business'' above. The transferee of any such wholesale electricity supply business will succeed to the status of the transferring wholesale electric utility prior to that transfer. Disposal of Facilities Generally, if a wholesale electric utility intends to transfer, or create a security interest in, certain facilities used for its wholesale electricity supply business, it must Ñle a notiÑcation with the METI. The transaction may not be consummated until a period of 20 days has passed since the date of receipt of the notiÑcation by the METI, provided that the METI may shorten this 20-day period if the transaction will not, in the METI's judgment, hinder proper operation of the wholesale electricity supply business by the relevant wholesale electric utility. If, however, in the METI's judgment, there is a possibility that such hindrance will occur, the METI may, within the above 20-day period, issue an order to change or cancel the transaction. Suspension or Termination of Business or Dissolution If a wholesale electric utility intends to suspend or terminate all or any part of its wholesale electricity supply business, it must obtain permission from the METI. Furthermore, a resolution for, or shareholders' consent to, dissolution of a wholesale electric utility will not be eÅective unless and until it is approved by the METI. The METI will not grant its permission or approval unless the relevant suspension, termination or dissolution will not, in the METI's judgment, be harmful to the public interest. Regulation of Wholesale Electricity Supply Supply Obligation A wholesale electric utility which has committed itself to supply electricity to a speciÑc EPCO for retail to general customers may not refuse to provide such supply without a justiÑable reason. Mutual Cooperation The EUIL requires that electricity suppliers cooperate with each other, with proper utilization of the capacity of wholesale suppliers, in connection with the development of electric power, supply of electricity and 83
the operation of related electric power facilities in order to contribute to the comprehensive and rational development of an integrated nationwide electricity supply business. In order to implement this framework, each wholesale electric utility is required to Ñle an electricity supply plan with the METI before the commencement of each Ñscal year with respect to its wholesale electricity supply and its construction and operation of electric power facilities. If any change is made to its electricity supply plan, the relevant wholesale electric utility must Ñle a notiÑcation with the METI without delay. The METI may recommend that any wholesale electric utility change its electricity supply plan if such plan is, in the METI's judgment, inappropriate from the viewpoint of the comprehensive and rational development of an integrated nationwide electricity supply business. In such case, the METI may also, where necessary and appropriate in the METI's judgment, issue an order requiring the relevant wholesale electric utility to take certain measures, including the supply of electricity to a speciÑc EPCO. Under the above framework, upon the occurrence of a natural disaster or other emergency situation, if the METI deems it necessary and appropriate for the protection of the public interest, it may order a wholesale electric utility (i) to supply electricity to another electricity supplier (other than a wholesale electric utility), (ii) to conduct commissioned transmission services to another electricity supplier, or (iii) to lease, borrow or jointly use electric power facilities. Regulation of Terms and Conditions of Wholesale Electricity Supply NotiÑcation of Terms and Conditions Generally, wholesale electric utilities must Ñle with the METI the fees and other terms and conditions of their wholesale electricity supply, and their wholesale electricity supply must be carried out upon the terms and conditions so Ñled with the METI. A person Ñling such terms and conditions may not commence wholesale electricity supply until a period of 20 days has passed since the date of receipt by the METI of such Ñling, provided that the METI may shorten this 20-day period if it judges that the relevant terms and conditions meet all the conditions described in (i) through (iv) below: (i)
the fees are calculated on a fair cost under eÇcient management plus fair return on capital basis;
(ii) the fees are clearly stipulated in the form of either Ñxed fees or Ñxed amounts for the respective types of supply; (iii) matters concerning the respective responsibilities of the wholesale electric utility and the EPCO(s), as well as the manner of allocation of costs relating to electricity meters and other instruments and electrical wiring and other related work, are properly and clearly provided in the terms and conditions; and (iv) the terms and conditions do not provide for unfair discriminatory treatment of any speciÑc person. If, in the METI's judgment, any of the above conditions is not met, the METI may, within the above 20-day period, issue an order to change the relevant terms and conditions. See ""Management's Discussion and Analysis of Financial Condition and Results of Operations Ì Factors AÅecting Our Results of Operations Ì Operating Revenues Ì Electric Power Segment Ì Electricity Fees'' with respect to the regulation of electricity fees. Order to Change Terms and Conditions If the METI judges that any fee or other term or condition of wholesale electricity supply by any wholesale electric utility has become materially inappropriate due to any change in social or economic conditions and that such situation hinders the promotion of the public interest, then the METI may order such wholesale electric utility to change the terms and conditions of its wholesale electricity supply. The ordered change must be made within a reasonable period, as designated by the METI, and if the relevant wholesale electric utility fails to comply with the order within the designated period, the METI may unilaterally change the relevant terms and conditions. 84
Financial Regulation Depreciation and Amortization The METI has authority to order any wholesale electric utility to prescribe and apply the amount and manner of (i) amortization of its Ñxed assets used for the electricity business or (ii) any provisions or reserves, in the event that the METI deems provisions or reserves necessary for the proper operation of the electricity supply business. Reserve for Fluctuation in Water Levels If the electricity supply-related operating revenues of any wholesale electric utility increase or its electricity supply-related operating expenses decrease in any Ñscal year as a result of an increase in the volume of electricity generated at its hydroelectric power plants in excess of a certain level prescribed by regulations under the EUIL due to an increase in streamÖow, such wholesale electric utility must set aside an amount equal to this increase in electricity supply-related operating revenues or decrease in electricity supply-related operating expenses as a ""reserve for Öuctuation in water levels'' until the reserve reaches a certain maximum amount prescribed by regulations under the EUIL. In general, the reserve for Öuctuation in water levels set aside by a wholesale electric utility may not be used for any purpose except when and to the extent that its electricity supply-related revenues decrease or its electricity supply-related expenses increase in any Ñscal year as a result of a decrease in the volume of electricity generated at its hydroelectric power plants below a certain level prescribed by regulations under the EUIL due to a decrease in streamÖow. Reserves for Öuctuation in water levels thereby serve as a means for wholesale electric utilities to help stabilize the results of operations of their wholesale electricity supply business. Regulation Relating to Security Maintenance of Facilities Wholesale electric utilities must maintain their electric power facilities in conformity with technical standards prescribed by regulations under the EUIL. If any electric power facility does not meet such technical standards, the METI may order the relevant wholesale electric utility to repair, rebuild or transfer the relevant electric power facility or to suspend or restrict its use thereof. Security Rules Wholesale electric utilities must establish security rules relating to construction, maintenance and operation of electric power facilities in accordance with regulations under the EUIL. Wholesale electric utilities must also Ñle their security rules with the METI in advance of commencement of use or, as the case may be, construction of the relevant electric power facilities. Any amendment by a wholesale electric utility of its security rules is subject to the same Ñling requirement. The METI may order any wholesale electric utility to change its security rules when the METI deems such change necessary in order to maintain security in connection with the construction, maintenance and operation of electric power facilities. Appointment of Chief Engineer A wholesale electric utility must appoint a qualiÑed chief engineer at each facility, as prescribed by regulations under the EUIL, and must notify the METI of such appointment without delay. Discharge of any chief engineer is subject to the same notiÑcation requirement. Chief engineers must diligently supervise security in connection with the construction, maintenance and operation of electric power facilities. Approval Requirement for Construction Generally, a wholesale electric utility that intends to undertake construction work relating to its electric power facilities, or any change related to its electric power facilities, must Ñle a notiÑcation with the 85
METI with respect to its construction plan. Where the planned construction or change to electric power facilities involves a nuclear power plant, however, the wholesale electric utility must Ñrst obtain the approval of the METI before undertaking any such construction or change. The METI's approval must be given if the construction plan meets certain technical and environmental requirements prescribed by the EUIL. Construction work subject to a notiÑcation requirement may not start until a period of 30 days, or such longer period as may be designated by the METI, has passed since the date of receipt of the notiÑcation by the METI, although the METI may shorten such period if the construction plan meets certain technical and environmental requirements prescribed by the EUIL. If the METI judges that any of those requirements are not met, it may issue an order within such period to change or cancel the construction plan. Inspection Wholesale electric utilities are required to conduct self-inspections of their electric power facilities before using them. In addition, wholesale electric utilities are required to conduct periodic self-inspection of boilers and turbines used for power generation. For instance, steam turbines for thermal power plants must be inspected once every four years and boilers must be inspected once every two years. In the case of nuclear power plants, inspection by the METI is required in addition to these self-inspections. General Supervision by the METI The METI audits the operations and accounting of wholesale electric utilities every Ñscal year. To the extent necessary for enforcement of the EUIL, the METI may require a wholesale electric utility to submit reports and materials concerning its operations and accounting, and government oÇcials may have access to a wholesale electric utility's oÇces, facilities, books, documents and other materials. Regulation of the Company Until the J-POWER Law was repealed on October 2, 2003, the Company was regulated principally under the J-POWER Law and it was engaged in the wholesale electricity supply business under a license granted under the EUIL. Since the repeal of the J-POWER Law, the Company has been regulated principally under the EUIL as a regular wholesale electric utility. The regulations provided under the J-POWER Law were substantially more stringent than those provided under the EUIL. For instance, the Company was required under the J-POWER Law to obtain approval from the METI with respect to, among other things, the following corporate actions: ‚
establishment of and changes in annual business plans
‚
appointment and removal of directors and corporate auditors
‚
commencement of new businesses
‚
transfers and leases of, and creation of any security interest or other right in, electric power facilities
‚
borrowings with a term of more than one year
‚
appropriations of proÑts
‚
issuances and oÅerings of bonds
‚
issuances of new shares
‚
amendments to the Articles of Incorporation of the Company
‚
consolidations, mergers and corporate splits
‚
resolution for dissolution 86
The J-POWER Law also required that the Government of Japan hold at least one half of the Company's issued shares. The above regulations ceased to be eÅective upon the repeal of the J-POWER Law, but transitional treatment is provided in the Law Partially Amending the Electricity Utilities Industry Law and the Gas Utilities Industry Law, as described below.
Wholesale Electricity Supply The J-POWER Law required the Company to obtain approval from the METI with respect to the terms and conditions of its wholesale electricity supply. Under the EUIL, no such approval requirement is imposed on wholesale electric utilities. Instead, wholesale electric utilities are only required to Ñle the terms and conditions of their wholesale electricity supply with the METI. Under the Law Partially Amending the Electricity Utilities Industry Law and the Gas Utilities Industry Law, the terms and conditions of the Company's wholesale electricity supply approved by the METI under the J-POWER Law are deemed to have satisÑed such Ñling requirement under the EUIL described above.
Statutory Lien Under the J-POWER Law, holders of bonds issued by the Company had a statutory lien over all of its assets. The Law Partially Amending the Electricity Utilities Industry Law and the Gas Utilities Industry Law provides that the statutory liens created for the bonds issued by the Company before the repeal of the J-POWER Law will continue to be eÅective. No statutory lien will be created for bonds to be issued by the Company after the repeal of the J-POWER Law because the EUIL contains no provision for statutory liens with respect to bonds issued by wholesale electric utilities.
Regulatory Outline All electricity suppliers and wholesale suppliers are subject to regulations pursuant to the EUIL under the METI's supervision. The extent of the regulations, however, varies depending upon the type of supplier. The table below sets forth a summary of the applicability of the respective regulations. In this table, ""yes'' means that the relevant category of regulation applies to the relevant supplier in a manner substantially similar to that described with respect to the same category of regulation under ""Ì Wholesale Electric Utilities'' above, and ""no'' means that such regulation does not apply to the relevant supplier.
Category of regulation Licensing requirement to engage in electricity supply businessÏÏÏÏÏÏÏÏÏÏÏ
Wholesale suppliers (including IPPs)
Wholesale electric utilities
EPCOs
Special electric utilities
Yes
Yes
Yes
No (1)
No
PPSs
Regulation of corporate reorganization: Business transfer or acquisition, consolidation, merger and corporate split ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Disposal of facilitiesÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Suspension or termination of business or dissolutionÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Yes Yes
Yes Yes
Yes No
No No
No No
Yes
Yes
Yes
No
No
Regulation of electricity supply: Supply obligation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Mutual cooperation ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Yes Yes
Yes Yes
Yes Yes
No Yes
No No
87
Category of regulation
Wholesale electric utilities
EPCOs
Special electric utilities
PPSs
Wholesale suppliers (including IPPs)
Regulation of terms and conditions of electricity supply: NotiÑcation of terms and conditions Terms and conditions of retail electricity supplyÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Terms and conditions of wholesale electricity supplyÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Order to change terms and conditions
No
No(2)
Yes
No
No
Yes Yes
Yes Yes
No No
No No
Yes Yes
Financial regulation: AmortizationÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Reserve for Öuctuation in water levels
Yes Yes
Yes Yes
Yes Yes
No No
No No
Regulation relating to securityÏÏÏÏÏÏÏÏÏ
Yes
Yes
Yes
Yes
Yes
General supervision by the METI ÏÏÏÏÏÏ
Yes
Yes
Yes
Yes
No
Notes: (1) PPSs, although not subject to a licensing requirement, are required to give prior notice to the METI of intent to engage in the electricity supply business. (2) In general, terms and conditions relating to retail supply of electricity by EPCOs are subject to prior approval by the METI. Amendments to such terms and conditions that reduce fees and in certain other cases that are unlikely to jeopardize the interests of retail customers are, however, subject only to a notiÑcation requirement. The establishment and amendment of ""selective service rate'' and ""last resort terms and conditions'' referred to in ""The Electricity Industry in Japan Ì Rates System Ì EPCOs'' above are also subject to a notiÑcation requirement.
Environmental Regulation Environmental Laws Under the Environmental Impact Assessment Law of Japan and the EUIL, any person who intends to construct or alter a large scale electric power facility, or a facility holder, must in general conduct an environmental impact assessment before commencing the construction or alteration. For the purpose of the environmental impact assessment, a facility holder must Ñrst prepare an assessment plan describing, among other matters, the items, such as air and water pollution, with respect to which environmental impact assessment will be conducted, as well as the manner of study, projection and assessment. Upon completion of the environmental impact assessment, the facility holder must prepare a preparatory statement describing, among other matters, the results of the study, projection and assessment, as well as the measures to be taken for the protection of the environment. Each of the assessment plan and the preparatory statement must be submitted to the relevant local governors and mayors and must also be published in order to seek public comment. Such plan and statement must also be submitted to, and examined by, the METI. In examining the preparatory statement, the METI must seek an opinion from the Minister of the Environment of Japan. The METI may issue a recommendation to the facility holder in connection with the environmental impact assessment within 180 days, in the case of the assessment plan, and 270 days, in the case of the preparatory statement, from the date of its receipt of the relevant plan or statement. In addition, the facility holder must prepare an evaluation report describing the measures to be taken to protect the environment, any comments received by the facility holder from the public, the local governors' opinion, and the facility holder's own opinion, relating to the environmental impact assessment conducted by it. The facility holder must submit the evaluation report to the METI for examination. If the METI Ñnds it necessary and appropriate to change the evaluation report in order to ensure that proper consideration is given for the protection of the environment, it may, within 30 days of the date of its receipt of the evaluation report, issue an order to change the report. If the METI Ñnds it unnecessary to issue such order, it will give notice thereof to the facility holder. Upon receipt of the notice, the facility holder must submit the evaluation report to the local governors and mayors and publish the same. 88
The facility holder must pay due regard to the local governors' opinions and the public comments received by it in the process of conducting its environmental impact assessment. NotiÑcation or application for approval in respect of the construction or alteration of electric power facilities, as described in ""Ì Wholesale Electric Utilities Ì Regulation Relating to Security Ì Approval Requirement for Construction'' above, may be Ñled only after the completion of all necessary steps in connection with an environmental impact assessment under the Environmental Impact Assessment Law. The Company is subject to the above requirements of the Environmental Impact Assessment Law and the EUIL when it constructs or alter its electric power facilities. The Company is also subject to various other Japanese laws regulating environmental issues, such as the Law Preventing Air Pollution, the Natural Park Law and the Law Protecting Natural Environment. In addition, many local governments have their own environmental regulations, which sometimes impose more stringent obligations on the Company than those imposed under the above laws.
Kyoto Protocol The Kyoto Protocol, or the Protocol, to the United Nations Framework Convention on Climate Change, or the Convention, was adopted on December 11, 1997 in pursuit of the ultimate objective of the Convention to achieve stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. ""Greenhouse gases'' are those gaseous constituents of the atmosphere, both natural and anthropogenic, that absorb and re-emit infrared radiation and include carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydroÖuorocarbons (HFCs), perÖuorocarbons (PFCs) and sulfur hexaÖuoride (SF6). The Protocol has not yet become eÅective and will enter into force on the 90th day after the date on which not less than 55 parties to the Convention, incorporating the parties included in Annex I to the Convention, or the Annex I Countries, which accounted in total for at least 55% of the total carbon dioxide emissions for 1990 of the Annex I Countries, have deposited their instruments of ratiÑcation, acceptance, approval or accession with the Secretary-General of the United Nations. Japan, which is an Annex I Country, executed the Protocol on April 28, 1998 and deposited its instrument of acceptance on June 4, 2002. The Protocol assigns a quantiÑed emission limitation and reduction commitment with respect to the aggregate anthropogenic carbon dioxide equivalent emissions of greenhouse gases to each of the Annex I Countries, which consist mainly of developed countries. The Protocol requires that the Annex I Countries individually or jointly ensure that their emissions do not exceed their assigned amounts, calculated pursuant to their quantiÑed emission limitation or reduction commitments, with a view to reducing their overall emissions of greenhouse gases by at least 5% below 1990 levels in the commitment period, from 2008 to 2012. The assigned amount for Japan pursuant to the Protocol is 94% of its 1990 levels. The Protocol permits the parties to the Convention to use various mechanisms to achieve the objective of the Convention, as described below.
Joint Implementation Any Annex I Country may transfer to, or acquire from, any other Annex I Country emission reduction units resulting from projects aimed at reducing anthropogenic emissions by sources or enhancing anthropogenic removals by sinks of greenhouse gases in any sector of the economy.
Clean Development Mechanism This mechanism is designed to assist the parties to the Protocol other than the Annex I Countries to achieve sustainable development and contribute to the ultimate objective of the Convention, as well as to assist the Annex I Countries in achieving compliance with their quantiÑed emission limitation and reduction commitments under the Protocol. Under this mechanism, any Annex I Country may engage in project activities that will be beneÑcial to any other party to the Protocol, other than the Annex I Countries, resulting in certiÑed emission reductions, which reductions may be used by such Annex I Country to contribute to compliance with part of its quantiÑed emission limitation and reduction commitments under the Protocol. 89
Emission Trading The parties included in Annex B to the Protocol, most of which are also Annex I Countries, may participate in emissions trading for the purposes of fulÑlling their commitments under the Protocol. The Protocol has no provision for speciÑc penalties or sanctions to be imposed on parties to the Protocol in case of non-compliance with the provisions of the Protocol. The Protocol provides, however, that procedures and mechanisms to determine and to address cases of such non-compliance entailing binding consequences will be adopted by means of an amendment to the Protocol. In Japan, the Law Concerning the Promotion of the Measures to Cope with Global Warming was enacted in October 1998, providing, among other things, that entrepreneurs shall jointly or severally make eÅorts to prepare and publish plans relating to the measures to be taken for controlling the emission of greenhouse gases. Following the acceptance of the Protocol by Japan, this law was amended with reference to the Protocol, but most of the amended provisions will not become eÅective until the Protocol comes into force. In each year since 1996, all of the EPCOs and the wholesale electric utilities have jointly published an action plan in which they state that they will make eÅorts to reduce emissions of CO2, with the goal of reducing their overall emissions of CO2 per kWh of electric power used by customers in the year ending March 31, 2011 to approximately 20% below the level in the year ended March 31, 1991.
90
SUBSIDIARIES AND AFFILIATES The Company conducts its business together with its subsidiaries (being companies over which the Company exerts substantial control through either majority ownership of voting stock or by other means) and aÇliates (being companies over which the Company has the ability to exercise signiÑcant inÖuence with respect to Ñnances, operations or business). At March 31, 2004, the Company had 46 subsidiaries, 13 of which were consolidated. At the same date, the Company had 36 aÇliates, 11 of which were accounted for using the equity method. The following table presents information on J-POWER's 13 consolidated subsidiaries and principal aÇliates as of March 31, 2004. Name of company Consolidated subsidiaries: ITOIGAWA POWER Inc. Denpatsu Holding Company Ltd.(1) Kaihatsu Denki Co., Ltd.(2) Kaihatsu Koji Co., Ltd.(2) Kaihatsu Denshi Gijutsu Co., Ltd. Denpatsu Kankyo Ryokka Center Co., Ltd.(2)(4) EPDC CoalTech and Marine Co., Ltd.(2) Kaihatsu Sekkei Consultant Co., Ltd. EPDC Overseas Coal Co., Ltd.(5) EPDC (Australia) Pty. Ltd.(6) EPDC Industrial Co., Ltd.(2) The Kaihatsu Keisan Center Co., Ltd.(2) J-Power Investment Netherlands B.V. AÇliates accounted for by the equity method: Gulf Electric Public Co., Ltd. Gulf Cogeneration Co., Ltd. Gulf Power Generation Co., Ltd.
Main businesses
Paid-in capital (millions)
J-POWER interest (%)
Investment in domestic IPP projects
Í
1,006
80
Management of certain aÇliates and subsidiaries
Í
120
100
Construction, technical development, design, consulting, maintenance and research for power plants, substations and transmission lines Boring, grouting, surveying and other civil engineering and construction services Construction and maintenance of electronic and communications facilities Research, construction and maintenance for environmental engineering; surveying and compensation of construction sites; research and planning of environmental conservation Unloading and transporting of coal to thermal power plants; disposition of ash; sales of fried ash; shipping of coal for thermal power plants Design and construction management of electric power facilities; engineering and construction Research, exploration and development of, and investments in coal mines Investments in coal mines in Australia
Í
500
100
Í
300
100
Í
110
100
Í
10
100
Í
20
100
Í
20
100
Í
1,000
100
A$*
10
100
Management of welfare facilities and buildings
Í
310
100
Development of computer software
Í
120
100
Management of overseas investments
4
50
100
Holding company for thermal power generation companies Operation of gas cogeneration facilities
THB* 4,254(7)
49
THB*
850
49
THB*
577
49
Construction and operation of thermal power plants
91
Name of company Samutprakarn Cogeneration Co., Ltd. Nong Khae Cogeneration Co., Ltd. Gulf Yala Green Co., Ltd. Trang Biomass Co., Ltd. Thaioil Power Co., Ltd. Independent Power (Thailand) Co., Ltd. SEC HoldCo, S.A. Chiahui Power Corporation
Operation of gas cogeneration facilities
Paid-in J-POWER capital interest (millions) (%) THB* 981 49
Operation of gas cogeneration facilities
THB* 1,241
49
Construction and operation of bio-mass generation power plants Construction and operation of bio-mass power plants Operation of gas cogeneration facilities
THB*
200
47
THB* 0.25
49
THB* 2,810
19
Operation of gas combined cycle power plants
THB* 1,771
11
Operation of wind power generation facilities Operation of gas combined cycle power plants
4* 3.6 NT$* 4,300
50 40
Main businesses
Notes: (1) On April 1, 2004, Denpatsu Holding Company Ltd. merged into the Company. (2) On April 1, 2004, EPDC Industrial Co., Ltd. merged with The Kaihatsu Keisan Center Co., Ltd. and the surviving entity changed its name to JP Business Service Corporation (and increased its paid-in capital to Í450 million on August 1, 2004 from Í430 million), Kaihatsu Koji Co., Ltd. acquired the compensation department, the hydroelectric facilities maintenance department and the transmission facilities maintenance department of Denpatsu Kankyo Ryokka Center Co., Ltd. and the hydroelectric, transmission and transformation department of Kaihatsu Denki Co., Ltd. through a corporate split and the surviving entity changed its name to JPHYTEC Co., Ltd. (paid-in capital Í500 million), and Kaihatsu Denki Co., Ltd. acquired the environmental aÅorestation department of Denpatsu Kankyo Ryokka Center Co., Ltd. and the coal unloading and transporting and coal marine transporting department of EPDC CoalTech and Marine Co., Ltd. through a corporate split and the surviving entity changed its name to JPec Co., Ltd. (paid-in capital Í500 million). (3) During the year ending March 31, 2005, the following companies are expected to become consolidated subsidiaries: Ichihara Power Co., Ltd., Nikaho-kogen Wind Power Co., Ltd., Green Power Kuzumaki Co., Ltd., NagasakiShikamachi Wind Power Co., Ltd., Green Power Aso Co., Ltd., J-Wind TAHARA Ltd., Dream-Up Tomamae Co., Ltd. and JPOWER GENEX CAPITAL Co., Ltd. Also, GENEX COMPANY, LIMITED is expected to become an equity method aÇliate during the year ending March 31, 2005. (4) The dissolution of Denpatsu Kankyo Ryokka Center Co., Ltd. was resolved on April 5, 2004 and completed on June 14, 2004. (5) EPDC Overseas Coal Co., Ltd. changed its name to J-POWER RESOURCES Co., Ltd. as of July 1, 2004. (6) EPDC (Australia) Pty. Ltd. changed its name to J-POWER AUSTRALIA PTY. LTD. as of August 1, 2004. (7) Gulf Electric Public Co., Ltd. increased its capital on June 11, 2004 to THB 4,574 million. J-POWER's interest in this aÇliate is unchanged at 49%. * A$ refers to Australian dollars, THB refers to Thai baht, 4 refers to the Euro and NT$ refers to new Taiwan dollars.
92
MANAGEMENT Our Board of Directors has the ultimate responsibility for our administration. Our Articles of Incorporation provide for a Board of Directors consisting of no more than 13 members. Directors are elected at general meetings of shareholders and the normal term of oÇce is two years although they may serve any number of consecutive terms. The Board of Directors may elect, from among its members, a President, one or more Executive Vice Presidents and Executive Managing Directors. The President is a Representative Director, and one or more additional Representative Directors may be elected by the Board of Directors from among its members. Each of the Representative Directors has the authority to represent us in the conduct of our aÅairs. In 2003, we amended our Articles of Incorporation to reduce our authorized number of directors from 20 to 13. We reduced our actual number of directors over time from 19 in 2001 to 12 in 2004. Our Articles of Incorporation provide for no more than four corporate auditors. Corporate auditors are elected at general meetings of shareholders and their normal term of oÇce is four years, although they may serve any number of consecutive terms. Corporate auditors elect from among themselves one or more fulltime corporate auditors. Corporate auditors are not required to be certiÑed public accountants, but the Commercial Code of Japan, or the Commercial Code, provides that they may not be our current employees or directors or current employees or directors of our subsidiaries, and requires that at least one of them be a person who was not one of our directors or employees or a director or employee of one of our subsidiaries during the Ñve-year period prior to such corporate auditor's election (and, after the close of the ordinary general meeting of shareholders to be held for the year ending on March 31, 2006, at least half of them must be persons who have not been one of our directors or employees or a director or employee of one of our subsidiaries). One of our three corporate auditors meets this requirement and has no history of prior employment with us or any of our subsidiaries. Pursuant to the requirements of the Commercial Code, we have a Board of Corporate Auditors which is charged with overseeing our aÅairs. It is the duty of each corporate auditor to examine the administration of our aÅairs by our directors as well as the Ñnancial statements and business reports submitted by a Representative Director to the general meeting of shareholders and to report to the Board of Corporate Auditors his or her opinion on the results of such examinations. The Board of Corporate Auditors then reports to a Representative Director its opinion on the results of such examinations. The corporate auditors are required to attend meetings of the Board of Directors and express opinions at such meetings, but they are not entitled to vote on matters decided by the Board of Directors. Under the Commercial Code, our directors and corporate auditors are liable for any damage suÅered by us as a result of their violation of laws or regulations or any failure to perform their duties. Under our Articles of Incorporation, such liability may, except in the case of willful misconduct or gross negligence or in certain other cases, be limited by resolution of the Board of Directors or also, for outside directors (if appointed), by a liability limitation agreement entered into between him/her and us, up to an amount to be calculated in accordance with the relevant provisions of the Commercial Code with reference to annual remuneration, retirement allowance and proÑts received upon exercise or transfer of stock options, if any. The Commercial Code permits the liability of outside directors to be capped at an amount lower than that applicable to other directors. We must appoint independent auditors in addition to the corporate auditors under current Commercial Code requirements. Such independent auditors have statutorily mandated duties with respect to the examination of the Ñnancial statements proposed to be submitted by a Representative Director to general meetings of shareholders. Our independent auditors must also report on these Ñnancial statements to the Board of Corporate Auditors and the directors. Currently, our independent auditors are Ernst & Young Shin Nihon. The following table presents information regarding our current directors and corporate auditors:
93
Directors and Corporate Auditors Name
Position (1)
Yoshihiko Nakagaki ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ President Youki Kawata(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Vice President Hisao Nakagami(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Vice President Katsuhiko Miyashita(1) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Vice President Akinobu Yasumoto ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Managing Director Kiyoshi Sawabe ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Managing Director Masayoshi Kitamura ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Managing Director Masashi Hatano ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Director Akio Ushio ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Director Yasuo Maeda ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Director Kanji Shimada ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Director Yoshihiko Sakanashi ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Executive Director Masayuki Hori ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Senior Corporate Auditor (full-time) Takeshi Sone ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Corporate Auditor (full-time) Yasuo Matsushita ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Corporate Auditor (external)
Director/Auditor since June June June June June June June June June June June June June June June
1996 2001 1998 2000 2001 2001 2001 2004 2004 2004 2004 2004 2004 2003 2000
Note: (1) Representative Director.
Yoshihiko Nakagaki became our President in June 2001. Previously, Mr. Nakagaki acted as our Executive Vice President from June 2000, the Executive Managing Director from June 1998 and the Executive Director and the Department Director of our Corporate Planning & Administration Department from June 1996. He has also been a Representative Director since June 2000. Youki Kawata became one of our Executive Vice Presidents in June 2001 and has also been one of our Representative Directors since then. Prior to that, Mr. Kawata was a member of the Board of Directors of Sumitomo Metal Industries, Ltd., serving as a Vice President from June 2000, an Executive Managing Director from June 1998 and an Executive Director from June 1997 and he was also the Director-General of the Agency for Natural Resources and Energy from February 1994 to June 1995. Hisao Nakagami became one of our Executive Vice Presidents in June 2003 and has also been one of our Representative Directors since then. Previously, Mr. Nakagami acted as one of our Executive Managing Directors from June 2000 and as one of our Executive Directors from June 1998. Katsuhiko Miyashita became one of our Executive Vice Presidents in June 2004. Previously, Mr. Miyashita acted as one of our Executive Managing Directors from April 2002 and one of our Executive Directors from June 2000. Akinobu Yasumoto became one of our Executive Managing Directors in June 2004. Previously, Mr. Yasumoto acted as our Executive Director from June 2001. Prior to that, Mr. Yasumoto was the Executive Director of the Global Industrial and Social Progress Research Institute from July 1999, the VicePresident of the Japan International Cooperation Agency from July 1997 and also the Head of Research, Committee on Commerce and Industry, Secretariat of the House of Representatives from June 1996 to July 1997. Kiyoshi Sawabe became one of our Executive Managing Directors in June 2004. Previously, Mr. Sawabe acted as one of our Executive Directors from June 2001. Masayoshi Kitamura became one of our Executive Managing Directors in June 2004. Previously, Mr. Kitamura acted as one of our Executive Directors from June 2001. Masashi Hatano became one of our Executive Directors in June 2004. Previously, Mr. Hatano was the Senior Advisor to the President from June 2003. Akio Ushio became one of our Executive Directors in June 2004. Prior to that, Mr. Ushio was the Director-General of Equity and Investigation Bureau, the Secretariat of the National Personnel Authority, from September 2002. 94
Yasuo Maeda became one of our Executive Directors in June 2004. Previously, Mr. Maeda was the Department Director of our Engineering Department from October 2002. Kanji Shimada became one of our Executive Directors in June 2004. Previously, Mr. Shimada was the Department Director of our General AÅairs Department from June 2003. Yoshihiko Sakanashi became one of our Executive Directors in June 2004. Previously, Mr. Sakanashi was the Department Director of our Business Planning Department from October 2002. Masayuki Hori became one of our Corporate Auditors in June 2004. Previously, Mr. Hori acted as one of our Executive Directors from October 2002, the Executive Director and the Department Director of our Engineering Department from April 2002, an Executive Director and a Department Director of our Engineering Center from July 2001, and the Executive Director and the Department Director of our Construction Department from June 2001. Takeshi Sone became one of our Corporate Auditors in June 2003. Prior to that Mr. Sone was the Department Director of our Finance Department from April 2002. Yasuo Matsushita became one of our Corporate Auditors in June 2000. Prior to that, Mr. Matsushita was the Governor of the Bank of Japan from December 1994, the President of Sakura Bank, Limited from April 1992, the President of The Taiyo Kobe Bank, Limited from June 1987 and the Administrative ViceMinister of the Ministry of Finance from June 1982. Executive Compensation Our aggregate executive compensation, including bonuses paid to our directors and corporate auditors in the aggregate during the year ended March 31, 2004, was Í427 million. In addition, in accordance with customary Japanese business practices, we pay our retiring directors and corporate auditors lump-sum retirement payments, which are subject to approval at our general shareholders meetings. Directors' Stock Ownership Plan We have a directors' stock ownership plan together with six of our consolidated subsidiaries. A director can join the plan to purchase our shares with funds deducted from such director's monthly salary and from such director's bonus payments, subject to maximum amounts. After our privatization and the listing of our shares on the Tokyo Stock Exchange, the plan administrator will begin making open-market purchases of our shares for the account of the plan on a monthly basis. In anticipation of our privatization and the listing of our shares, we commenced such deductions in April 2001.
95
SHAREHOLDERS AND SELLING SHAREHOLDERS Shareholders The following table sets forth the shareholders of the Company appearing in its register of shareholders and the number and percentage of shares held by each of them as of March 31, 2004.
Shareholders of the Company
Shareholder J-POWER Privatization Fund Co., Ltd. ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ The Tokyo Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ The Kansai Electric Power Company, IncorporatedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Chubu Electric Power Company, IncorporatedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Tohoku Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Kyushu Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ The Chugoku Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hokkaido Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Hokuriku Electric Power Company ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Shikoku Electric Power Company, Incorporated ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
Number of Shares held of record (in thousands) 115,291 7,037 5,164 4,460 1,417 1,417 1,415 947 947 713 138,808
Percentage of total issued Shares 83.06% 5.07 3.72 3.21 1.02 1.02 1.02 0.68 0.68 0.51 100%
The Selling Shareholders All of the shares held by the Fund will be sold in the oÅerings and all of the shares held by the Company's other existing shareholders will be sold in the Japanese oÅering. Therefore, upon the completion of the oÅerings, all of the Company's existing shareholders will cease to be shareholders. The Fund was established in October 2003 for the purpose of the privatization of the Company. The Fund is designated under the Law Partially Amending the Electricity Utilities Industry Law and the Gas Utilities Industry Law to acquire, manage and sell the Company's shares. All of the shares of the Company formerly held by the Minister of Finance, which represented 66.69% of the Company's total issued shares, were transferred by the Minister of Finance to the Fund in November 2003, and through the issuance of additional shares to the Fund in December 2003, the Fund's shareholding in the Company increased to 83.06% of the Company's total issued shares. The Fund is to be dissolved after disposing of all the shares held by it (including the additional shares referred to below, if issued) not later than the date to be prescribed by a cabinet ordinance. Once the Fund has disposed of all the shares held by it, the Fund has the power, upon the Company's request and once only, to purchase an additional amount of shares to be newly issued by the Company having a total value up to the amount the Fund received in consideration for its disposal of the shares originally owned by it and calculated based on a computation method established by ministerial ordinance of the Ministry of Finance and the Ministry of Economy, Trade and Industry. We presently have no intention of issuing such new shares to the Fund.
96
Certain Related-Party Transactions As a wholesale electric utility, we sell virtually all the electricity we produce to the ten EPCOs, of which nine are also our shareholders. For the year ended March 31, 2004, 99.7% of our electric power business operating revenues, which accounted for 91% of our total operating revenues, were from the ten EPCOs. The Tokyo Electric Power Company, The Chugoku Electric Power Company and The Kansai Electric Power Company represented 23%, 20% and 19%, respectively, of our electric power business operating revenues, or 21%, 18% and 18%, respectively, of our total operating revenues for the year ended March 31, 2004. We undertake development and construction of new power plants based on basic agreements that we enter into with one or more of the EPCOs. We enter into speciÑc long-term electricity supply contracts with one or more of the EPCOs prior to the commencement of operation of each power plant. Although our nine EPCO shareholders will no longer be our shareholders after their sale of our shares in the Japanese oÅering, we do not believe that this will have any material eÅect on our long-term electricity supply arrangements with them.
97
DESCRIPTION OF THE SHARES The following section contains information relating to the shares, including summaries of provisions of the Company's Articles of Incorporation and share handling regulations, the Commercial Code of Japan relating to joint stock corporations (kabushiki kaisha), and certain related legislation, as currently in eÅect. The following description assumes that the shares will be listed on the Tokyo Stock Exchange. General The Company's authorized share capital consists of 550,000,000 shares of capital stock, of which 138,808,000 shares of common stock have been issued. Under the Commercial Code of Japan, or the Commercial Code, shares are transferable by delivery of share certiÑcates. To assert shareholders' rights against the Company, a shareholder must have its name and address registered in the Company's register of shareholders in accordance with its share handling regulations. Shareholders are required to Ñle their names, addresses and seal impressions with The Sumitomo Trust and Banking Company, Limited which is the transfer agent for the shares. Shareholders not resident in Japan are required to provide a mailing address within Japan or to appoint a standing proxy in Japan. A local standing proxy can usually handle the transfer of shares and registration of purchases and the application for reduced withholding tax. See ""Taxation Ì Japanese Taxation''. JASDEC Clearing System A holder of shares may deposit share certiÑcates representing its shares with the Japan Securities Depository Center, Inc., or JASDEC, the sole depositary under the clearing system, through a participating institution such as a securities company or bank having a clearing account with JASDEC. Participating institutions may deposit share certiÑcates representing shares directly with JASDEC. All shares represented by share certiÑcates deposited with JASDEC will be registered in the name of JASDEC on the Company's register of shareholders. BeneÑcial ownership of the deposited shares will in turn be registered on the register of beneÑcial shareholders prepared by the Company based on information furnished by the participating institutions and JASDEC. The register of beneÑcial shareholders will be updated at the record dates on which shareholders entitled to rights pertaining to the shares are determined. The delivery of share certiÑcates is not necessary for transfer of the deposited shares within JASDEC. The beneÑcial owners of deposited shares registered on the register of beneÑcial shareholders are treated in the same way as shareholders registered on the Company's register of shareholders in general. CertiÑcates for shares newly issued with respect to shares already deposited with JASDEC, including those issued upon stock split of deposited shares, will automatically be deposited with JASDEC together with certiÑcates representing deposited shares. The registered beneÑcial owners may exercise the rights attached to their shares, such as voting rights, and will receive dividends, if any, and notices to shareholders directly from the Company. The shares held by a person as a registered shareholder and those held by the same person as a registered beneÑcial owner are aggregated for these purposes. BeneÑcial owners may at any time withdraw their deposited shares and receive share certiÑcates deposited with JASDEC. Paperless Clearing System In view of the globalization of securities trading, the Government of Japan is seeking to enhance the safety, eÇciency and convenience of the clearing system for securities in Japan. For this purpose, a series of laws has been enacted to establish a uniÑed clearing system for various types of securities and to eliminate certiÑcates representing securities to be traded through this system. A new law to incorporate shares of stock into this ""paperless clearing system'' was promulgated on June 9, 2004 and will come into full force and eÅect on a date, to be designated by a cabinet ordinance, which will occur within Ñve years from the date of promulgation. On this eÅective date, the paperless clearing system is expected to become compulsorily applicable to the shares of all listed companies in Japan. On the same date, all share certiÑcates issued by listed companies will become void and the JASDEC clearing system will terminate, but measures will be taken to ensure a smooth transition to the paperless clearing system with respect to all shares, whether the share certiÑcates are then in the possession of shareholders or JASDEC. The paperless clearing system will be operated by a clearing organization (which may be the same entity as JASDEC), and certain institutions, typically securities companies, will participate in the system directly or indirectly through other participating institutions. Following the application of the paperless clearing system to the shares of all listed companies, shareholders of each listed company will be recorded in 98
such company's register of shareholders. The register of shareholders will be updated at each record date for determining shareholders entitled to dividends and voting rights, and at any other date that may be designated by the company, based on information provided to the company by the clearing organization. Transfer of shares will be eÅected by book-entry in accounts maintained by the transferor and the transferee at participating institutions. The description of the shares below does not contain further information regarding this paperless clearing system, which is not yet applicable to shares of listed companies as of the date of this oÅering circular. Settlement Settlement of a transaction concerning shares listed on any of the stock exchanges in Japan will normally occur on the third trading day after the transaction day. Settlement in Japan is made by physical delivery of share certiÑcates or through JASDEC as described above. Dividends Under its Articles of Incorporation, the Company's Ñscal year ends on March 31 of each year, and the Company may pay year-end dividends, if any, to shareholders (in the case of shares deposited with JASDEC, beneÑcial shareholders registered in the register of beneÑcial shareholders) and pledgees of record as of that date in proportion to the number of shares held by them. The Commercial Code also permits a joint stock corporation to distribute proÑts by interim dividends (i.e., cash distributions) if its Articles of Incorporation so provide. The Company's Articles of Incorporation permit it to pay interim dividends and the Company may pay these interim dividends, if any, to shareholders (in the case of shares deposited with JASDEC, beneÑcial shareholders registered in the register of beneÑcial shareholders) and pledgees of record as of September 30 of each year by resolution of the Board of Directors. Under its Articles of Incorporation, the Company is not obligated to pay any dividends left unclaimed for a period of three years after the date on which they Ñrst became payable. For information as to Japanese taxes on dividends, see ""Taxation Ì Japanese Taxation''. The Commercial Code provides that, until the aggregate of its legal reserve and its additional paid-in capital is at least one-quarter of the stated capital, the Company may not make any distribution of proÑts by way of year-end dividends or interim dividends unless it sets aside in its legal reserve an amount equal to at least one-tenth of any amount paid out by the Company as an appropriation of retained earnings, including any payment by way of year-end dividends and bonuses to directors and corporate auditors, or equal to one-tenth of any interim dividend. The Company may pay year-end dividends out of the excess of its net assets, as appearing on its nonconsolidated balance sheet as at the end of the preceding Ñscal year, over the aggregate of: (i) its stated capital; (ii) its additional paid-in capital; (iii) its accumulated legal reserve; (iv) the legal reserve to be set aside in respect of the dividend concerned and other proposed payments by way of appropriation of retained earnings, if any; and (v) such other amounts as are set out in an ordinance of the Ministry of Justice of Japan. In the case of interim dividends, the Company calculates its net assets by reference to the nonconsolidated balance sheet at the last Ñscal year end. The net assets, however, are adjusted to reÖect: (a) any subsequent payment made by appropriation of retained earnings and transfer to legal reserve following the appropriation; (b) any subsequent transfer of retained earnings to stated capital; (c) if a resolution of an ordinary general shareholders' meeting has authorized the Company to acquire its own shares, the total purchase price of those shares so authorized to be paid by the Company; and 99
(d) if the Board of Directors resolves the acquisition of its own shares, the total amount of the purchase price of such shares resolved by the Board of Directors. The Company may not pay any interim dividends where there is a risk that at the end of the Ñscal year net assets might be less than the aggregate of the amounts referred to in (i) through (v) above. If the Company reduces the amount of its stated capital, additional paid-in capital or accumulated legal reserve after the end of the latest Ñscal year-end, the amount so reduced, less the amount paid to shareholders upon such reduction and certain other amounts, and such other amounts as are set out in an ordinance of the Ministry of Justice of Japan, will be added to the amount distributable as interim dividends as described above. In Japan, the ex-dividend date and record date for dividends precede the date of determination of the amount of the dividend. The price of shares generally goes ex-dividend on the third business day prior to the record date.
Capital and Reserves The entire amount of the issue price of any new shares is required to be accounted for as stated capital, although the Company may account for an amount not exceeding one-half of such issue price as additional paid-in capital. The Company may at any time transfer the whole or any part of the additional paidin capital and legal reserve to stated capital by resolution of the Board of Directors. The whole or any part of retained earnings which may be distributed as year-end dividends may also be transferred to stated capital by resolution of an ordinary general meeting of shareholders. The Company may reduce stated capital by special resolution of a general meeting of shareholders, as discussed under ""Ì Voting Rights''. The Company may also reduce additional paid-in capital and/or legal reserve by resolution of a general meeting of shareholders, provided that the sum of additional paid-in capital and legal reserve remaining after such reduction may not be less than one-quarter of the Company's stated capital.
Acquisition by the Company of its Own Shares The Company may acquire its own shares (i) by way of purchase on the public stock markets or by way of tender oÅer (in either case, pursuant to an ordinary resolution of an ordinary general meeting of shareholders or by resolution of the Board of Directors); (ii) from speciÑc shareholders, other than the Company's subsidiaries (pursuant to a special resolution of the ordinary general meeting of shareholders); or (iii) from the Company's subsidiaries (pursuant to a resolution of the Board of Directors). In the case of (ii) above, any other shareholder may make a request directly to a director in writing, Ñve days prior to the relevant shareholders' meeting, to add him or her as the sellers of shares in the proposed purchase. Any such acquisition of shares must satisfy certain requirements, including that the total amount of the purchase price may not exceed the amount of the retained earnings available for year-end dividend payments after taking into account any reduction of the stated capital, additional paid-in capital or legal reserve (if such reduction is authorized by a resolution of the relevant general meeting of shareholders), less the sum of the amount to be paid by way of appropriation of retained earnings and the amount of retained earnings to be transferred to the stated capital in respect of the relevant Ñscal year pursuant to a resolution of such general meeting of shareholders. In the case of the purchase by the Company of its own shares pursuant to a resolution of the Board of Directors mentioned in (i) or (iii) above, however, the total amount of the purchase price of such shares may not exceed the amount distributable as interim dividends as described in ""Ì Dividends'', less the amount of the interim dividend actually paid by the Company. However, if it is anticipated that the net assets, as stated on its non-consolidated balance sheet at the end of the Ñscal year, will be less than the aggregate amount of items described in (i) to (v) in ""Ì Dividends'' above, the Company may not purchase such shares. In addition, the Company may acquire its own shares by: ‚
repurchase of shares constituting less than one unit (or fractional shares, but only if the Company abolishes its existing unit share system and adopts a fractional share system) upon the request of their holder; 100
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redemption of redeemable shares (if the Company issues redeemable shares); or
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merger or corporate split.
The Company may hold its own shares which it has acquired in compliance with the provisions of the Commercial Code, and may generally dispose of or cancel such shares by a resolution of the Board of Directors, subject to the same limitations as to the issuance of stock at a ""specially favorable'' price as discussed under ""Ì Voting Rights'' and ""Ì Stock Acquisition Rights'' below.
Stock Splits The Company may at any time split the shares into a greater number of shares by resolution of the Board of Directors. When the Board of Directors approves a stock split, it may also amend the Articles of Incorporation of the Company without shareholders' approval to increase the number of authorized shares in proportion to the stock split. Upon stock splits, shareholders will not be required to exchange share certiÑcates held by them for new share certiÑcates. In respect of deposited shares, new shares resulting from the stock split will be deposited with JASDEC, and shareholders who directly possess share certiÑcates will receive additional certiÑcates representing the additional shares resulting from the stock split. Before a stock split, the Company must give public notice of the stock split, specifying the record date for the stock split, not less than two weeks prior to the record date. In addition, promptly after the stock split takes eÅect, the Company must send notice to each shareholder specifying the number of entitled shares.
Consolidation of Shares The Company may at any time consolidate the shares into a smaller number of shares by a special resolution of the general meeting of shareholders. A Representative Director must disclose the reason for the consolidation of the shares at the general meeting of shareholders.
Unit Share System The Articles of Incorporation of the Company provide that 100 shares constitute one ""unit'' of shares. The Board of Directors is permitted to reduce the number of shares that will constitute a unit or abolish the unit share system entirely by amending the Articles of Incorporation of the Company without shareholders' approval. The number of shares constituting a unit may not exceed 1,000 shares or 1/200 of the number of all issued shares, whichever is smaller. The Articles of Incorporation and the share handling regulations of the Company provide that no share certiÑcates shall, in general, be issued with respect to any shares constituting less than one unit. Consequently, no certiÑcates for shares other than those constituting a full unit or an integral multiple thereof will be issued, except that the Company may issue such certiÑcates (i) in the event of stain, mutilation or expiration of, or insuÇciency of space for entry of shareholders' names on, existing certiÑcates representing shares constituting less than one unit, or (ii) if it is in the Company's judgment necessary to issue such certiÑcates for protection of the holders of shares constituting less than one unit. As the transfer of shares normally requires delivery of the relevant share certiÑcates, any shares constituting less than one unit for which no share certiÑcates are issued will not be transferable. A holder of shares constituting less than one unit may require the Company to purchase such shares (i) at the reported closing price of the shares on the Tokyo Stock Exchange on the day when the request for purchase arrived at the business handling oÇce of the transfer agent or its liaison oÇce or (ii) if on such day no shares are traded on the Tokyo Stock Exchange, at the price at which the shares are Ñrst traded on the Tokyo Stock Exchange on a following day. Under the unit share system, a shareholder has one vote for each unit of shares held by it, except as stated in ""Ì Voting Rights''. Shares not constituting a whole unit will carry no voting rights and be excluded for the purpose of calculating the quorum for voting purposes. Except as otherwise described above, holders of shares constituting less than one unit will have all the rights granted to shareholders under the Commercial Code. 101
Fractional Shares Fractional shares may arise due to, among other reasons, a stock split or consolidation of outstanding shares into a smaller number of shares. Currently, the Company is required to auction those fractional shares and distribute amounts equal to the auction price among shareholders in proportion to the number of fractional shares they own. Accordingly, the Company currently does not maintain a register of holders of fractional shares. If the Company abolishes the unit share system by amending its Articles of Incorporation, any holder of fractional shares constituting one one-hundredth of one share or any integral multiple thereof will be registered in the Company's register of fractional shares unless the Articles of Incorporation of the Company provide otherwise. Fractional shares will carry no voting rights, but their holders will have the right to receive dividends unless the Articles of Incorporation of the Company provide otherwise. No certiÑcates will be issued representing fractional shares and therefore fractional shares will not be transferable. However, the registered holders of fractional shares may at any time require the Company to purchase such fractional shares at the current market price as determined pursuant to the Commercial Code. If the Articles of Incorporation of the Company so provide, a holder of fractional shares will have the right to require the Company to sell to the holder additional fractional shares suÇcient to raise such holder's holding to a full share. Other Classes of Shares The Company may issue various classes of shares if so provided in its Articles of Incorporation. Such classes of shares may contain diÅerent rights from other classes of shares with respect to annual or interim dividends, distributions of residual assets upon liquidation, repurchase of shares, cancellation of shares by proÑts or voting rights. Currently, the Articles of Incorporation of the Company do not provide for any classes of shares other than shares of common stock. Holding of Our Shares by Foreign Investors The laws of Japan, the Articles of Incorporation and other constituent documents of the Company do not limit the rights of non-residents or foreign shareholders to hold or exercise voting rights in connection with the shares. Ordinary General Meeting of Shareholders The Company normally holds its ordinary general meeting of shareholders in June of each year in any of the Wards of Tokyo. In addition, the Company may hold an extraordinary general meeting of shareholders whenever necessary by giving at least two weeks' advance notice stating the place, time, and purpose of the meeting. Under the Commercial Code, notice of any general meeting of shareholders must be given to each shareholder having voting rights or, in the case of a non-resident shareholder, to its standing proxy or mailing address in Japan in accordance with the share handling regulations of the Company, at least two weeks prior to the date of the meeting. Such notice may be given to shareholders by electronic means, subject to the consent of the relevant shareholders. The record date for an ordinary general meeting of shareholders is March 31 of each year. Any shareholder holding at least 3% of the total number of voting rights for a period of six months or more may require the convocation of a general meeting of shareholders for a particular purpose. Unless such meeting is convened promptly or a convocation notice of a meeting which is to be held not later than eight weeks from the day of such demand is dispatched, the requiring shareholder may, upon obtaining a court approval, convene such meeting. Any shareholder holding at least 300 voting rights or 1% of the total number of voting rights for a period of six months or more may propose a matter to be considered at a general meeting of shareholders by submitting a written request to one of the Company's directors at least eight weeks prior to the date of such meeting. Voting Rights A holder of shares constituting one or more units is generally entitled to one vote per one unit (or one vote per one share if the Company abolishes the unit share system). Except as otherwise provided by law or in 102
the Articles of Incorporation of the Company, a general meeting of shareholders may adopt a resolution by a majority of the voting rights represented at the meeting with no requirement as to quorum. The Commercial Code and the Articles of Incorporation of the Company require a quorum for the election of directors and corporate auditors of not less than one-third of the total number of voting rights held by all shareholders. The Company's shareholders are not entitled to cumulative voting in the election of directors. Under the Commercial Code, a corporate shareholder having more than one-quarter of its voting rights directly or indirectly held by the Company does not have voting rights with respect to the shares of the Company that it owns. The Company has no voting rights with respect to its own shares. Shareholders may exercise their voting rights through proxies, provided that those proxies are also shareholders who have voting rights. Shareholders who intend to be absent from a general meeting of shareholders may also exercise their voting rights in writing. Shareholders may also exercise their voting rights by electronic means if the Board of Directors decides to approve such method of exercising voting rights. The Commercial Code and the Articles of Incorporation of the Company require a quorum of one-third of the total number of voting rights and the approval of two-thirds of the voting rights represented at the meeting of shareholders to approve material corporate actions such as: ‚
reduction of stated capital;
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amendment of the Articles of Incorporation (except amendments that the Board of Directors are authorized to make under the Commercial Code as described in ""Ì Stock Splits'' and ""Ì Unit Share System'' above);
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removal of a director or corporate auditor;
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share exchange or share transfer, as prescribed by the Commercial Code, which requires shareholders' approval;
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dissolution, merger or consolidation requiring shareholders' approval;
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corporate split requiring shareholders' approval;
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transfer of the whole or an important part of its business;
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taking over of the whole of the business of any other corporation requiring shareholders' approval;
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consolidation of the shares;
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purchase by the Company of its own shares from a speciÑc shareholder other than a subsidiary of the Company; and
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issuance of new shares at a specially favorable price (or issuance of stock acquisition rights or of bonds with stock acquisition rights, with specially favorable conditions, as discussed under ""Ì Stock Acquisition Rights'' below) to persons other than shareholders.
In addition, the EUIL requires approval from the Minister of Economy, Trade and Industry with respect to business transfer or acquisition of an electricity supply business in its entirety, consolidation, merger or corporate split, and permission from the Minister of Economy, Trade and Industry with respect to suspension or termination of all or any part of the Company's electricity supply business or dissolution. Stock Acquisition Rights Holders of shares have no preemptive rights under the Articles of Incorporation of the Company. Under the Commercial Code, however, the Company may grant subscription rights for new shares to its shareholders by a resolution of its Board of Directors. In such case, the subscription rights must be given on uniform terms to all of the shareholders of the Company as of a record date of which not less than two weeks' prior public notice must be given. In addition, the Company must give notice to its shareholders at least two weeks prior to the date on which such rights expire. In addition, the Company may grant rights to acquire the shares (shinkabu-yoyakuken; ""stock acquisition rights'') to any person by a resolution of its Board of Directors or, if their conditions are specially 103
favorable, by a special resolution of a general meeting of shareholders, as discussed under ""Ì Voting Rights'' above. Such stock acquisition rights may be issued together with bonds or without being attached to bonds.
Liquidation Rights In the event of liquidation, the Company's assets remaining after payment of all debts, liquidation expenses and taxes will be distributed among the shareholders in proportion to the number of shares they own.
Liability to Further Calls or Assessments All of the currently issued shares are fully paid and non-assessable.
Transfer Agent The Sumitomo Trust and Banking Company, Limited is the transfer agent for the shares. Its oÇce is located at 4-4, Marunouchi 1-chome, Chiyoda-ku, Tokyo 100-8233, Japan. The Sumitomo Trust and Banking Company, Limited maintains the Company's register of shareholders and records transfers of record ownership upon presentation of share certiÑcates.
Reports to Shareholders The Company furnishes shareholders with notices of general meetings of shareholders, business reports, including Ñnancial statements, and notices of resolutions adopted at those meetings, all of which are in Japanese. These notices may be given by electronic means to those shareholders who have consented to this manner of transmission of notice, if the Board of Directors decides to adopt this method. Pursuant to the Articles of Incorporation of the Company, public notices to be given to the Company's shareholders will be published in Japanese in the Nihon Keizai Shimbun, a Japanese newspaper of general circulation.
Record Date The close of business on March 31 is the record date for year-end dividends, if paid, and the close of business on September 30 is the record date for interim dividends, if paid. The Company sets March 31 as the record date for determining shareholders entitled to vote at the ordinary general meeting of shareholders. In addition, the Company may set a record date for determining the shareholders entitled to other rights and for other purposes by giving at least two weeks' prior public notice. Shares are generally traded ex-dividend or ex-rights in the Japanese stock exchanges on the third business day before a record date (or if the record date is not a business day, the fourth business day prior thereto), for the purpose of dividends or rights oÅerings.
Report of Substantial Shareholdings The Securities and Exchange Law of Japan requires any holder of shares who has become, beneÑcially and solely or jointly, a holder of more than 5% of the total issued shares of a company listed on any Japanese stock exchange or whose shares are traded on the over-the-counter market to Ñle with the relevant local Ñnance bureau of the Ministry of Finance of Japan, within Ñve business days, a report concerning those shareholdings. A holder must Ñle a similar report to reÖect any change of 1% or more in any shareholding. Copies of any reports must also be furnished to the company and to all Japanese stock exchanges on which the shares are listed or, in the case of shares traded on the over-the-counter market, the Securities Dealers Association of Japan. For this purpose, shares issuable upon exercise of stock acquisition rights, whether or not attached to bonds, must be taken into account in determining both the number of shares held by that holder and the total issued share capital. 104
Prohibition of Insider Trading The Securities and Exchange Law prohibits insider trading of securities, including shares, of a listed company or a company traded on the over-the-counter market by corporate insiders who have material, nonpublic information concerning the company. Insiders include directors, oÇcers, agents and employees of the company and other persons having certain relationships with the company as well as persons who received such information from such an insider. A violation of the insider trading regulations may trigger a criminal sanction, in the case of an individual, of up to a three-year imprisonment and/or up to a Í3 million penalty or, in the case of a legal entity, of up to a Í300 million penalty. Any cash acquired in violation of the regulations may be forfeited.
105
TAXATION The following summaries are not intended as a complete analysis of the tax consequences under Japanese or U.S. law as a result of the acquisition, ownership and sale of international shares by investors. Potential investors should consult their own tax advisers on the tax consequences of acquisition, ownership, sale, and other relevant circumstances concerning the international shares, including speciÑcally the applicable tax consequences under Japanese or U.S. law, the law of the jurisdiction of their country of residence (if diÅerent) and any tax treaty between Japan and their country of residence. Japanese Taxation The following is a summary of the principal Japanese tax consequences to owners of our shares who are non-resident individuals or non-Japanese corporations without a permanent establishment in Japan (such owners being hereinafter referred to as ""non-resident shareholders''). The statements regarding Japanese tax laws below are subject to changes in the applicable Japanese laws or tax treaties, conventions or agreements, or in their interpretation, occurring after the date of this oÅering circular. This summary does not exhaust all possible tax considerations that may apply to a particular investor or shareholder. Potential investors or shareholders should satisfy themselves as to: ‚
the overall tax consequences of the acquisition, ownership and disposition of our shares, including speciÑcally the tax consequences under Japanese law;
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the laws of the jurisdiction of which they are resident; and
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any tax treaty, convention or agreement between Japan and their country of residence, by consulting their own tax advisers.
Generally, a non-resident shareholder is subject to Japanese withholding tax on dividends paid on our shares. Stock splits are not subject to Japanese income or corporation tax. If we purchase our own shares, excluding purchasing in a stock exchange or over-the-counter transaction, the selling non-resident shareholders are in general deemed to have received a dividend in an amount equal to the selling price less the aggregate of the stated capital and certain other capital surpluses attributable to the shares on a non-consolidated basis. If, however, we purchase our own shares by a tender oÅer on or before March 31, 2005 and their purchase price exceeds the aggregate of the stated capital and certain other capital surpluses attributable to such shares on a non-consolidated basis, such excess will not be deemed as dividends received by any selling non-resident individual shareholder. If we cancel our shares, the non-resident shareholders are in general deemed to have received a dividend in an amount equal to the price less the aggregate of the stated capital and certain other capital surpluses attributable to the cancelled shares on a non-consolidated basis. However, if we cancel the shares which have already been acquired by us, no dividends will be deemed to have been received by any non-resident selling shareholder. In addition, distribution by us of cash or other assets to non-resident shareholders due to merger, corporate split, reduction of stated capital or dissolution will in certain cases be deemed and treated as a dividend payment to nonresident shareholders for Japanese tax purposes and be subject to Japanese income tax if the aggregate of the amount of cash and the value of other assets so distributed to a non-resident shareholder exceeds the total amount of the stated capital and certain other capital surpluses attributable to the shares held by such nonresident shareholder on a non-consolidated basis. In principle, the rate of Japanese withholding tax applicable to dividends on shares paid by Japanese corporations to non-resident shareholders is 20%. However, with respect to dividends paid on listed shares issued by Japanese corporations (such as the shares following the listing thereof on the Tokyo Stock Exchange) to any non-resident shareholder, except for any individual shareholder who holds 5% or more of the total issued shares of the relevant Japanese corporation, the aforementioned 20% withholding tax rate is reduced to (i) 7% for dividends due and payable on or before March 31, 2008 and (ii) 15% for dividends due and payable on or after April 1, 2008. Japan has income tax treaties, conventions or agreements which generally provide that the withholding tax rate may not exceed 15% for portfolio investors with, among others, Australia, Belgium, Canada, Denmark, Finland, France, Germany, Ireland, Italy, Luxembourg, the Netherlands, New Zealand, Norway, Singapore, Spain, Sweden, Switzerland and the United Kingdom. In the case of the Japan U.S. tax treaty, the maximum withholding tax rate is 10% for portfolio investors. Under Japanese tax law, the maximum rate 106
applicable under the tax treaties, conventions or agreements shall be applicable except when such maximum rate is more than the Japanese statutory rate. Gains derived from the sale of our shares outside Japan, or from the sale of our shares within Japan by a non-resident shareholder, are generally not subject to Japanese income or corporation taxes. Japanese inheritance and gift taxes may be assessed against an individual who has acquired our shares as a legatee, heir or donee, even if the individual is not a Japanese resident. You should consult your own tax advisor regarding the Japanese tax consequences of owning and disposing of shares in your particular circumstances. United States Federal Income Taxation This section describes the material United States federal income tax consequences of owning shares. It applies to you only if you acquire your shares in this oÅering and you hold your shares as capital assets for tax purposes. This section does not apply to you if you are a member of a special class of holders subject to special rules, including: ‚
a dealer in securities,
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a trader in securities that elects to use a mark-to-market method of accounting for securities holdings,
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a tax-exempt organization,
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a life insurance company,
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a person liable for alternative minimum tax,
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a person that actually or constructively owns 10% or more of our voting stock,
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a person that holds shares as part of a straddle or a hedging or conversion transaction, or
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a U.S. holder (as deÑned below) whose functional currency is not the U.S. dollar.
This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, as well as on the Convention Between the United States of America and Japan for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income (the ""Treaty''). These laws are subject to change, possibly on a retroactive basis. You are a U.S. holder if you are a beneÑcial owner of shares and you are: ‚
a citizen or resident of the United States,
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a domestic corporation,
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an estate whose income is subject to United States federal income tax regardless of its source, or
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a trust if a United States court can exercise primary supervision over the trust's administration and one or more United States persons are authorized to control all substantial decisions of the trust.
A ""non-U.S. holder'' is a beneÑcial owner of shares that is not a United States person for United States federal income tax purposes. If a partnership holds our shares, the tax treatment of a partner will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding our shares, you are urged to consult your tax advisor. You should consult your own tax advisor regarding the United States federal, state and local and other tax consequences of owning and disposing of shares in your particular circumstances. 107
Taxation of Dividends U.S. Holders. Under the United States federal income tax laws, and subject to the passive foreign investment company, or PFIC, rules discussed below, if you are a U.S. holder, the gross amount of any dividend we pay out of our current or accumulated earnings and proÑts (as determined for United States federal income tax purposes) is subject to United States federal income taxation. If you are a noncorporate U.S. holder, dividends paid to you in taxable years beginning before January 1, 2009 that constitute qualiÑed dividend income will be taxable to you at a maximum tax rate of 15% provided that you hold the shares for more than 60 days during the 120-day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends we pay with respect to the shares generally will be qualiÑed dividend income. You must include any Japanese tax withheld from the dividend payment in this gross amount even though you do not in fact receive it. The dividend is taxable to you when you receive the dividend, actually or constructively. The dividend will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations. The amount of the dividend distribution that you must include in your income as a U.S. holder will be the U.S. dollar value of the yen payments made, determined at the spot yen/U.S. dollar rate on the date the dividend distribution is includible in your income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange Öuctuations during the period from the date you include the dividend payment in income to the date you convert the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualiÑed dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Distributions in excess of current and accumulated earnings and proÑts, as determined for United States federal income tax purposes, will be treated as a non-taxable return of capital to the extent of your basis in the shares or and thereafter as capital gain. Subject to certain limitations, the Japanese tax withheld in accordance with the Treaty and paid over to Japan will be creditable against your United States federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the maximum 15% tax rate. To the extent a refund of the tax withheld is available to you under Japanese law or under the Treaty, the amount of tax withheld that is refundable will not be eligible for credit against your United States federal income tax liability. Dividends will be income from sources outside the United States, but generally will be ""passive income'' or ""Ñnancial services income'' which is treated separately from other types of income for purposes of computing the foreign tax credit allowable to you. Distributions of additional shares to you with respect to shares that are made as part of a pro rata distribution to all of our shareholders generally will not be subject to United States federal income tax. The basis of any new shares you receive as a result of a pro rata distribution of shares by us will be determined by allocating your basis in the old shares between the old shares and the new shares received, based on their relative fair market values on the date of distribution. Certain transactions described under the section entitled ""Ì Japanese Taxation'' which are treated as dividends for Japanese tax purposes may not generally be taxable events for United States federal income tax purposes and therefore would not give rise to foreign source income. Consequently, U.S. holders would not be able to use the foreign tax credit arising from any Japanese withholding tax imposed on such transactions unless they can apply the credit (subject to limitations) against U.S. tax due on other foreign source income in the appropriate category for foreign tax credit purposes. Non-U.S. Holders. If you are a non-U.S. holder, dividends paid to you in respect of shares will not be subject to United States federal income tax unless the dividends are ""eÅectively connected'' with your conduct of a trade or business within the United States, and the dividends are attributable to a permanent establishment that you maintain in the United States if that is required by an applicable income tax treaty as a condition for subjecting you to United States taxation on a net income basis. In such cases you generally will be taxed in the same manner as a U.S. holder. If you are a corporate non-U.S. holder, ""eÅectively connected'' dividends may, under certain circumstances, be subject to an additional ""branch proÑts tax'' at a 30% rate or at a lower rate if you are eligible for the beneÑts of an income tax treaty that provides for a lower rate. 108
Taxation of Capital Gains U.S. Holders. If you are a U.S. holder and you sell or otherwise dispose of your shares, you will recognize capital gain or loss for United States federal income tax purposes equal to the diÅerence between the U.S. dollar value of the amount that you realize and your tax basis, determined in U.S. dollars, in your shares. Capital gain of a noncorporate U.S. holder that is recognized before January 1, 2009 is generally taxed at a maximum rate of 15% where the holder has a holding period greater than one year. The deductibility of capital losses is subject to limitations. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes. Non-U.S. Holders. If you are a non-U.S. holder, you will not be subject to United States federal income tax on gain recognized on the sale or other disposition of your shares unless: ‚
the gain is ""eÅectively connected'' with your conduct of a trade or business in the United States, and the gain is attributable to a permanent establishment that you maintain in the United States if that is required by an applicable income tax treaty as a condition for subjecting you to United States taxation on a net income basis, or
‚
you are an individual, you are present in the United States for 183 or more days in the taxable year of the sale and certain other conditions exist.
If you are a corporate non-U.S. holder, ""eÅectively connected'' gains that you recognize may also, under certain circumstances, be subject to an additional ""branch proÑts tax'' at a 30% rate or at a lower rate if you are eligible for the beneÑts of an income tax treaty that provides for a lower rate.
PFIC Rules We believe that the shares should not be treated as stock of a PFIC for United States federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If we were to be treated as a PFIC, gain realized on the sale or other disposition of your shares would in general not be treated as capital gain. Instead, if you are a U.S. Holder, you would be treated as if you had realized such gain and certain ""excess distributions'' ratably over your holding period for the shares and would be taxed at the highest tax rate in eÅect for each such year to which the gain was allocated, together with an interest charge in respect of the tax attributable to each such year. In addition, dividends that you receive from us will not be eligible for the special tax rates applicable to qualiÑed dividend income if we are a PFIC either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.
Backup Withholding and Information Reporting If you are a noncorporate U.S. holder, information reporting requirements, on Internal Revenue Service Form 1099, generally will apply to: ‚
dividend payments or other taxable distributions made to you within the United States, and
‚
the payment of proceeds to you from the sale of shares eÅected at a United States oÇce of a broker.
Additionally, backup withholding may apply to such payments if you are a noncorporate U.S. holder that: ‚
fails to provide an accurate taxpayer identiÑcation number,
‚
is notiÑed by the Internal Revenue Service that you have failed to report all interest and dividends required to be shown on your federal income tax returns, or
‚
in certain circumstances, fails to comply with applicable certiÑcation requirements. 109
If you are a non-U.S. holder, you are generally exempt from backup withholding and information reporting requirements with respect to: ‚
dividend payments made to you outside the United States by us or another non-United States payor and
‚
other dividend payments and the payment of the proceeds from the sale of shares eÅected at a United States oÇce of a broker, as long as the income associated with such payments is otherwise exempt from United States federal income tax, and: ‚
‚
the payor or broker does not have actual knowledge or reason to know that you are a United States person and you have furnished the payor or broker: ‚
an Internal Revenue Service Form W-8BEN or an acceptable substitute form upon which you certify, under penalties of perjury, that you are a non-United States person, or
‚
other documentation upon which it may rely to treat the payments as made to a nonUnited States person in accordance with U.S. Treasury regulations, or
you otherwise establish an exemption.
Payment of the proceeds from the sale of shares eÅected at a foreign oÇce of a broker generally will not be subject to information reporting or backup withholding. However, a sale of shares that is eÅected at a foreign oÇce of a broker will be subject to information reporting and backup withholding if: ‚
the proceeds are transferred to an account maintained by you in the United States,
‚
the payment of proceeds or the conÑrmation of the sale is mailed to you at a United States address, or
‚
the sale has some other speciÑed connection with the United States as provided in U.S. Treasury regulations,
unless the broker does not have actual knowledge or reason to know that you are a United States person and the documentation requirements described above are met or you otherwise establish an exemption. In addition, a sale of shares eÅected at a foreign oÇce of a broker will be subject to information reporting if the broker is: ‚
a United States person,
‚
a controlled foreign corporation for United States tax purposes,
‚
a foreign person 50% or more of whose gross income is eÅectively connected with the conduct of a United States trade or business for a speciÑed three-year period, or
‚
a foreign partnership, if at any time during its tax year: ‚
one or more of its partners are ""U.S. persons'', as deÑned in U.S. Treasury regulations, who in the aggregate hold more than 50% of the income or capital interest in the partnership, or
‚
such foreign partnership is engaged in the conduct of a United States trade or business,
unless the broker does not have actual knowledge or reason to know that you are a United States person and the documentation requirements described above are met or you otherwise establish an exemption. Backup withholding will apply if the sale is subject to information reporting and the broker has actual knowledge that you are a United States person. You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your income tax liability by Ñling a refund claim with the United States Internal Revenue Service. 110
OFFERING AND SALE We have entered into an international purchase agreement, dated September 27, 2004, with the international selling shareholder and the international managers named below, for whom Nomura International plc and UBS Limited are acting as the joint lead managers. Pursuant to the international purchase agreement, the international managers have each agreed with us and the international selling shareholder, subject to the satisfaction of certain conditions, severally but not jointly to purchase the international shares as indicated in the table below at a purchase price of Í2,632.5 per share and to oÅer the international shares at the oÅer price stated on the cover page of this oÅering circular. Number of international shares
International manager Nomura International plc ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ UBS Limited ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Daiwa Securities SMBC Europe Limited ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Goldman Sachs International ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Merrill Lynch International ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Morgan Stanley & Co. International LimitedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Citigroup Global Markets LimitedÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Deutsche Bank AG London ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ HSBC Bank plc ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ J.P. Morgan Securities Ltd. ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Lehman Brothers International (Europe) ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ Total ÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏÏ
13,013,600 13,013,600 1,388,000 1,388,000 1,388,000 1,388,000 1,388,000 433,700 433,700 433,700 433,700 34,702,000
The diÅerence between the oÅer price and the purchase price of the international shares will be distributed among the international managers in the manner agreed upon by the international managers. No selling concession, management commission or underwriting commission will be payable by us or the international selling shareholder with respect to the international shares. After the initial oÅering of the international shares, the joint lead managers may change the oÅer price and other selling terms of the international shares. The international managers are oÅering the international shares subject to their acceptance of the international shares from the international selling shareholder and subject to prior sale. The international managers reserve the right to withdraw, cancel or modify orders and to reject any orders in whole or in part. The international purchase agreement provides that the obligations of the several international managers to pay for and accept delivery of the international shares are subject to approval of certain legal matters by their counsel and to certain other conditions. The international managers are entitled to be released and discharged from their obligations under, and to terminate, the international purchase agreement in certain circumstances prior to payment to the international selling shareholder. If an international manager defaults, the international purchase agreement provides that the purchase commitments of the non-defaulting international managers may be increased or the international purchase agreement may be terminated. The international purchase agreement provides that we will indemnify the international managers and the Rule 144A selling agents against certain liabilities in connection with the oÅering and sale of the international shares, including liabilities under the Securities Act, and will contribute to payments the international managers and the Rule 144A selling agents may be required to make in respect of those liabilities. In addition, we have agreed to pay certain costs incurred in connection with the sale of the international shares and to reimburse the international managers for certain of their expenses. The international shares are being oÅered and sold by the international managers (i) to non-U.S. persons in oÅshore transactions outside Japan and the United States in reliance on Regulation S and (ii) through the Rule 144A selling agents of certain international managers to QIBs in the United States in reliance on Rule 144A. Pursuant to the international purchase agreement, we have agreed that, without the prior written consent of each of the joint lead managers, we will not, and we will not permit any entity over which we exercise control or any person acting on our behalf to, for a period that will end 180 days after the date of this oÅering circular, (i) oÅer, pledge, issue, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend, or otherwise transfer or 111
dispose of, directly or indirectly, any of our shares or any securities convertible into or exercisable or exchangeable for our shares or (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of our shares, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of shares or such other securities, in cash or otherwise, except that the restrictions described above do not apply to (A) the shares being oÅered and sold in the international oÅering and the Japanese oÅering, (B) new shares issued by us by way of stock split or (C) transactions by any person other than us that involve our shares or other securities acquired in open market transactions after the completion of the international oÅering. We have also entered into an underwriting agreement with the international selling shareholder, the Japanese selling shareholders and certain Japanese underwriters, for whom Nomura Securities Co., Ltd. and UBS Securities Japan Ltd are acting as the Japanese joint lead managers, providing for the oÅer and sale of an aggregate of 104,106,000 Japanese shares in connection with the Japanese oÅering. The closing of the international oÅering is conditional upon the closing of the Japanese oÅering. Each of the oÅer price and the purchase price, respectively, is identical in the international oÅering and the Japanese oÅering. A portion of the Japanese shares is expected to be allocated to and purchased by our employee stock ownership plan. The international selling shareholder has appointed Nomura Securities Co., Ltd. and UBS Securities Japan Ltd to act as joint global coordinators of the oÅerings. We have been advised by the joint global coordinators that, pursuant to an intersyndicate agreement dated September 27, 2004 among the joint lead managers, on behalf of the international managers, and the Japanese joint lead managers, on behalf of the Japanese underwriters, each international manager has agreed that, subject to certain exceptions, it is not purchasing, and will not purchase, directly or indirectly, any shares for the account of any Japanese person (as deÑned below) and that it has not oÅered or sold, and will not oÅer or sell, directly or indirectly, any shares or distribute any oÅering circular or prospectus relating to the shares in Japan or to any Japanese person (as deÑned below), and each Japanese underwriter has agreed that, subject to certain exceptions, it is not purchasing, and will not purchase, directly or indirectly, any shares for the account of any person or entity other than a Japanese person (as deÑned below) and that it has not oÅered or sold, and will not oÅer or sell, directly or indirectly, any shares or distribute any oÅering circular or prospectus relating to the shares outside Japan or to any person or entity other than a Japanese person (as deÑned below). For the purpose of this ""OÅering and Sale'' section, ""Japanese person'' is deÑned as any individual whose place of abode is in Japan, or any corporation whose principal place of business is in Japan (other than a branch or oÇce located outside Japan of any Japanese person), and includes any Japanese branch or oÇce of a person who is otherwise not a Japanese person. Subject to certain exceptions, these obligations of the international managers and the Japanese underwriters will terminate upon the earlier of the mutual agreement of the joint global coordinators and 30 days after the date of the intersyndicate agreement. In addition, pursuant to the intersyndicate agreement, the Japanese underwriters may sell to the international managers such number of shares as is agreed upon by the joint global coordinators in consultation with the joint lead managers. To the extent the Japanese underwriters sell shares to the international managers pursuant to the intersyndicate agreement and in compliance with any applicable laws, regulations and rules, the number of international shares initially available for sale by the international managers may be higher, and the number of Japanese shares initially available for sale by the Japanese underwriters may be lower, than the corresponding numbers appearing on the cover page of this oÅering circular. The international shares have not been and will not be registered under the Securities Act and may not be oÅered or sold within the United States or to, or for the account or beneÑt of, U.S. persons except pursuant to an eÅective registration statement or in accordance with an applicable exemption from the registration requirements of the Securities Act. Each international manager has agreed that, except as permitted by the international purchase agreement, it will oÅer and sell shares (i) as part of its distribution of international shares at any time and (ii) otherwise until 40 days after the later of the commencement of the international oÅering and the closing date of the international oÅering, only in accordance with Rule 903 of Regulation S or Rule 144A under the Securities Act. Each United States purchaser of international shares is hereby notiÑed that the oÅer and sale of international shares to it is being made in reliance upon the exemption from the registration requirements of the Securities Act provided by Rule 144A. 112
The oÅering of the international shares outside the United States will be made in compliance with Regulation S. In addition, until 40 days after the later of the commencement of the oÅerings and the closing date, an oÅer or sale of international shares within the United States by a dealer (whether or not participating in the oÅerings) may violate the registration requirements of the Securities Act if such oÅer or sale is made otherwise than in accordance with Rule 144A or pursuant to another exemption from registration under the Securities Act. Each international manager has represented, warranted and agreed that it understands that the international shares have not been and will not be registered under the Securities and Exchange Law and that the international shares which it will purchase will be purchased by it as principal and that, in connection with the international oÅering, it will not, directly or indirectly, oÅer or sell any international shares in Japan or to, or for the beneÑt of, any Japanese person or to others for reoÅer or resale, directly or indirectly, in Japan or to, or for the beneÑt of, any Japanese person except pursuant to any exemption from the registration requirements and from the requirements to deliver a prospectus under the Securities and Exchange Law and otherwise in compliance with the Securities and Exchange Law and other applicable laws and regulations. Each international manager has represented, warranted and agreed that it has (i) not oÅered or sold and, prior to the expiration of six months from the closing date of the international oÅering, will not oÅer or sell any international shares to persons in the United Kingdom except to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their businesses or otherwise in circumstances which have not resulted and will not result in an oÅer to the public in the United Kingdom within the meaning of the Public OÅers of Securities Regulations 1995, as amended; (ii) 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 sale of any international shares in circumstance in which Section 21(1) of the FSMA does not apply to the Company; and (iii) complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the international shares in, from or otherwise involving the United Kingdom. Each international manager has represented, warranted and agreed that it has (i) not oÅered or sold and will not oÅer or sell, by means of any document, any international shares other than in circumstances which do not constitute an oÅer to the public within the meaning of the Companies Ordinance (Cap. 32) of Hong Kong; and (ii) not issued and will not issue any advertisement, invitation or document relating to the international shares, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to international shares which are or are intended to be disposed of only to persons outside Hong Kong or only to ""professional investors'' within the meaning of the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made thereunder. Each international manager has represented, warranted and agreed that it understands that this oÅering circular has not been registered as a prospectus with the Monetary Authority of Singapore and, accordingly, this oÅering circular and any other document or material in connection with the oÅer or sale, or invitation for subscription or purchase, of the international shares may not be circulated or distributed, nor may the international shares be oÅered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to the public or any member of the public in Singapore other than (i) to an institutional investor or other person speciÑed in Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a sophisticated investor, and in accordance with the conditions, speciÑed 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. Each international manager has represented, warranted and agreed that it understands that the international shares may not, directly or indirectly, be oÅered in or from the Netherlands, as part of their initial distribution or as part of any reoÅering, and neither this oÅering circular, nor any other document in respect of the international oÅering may be distributed in or from the Netherlands, other than to individuals or legal entities who or which trade or invest in securities in the conduct of their profession or trade (which includes banks, investment institutions, securities intermediaries, insurance companies, pension funds, other institutional investors and treasury departments and Ñnance companies of large enterprises). 113
Each international manager has represented, warranted and agreed that it understands that the international oÅering has not been registered with the Commissione Nazionale per la Societa'e la Borsa, or CONSOB (the Italian securities exchange commission), pursuant to the Italian securities legislation and, accordingly, each international manager has represented, warranted and agreed that (i) it has not oÅered, sold or delivered any international shares nor distributed any copies of the oÅering circular or any other document relating to the international shares, and will not oÅer, sell or deliver any international shares nor distribute any copies of the oÅering circular or any other document relating to the international shares in the Republic of Italy in a solicitation to the public at large (sollecitazione all'investimento), and that the international shares in the Republic of Italy will only be: (A) oÅered or sold to professional investors (operatori qualiÑcati), as deÑned in Article 31, second paragraph of CONSOB Regulation No. 11522 of July 1, 1998, as amended, or Regulation No. 11522, (B) oÅered or sold in circumstances where an exemption from the rules governing solicitations to the public at large applies, pursuant to Article 100 of Legislative Decree No. 58 of February 24, 1998, or the Financial Services Act, and Article 33, Ñrst paragraph, of CONSOB Regulation No. 11971 of May 14, 1999, as amended, or Regulation No. 11971, or (C) sold to a person located in the Republic of Italy who submits an unsolicited request to purchase international shares, and will in any event be eÅected in accordance with all relevant Italian securities, tax and exchange control and other applicable laws and regulations, and (ii) the international shares may not be oÅered, sold or delivered and neither the oÅering circular nor any other material relating to the international shares may be distributed or made available in the Republic of Italy unless such oÅer, sale or delivery of international shares or distribution or availability of copies of the oÅering circular or any other material relating to the international shares in the Republic of Italy is made by investment Ñrms, banks or Ñnancial intermediaries permitted to conduct such activities in the Republic of Italy in accordance with the Financial Services Act, Legislative Decree No. 385 of September 1, 1993, Regulation No. 11522, Regulation No. 11971 and any other applicable laws and regulations. Each international manager has represented, warranted and agreed that it (i) acknowledges that the distribution of the international shares in Canada is being made only on a basis exempt from the requirement that the Company prepare and Ñle a prospectus with the securities regulatory authorities in each province or territory where trades of international shares are eÅected, (ii) represents and warrants that it has complied with, or is exempt from, the dealer registration requirements of the securities regulatory authorities in each province or territory where trades of international shares are eÅected, (iii) represents, warrants and agrees that any oÅer or sale of the international shares in Canada by it has been and will be made in accordance with applicable securities laws in each relevant jurisdiction in Canada, (iv) agrees to Ñle any required reports or documents with the securities regulatory authorities in each relevant jurisdiction in Canada and (v) agrees that the distribution of the international shares shall not be advertised in Canada. Prior to the oÅerings, there has been no public market for our shares inside or outside Japan. The oÅer price has been determined by agreement among the selling shareholders and the joint global coordinators. Among the factors considered in determining the oÅer price are prevailing market conditions, our historical performance, assessments of our management and business prospects and consideration of those factors in relation to market valuations of companies in related businesses. The international shares may not be oÅered or sold, directly or indirectly, and neither this oÅering circular nor any other oÅering material or advertisement in connection with the international shares may be distributed or published, in or from any country or jurisdiction except in compliance with any applicable rules and regulations of any such country or jurisdiction, but subject to restrictions described above and in ""Transfer Restrictions''. Buyers of international shares sold by the international managers may be required to pay stamp taxes and other charges in accordance with the laws and practice of the country of purchase in addition to the oÅer price. It is expected that delivery of the international shares will be made on or about October 6, 2004 (Tokyo time) through the facilities of JASDEC against payment therefor in immediately available funds. See ""Clearance and Settlement''. Certain of the international managers, the Japanese underwriters or their aÇliates have provided, and may in the future provide, various Ñnancial advisory and investment banking services for us, the international selling shareholder, the Japanese selling shareholders or their aÇliates for which they received or may receive, customary fees and expenses.
114
TRANSFER RESTRICTIONS Because of the following restrictions, investors are advised to consult legal counsel prior to making any reoÅering, resale, pledge or transfer of the international shares. The international oÅering is being made in accordance with Rule 144A and Regulation S. The international shares have not been and will not be registered under the Securities Act or with any securities regulatory authority of any state or other jurisdiction of the United States. Accordingly, the international shares may not be oÅered, sold, pledged or otherwise transferred or delivered within the United States (as deÑned in Regulation S) or to, or for the account or beneÑt of, U.S. persons (as deÑned in Regulation S) except as set forth below. Rule 144A Shares Each purchaser of the international shares oÅered hereby in reliance on Rule 144A, or the Rule 144A shares, will be deemed to have represented and agreed as follows: (1)
It (A) is a qualiÑed institutional buyer, (B) is aware that the sale of the Rule 144A shares to it is being made in reliance on Rule 144A and (C) is acquiring the Rule 144A shares for its own account or for the account of a qualiÑed institutional buyer, as the case may be.
(2)
It understands that the Rule 144A shares have not been and will not be registered under the Securities Act and may not be oÅered, resold, pledged or otherwise transferred except (A) (i) to a person whom the purchaser and any person acting on its behalf reasonably believes is a qualiÑed institutional buyer within the meaning of Rule 144A under the Securities Act purchasing for its own account or for the account of a qualiÑed institutional buyer in a transaction meeting the requirements of Rule 144A, (ii) in an oÅshore transaction complying with Rule 903 or Rule 904 of Regulation S or (iii) pursuant to an exemption from registration under the Securities Act provided by Rule 144A thereunder (if available) and (B) in accordance with all applicable securities laws of the states of the United States.
No representation can be made as to the availability of the exemption provided by Rule 144 for resales of the Rule 144A shares oÅered hereby. Regulation S Shares Each initial purchaser of international shares other than the Rule 144A shares, or the Regulation S shares, will be deemed to have represented and agreed as follows: (1)
It is a non-U.S. person who is acquiring such Regulation S shares in an oÅshore transaction in accordance with Rule 903 or Rule 904 of Regulation S under the Securities Act.
(2)
It understands that such Regulation S shares have not been and will not be registered under the Securities Act and until 40 days after the later of the commencement of the international oÅering and the closing date, may not be oÅered, resold, pledged or transferred within the United States (as deÑned in Regulation S) or to, or for the account or beneÑt of U.S. Persons (as deÑned in Regulation S), except in certain transactions in accordance with Rule 144A under the Securities Act.
115
JAPANESE FOREIGN EXCHANGE REGULATIONS The Foreign Exchange and Foreign Trade Law of Japan, as amended, and the cabinet ordinance and ministerial ordinances thereunder or, collectively, the Foreign Exchange Regulations, govern certain aspects of the transfer of shares by ""exchange residents'' and the acquisition and holding of shares by ""exchange nonresidents'' and by ""foreign investors'' (as these terms are deÑned below). ""Exchange non-residents'' are deÑned as individuals who are not resident in Japan and corporations whose principal oÇces are located outside Japan. Generally, branch and other oÇces located within Japan of non-resident corporations are regarded as exchange residents of Japan and branch and other oÇces of Japanese corporations located outside Japan are regarded as exchange non-residents of Japan. ""Foreign investors'' are deÑned, with respect to inward direct investment described below, to be (i) individuals not resident in Japan, (ii) corporations which are organized under the laws of foreign countries or the principal oÇces of which are located outside Japan and (iii) corporations not less than 50% of the voting rights of which are directly or indirectly held by (i) and/or (ii) or a majority of the directors and other persons in similar positions (or a majority of directors and such persons having the power of representation) of which are nonresident individuals. Acquisition of Shares Acquisition by an exchange non-resident of shares of stock of a Japanese corporation from an exchange resident requires post facto reporting by the exchange resident of Japan to the Minister of Finance of Japan through The Bank of Japan. No such reporting requirement is imposed, however, if: ‚
the aggregate purchase price of the relevant shares is Í100 million or less;
‚
the acquisition is eÅected through any securities house, bank or other entity prescribed by the Foreign Exchange Regulations acting as an agent or intermediary; or
‚
the acquisition constitutes an ""inward direct investment'' described below.
Inward Direct Investment in Shares of Listed Corporations. Acquisition of shares of a listed Japanese corporation by a foreign investor (whether from an exchange resident, an exchange non-resident or any other foreign investor) constitutes an inward direct investment if such foreign investor will directly or indirectly hold 10% or more of the total issued shares of such corporation upon consummation of the proposed acquisition. In case of an inward direct investment in a listed Japanese corporation which is engaged in any of the businesses designated by the Foreign Exchange Regulations, or the Designated Businesses, the foreign investor who intends to acquire shares of such corporation must in general Ñle a prior notiÑcation with the Minister of Finance and other competent Ministers. If such prior notiÑcation is Ñled, the proposed acquisition may not be consummated until 30 days have passed following the date of the Ñling, although this period will be shortened to two weeks unless the Minister of Finance and other competent Ministers deem it necessary to review the proposed acquisition. The Ministers may recommend any modiÑcation or abandonment of the proposed acquisition and, if such recommendation is not accepted, they may order the modiÑcation or abandonment of such acquisition. The electricity supply business is one of the Designated Businesses. Accordingly, any foreign investor who intends to acquire our shares after the closing of the international oÅering must in general Ñle a prior notiÑcation with the Minister of Finance and the METI if such foreign investor will directly or indirectly hold 10% or more of the total issued shares upon consummation of the proposed acquisition. As described above, a 30-day waiting period will be applicable to such prior notiÑcation, which period can be shortened to two weeks, and such Ministers have authorities to issue recommendations and orders, if necessary. Acquisition of shares by foreign investors by way of stock split is not subject to any notiÑcation or reporting requirements. Dividends and Proceeds of Sales Under the Foreign Exchange Regulations, dividends paid on, and the proceeds of sales in Japan of, shares held by exchange non-residents may in general be converted into any foreign currency and repatriated abroad. 116
CLEARANCE AND SETTLEMENT JASDEC The central clearing system of share certiÑcates under the Law Concerning Central Securities Depository and Book-Entry Transfer applies to the shares. Under this system, holders of the shares may deposit certiÑcates therefore with JASDEC, the sole depository under the system, through the participating institutions in the system. See ""Description of the Shares Ì General Ì JASDEC Clearing System''. Euroclear System and Clearstream Banking Book-entry interests in the shares may be held through the Euroclear Bank S.A./N.V., as operator of the Euroclear System, or Euroclear, or Clearstream Banking, societ π eπ anonyme, or Clearstream, and, if a purchaser of shares of the shares wishes to hold them through Euroclear or Clearstream it must deliver certiÑcates for the shares to a nominee in Japan for the relevant clearing system who will hold the shares in JASDEC. Settlement for purchasers of international shares will be made only through accounts of participating institutions in JASDEC. The aggregate holdings of book-entry interests in the shares in Euroclear and Clearstream will be reÖected in the book-entry accounts of each such clearing system. Euroclear or Clearstream, as the case may be, and every other intermediate holder in the chain to the beneÑcial owner of book-entry interests in the shares, will be responsible for establishing and maintaining accounts for their participants and clients having an interest in the book-entry interests in the shares. The Company will not impose any fees in respect of the holding of book-entry interests in the shares. However, holders of book-entry interests in the shares through Euroclear and Clearstream may incur fees normally payable in respect of the maintenance and operation of accounts in Euroclear or Clearstream. In addition, a Japanese securities company or commercial bank acting as standing proxy will charge certain standard fees. Secondary Market Trading Settlement of transactions concerning shares listed on any of the stock exchanges in Japan normally will be eÅected on the third business day after the transaction date. Settlement in Japan is made by physical delivery of share certiÑcates or through JASDEC as described above and in ""Description of the shares Ì General Ì JASDEC Clearing System''. Secondary market sales of book-entry interests in the shares held through Euroclear or Clearstream to purchasers of book-entry interests in the shares through Euroclear or Clearstream will be conducted in accordance with the normal rules and operating procedures of Euroclear and Clearstream and will be settled using the procedures applicable to conventional eurobonds. Any transfer of interests in the shares held through Euroclear or Clearstream out of the relevant clearing system will be done in accordance with rules of Euroclear or Clearstream, as applicable, and those of JASDEC and the Company's share handling regulations. Secondary market sales and transfers of the shares held outside of Euroclear and Clearstream will be conducted in accordance with the Company's share handling regulations and the rules of JASDEC, if applicable, and, in any case, the rules of the relevant stock exchange.
117
VALIDITY OF SECURITIES The validity of the international shares will be passed upon for the Company by Tomotsune & Kimura. The Company is also being represented by Sullivan & Cromwell LLP. The international managers are being represented by Simpson Thacher & Bartlett LLP and Mitsui, Yasuda, Wani & Maeda.
INDEPENDENT AUDITORS The consolidated Ñnancial statements for the years ended March 31, 2002, 2003 and 2004 included herein have been audited by Ernst & Young Shin Nihon, independent auditors, as stated in their reports appearing herein.
118
GENERAL INFORMATION 1. Each of the Company and the international selling shareholder have obtained all necessary consents, approvals and authorizations to be obtained by it in Japan in connection with the oÅerings. 2. Copies of the Articles of Incorporation, the Regulations of the Board of Directors and the share handling regulations of the Company will be available for inspection during usual business hours on any weekday (except Saturdays, Sundays and public holidays) at the head oÇce of the Company. 3. Except as described herein, there has been no material adverse change in the Company's Ñnancial position or results of operations on either a consolidated or non-consolidated basis since March 31, 2004. 4. Except as described herein, neither the Company nor any of its consolidated subsidiaries is involved in or threatened by any legal, arbitral, administrative or other proceedings the results of which might, individually or in the aggregate, be material in the context of the oÅerings. 5. The shares have been accepted for clearance through the facilities of Euroclear and Clearstream. The Securities IdentiÑcation Code for the shares on the Japanese stock exchanges on which it is listed is 9513. The International Security IdentiÑcation Number (ISIN), the Common Code and the SEDOL number are JP3551200003, 020048867 and B02Q328, respectively.
119
SUMMARY OF CERTAIN SIGNIFICANT DIFFERENCES BETWEEN JAPANESE AND U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The accompanying consolidated Ñnancial statements of the Company have been prepared in conformity with Japanese GAAP, which diÅers from U.S. GAAP in certain material respects. Such diÅerences are discussed below and include only those diÅerences related to the consolidated Ñnancial statements. Certain signiÑcant diÅerences between Japanese GAAP and U.S. GAAP relevant to the Company's Ñnancial statements are summarized below. The summary should not be construed to be exhaustive. In making an investment decision, investors must rely upon their own examination of the Company, the terms of the oÅering and the Company's Ñnancial information. Potential investors should consult their own professional advisors for an understanding of the diÅerences between Japanese GAAP and U.S. GAAP and how these diÅerences might aÅect the Ñnancial information herein. Additionally, no attempt has been made to identify all disclosure, presentation or classiÑcation diÅerences that would aÅect the manner in which transactions and events are presented in the Ñnancial statements or notes thereto. Further, no attempt has been made to identify future diÅerences between Japanese GAAP and U.S. GAAP as the result of prescribed changes in accounting standards and regulations. Regulatory bodies that promulgate Japanese GAAP and U.S. GAAP have signiÑcant projects ongoing that could aÅect future comparisons such as this one. Finally, no attempt has been made to identify all future diÅerences between Japanese GAAP and U.S. GAAP that may aÅect the Company's Ñnancial statements as a result of transactions or events that may occur in the future.
1.
Consolidation
Under Japanese GAAP, once the parent company registers with the Ministry of Finance of Japan (the ""MOF'') the parent company consolidates not only a business entity in which it has more than 50% ownership, but also a business entity over which it has direct or indirect controls, even if it has ownership of 50% or less. If the parent company is not registered with the MOF, Japanese GAAP does not require the preparation of consolidated Ñnancial statements. The Company registered with the MOF in 2001. Under U.S. GAAP, Financial Accounting Standards Board (""FASB'') Statement of Financial Accounting Standard (""SFAS'') No. 94, ""Consolidation of All Majority-Owned Subsidiaries Ì an amendment of ARB No. 51, with related amendments of APB Opinion No. 18 and ARB No. 43, Chapter 12'' requires consolidation of another company if controlling Ñnancial ownership interest exists in the form of a majority voting interest. As a general rule, ownership by one company, directly or indirectly, of over Ñfty percent of the outstanding voting shares of another company is a condition pointing toward consolidation. There are exceptions to this general rule such as when minority interest holders have substantive participating rights or if the company is a variable interest entity.
2.
Investments in Unconsolidated Subsidiaries and AÇliates Non-consolidated Ñnancial statements
Under Japanese GAAP, the equity method is not required to be applied to investments in unconsolidated subsidiaries and aÇliates in the preparation of non-consolidated Ñnancial statements. The equity method is applied only in the preparation of consolidated Ñnancial statements. Investments in subsidiaries and aÇliates are carried at cost in the non-consolidated Ñnancial statements and are required to be written down if, due to Ñnancial crisis, their value has substantially declined by 50% or more and a recovery is not expected. Under U.S. GAAP, Accounting Principles Board (APB) Opinion No. 18, ""The Equity Method of Accounting for Investments in Common Stock'', requires an investor whose investment in voting stock gives it the ability to exercise signiÑcant inÖuence over operating and Ñnancial policies of an investee even though the investor holds 50% or less of the voting stock to account for its investment under the equity method. The investor's share of the investee's earnings or losses is included in net income with the carrying value of the investments adjusted accordingly. APB 18 also requires the elimination of intercompany proÑt until such transactions are realized and dividends received. 120
3.
Accounting for the EÅects of Regulation
Regulations for the establishment of electric rates consider, in certain cases, certain income and expenses to be recognized in diÅerent years than they are recognized for Ñnancial reporting. In accordance with SFAS No. 71, ""Accounting for the EÅects of Certain Types of Regulation'' for regulated enterprises, a regulatory liability or asset is recognized on the consolidated balance sheet by a charge or credit to operations to match revenues and expenses. SFAS No. 90, ""Regulated Enterprises Ì Accounting for Abandonments and Disallowance of Plant Costs'', requires an enterprise to remove an operating asset or an asset under construction from plant-inservice or work-in-process when it becomes probable that the asset will be abandoned. The enterprise shall determine whether recovery of any allowed cost is likely to be provided with (a) full return on investment during the period from the time when abandonment becomes probable to the time when recover is completed or (b) partial or no return on investment during that period. If full return on investment is likely, the cost of the abandoned plant shall be reported as a separate new asset. If partial or no return on investment is likely to be provided, the present value of future revenues expected to be provided to recover the allowable costs of the abandoned plant and return on investment shall be recorded as an asset and a loss recognized. During the period between the date on which the new asset is recognized and the date on which recovery begins, the carrying amount shall be increased by accruing a carrying charge. During the recovery period, amortization of the asset shall be in manner consistent with either that used for rate-making purposes (full return on investment) or that will produce a constant return on the unamortized investment (partial or no return on investment). 4.
Valuation of Securities
Under Japanese GAAP, the accounting standard for Ñnancial instruments requires that securities (except for investments in subsidiaries and aÇliates) be classiÑed as trading securities, held-to-maturity securities and other securities and that the securities be stated in the Ñnancial statements based on these three categories. Trading securities Securities classiÑed in this category correspond to ""trading'' securities as deÑned under Japanese GAAP. Trading securities are to be measured at fair value, with the related net unrealized gain or loss included in current earnings. Held-to-maturity securities Securities classiÑed in this category correspond to ""held-to-maturity'' securities as deÑned under Japanese GAAP. Held-to-maturity securities are to be accounted for at amortized cost at a constant rate or in equal amounts applied consistently over the period of amortization. Other securities Securities classiÑed in neither category referred to above are classiÑed as ""other'' securities. Other securities are to be stated at fair value except that securities without fair value are stated at cost. There are two methods for accounting for unrealized gain or loss. One method is that net unrealized gain or loss (net of the related tax eÅect) is reported as a separated component of shareholders' equity. The other method is that unrealized gain is reported as a separate component of shareholders' equity and unrealized loss is included in current earnings. However, if the value of the securities has substantially declined (i.e., by 50% or more) and a recovery is not expected, the unrealized loss is treated as a realized loss and is included in current earnings under both methods. Under U.S. GAAP, SFAS No. 115, ""Accounting for Certain Investments in Debt and Equity Securities'', requires debt securities and marketable equity securities to be classiÑed into one of three categories: ""trading'', ""held-to-maturity'' or ""available-for-sale'' securities. The valuation of these securities depends on their classiÑcation. 121
Trading securities Debt and marketable equity securities which are acquired and held primarily for sale in the near term are classiÑed as trading securities. The intent to trade and the existence of trading activity are the key factors to be considered when determining whether a security should be included in this category. Trading securities are measured at fair value with unrealized gain or loss included in current earnings. Held-to-maturity securities Held-to-maturity securities are limited to debt securities, which the holder has both the positive intent and the ability to hold to maturity. This category does not include securities which an entity intends to hold only for an indeÑnite period. Held-to-maturity securities are stated at amortized cost. Available-for-sale securities Securities classiÑed in neither of the aforementioned categories are classiÑed as available-for-sale securities. Securities in this category are to be stated at fair value. Unrealized gain or loss, net of the related tax eÅect, is included as a separated component of shareholders' equity. If a decline in fair value below the cost of such securities is deemed ""other-than-temporary'', the loss is accounted for as a realized loss and is charged to current earnings. In March 2004, the FASB Emerging Issues Task Force (EITF) reached a consensus to Issue No. 03-1, ""Meaning of Other Than Temporary Impairment'', that established a basic model to evaluate whether an investment within the scope of Issue 03-1 is other-than-temporarily impaired. The basic model Ñrst determines whether the investment is impair, which occurs when the investment's fair value is less than its cost; second, evaluate whether the impairment is other-than-temporary; and last, if the impairment is other-than-temporary, recognize an impairment loss equal to the diÅerence between the investment's cost and its fair value. 5.
Impairment of Long-Lived Assets and Assets to be Disposed of Under Japanese GAAP, no impairment loss is currently required to be recognized on long-lived
assets. However, on August 9, 2002, the Business Accounting Council issued ""Accounting Standard for the Impairment of Fixed Assets'' which consists of: 1) assets subject to impairment consideration, 2) recognition and measurement of an impairment loss, 3) accounting for such assets after the recognition of an impairment loss, and 4) reporting in the Ñnancial statements. This new standard will become eÅective for years beginning after March 31, 2005. However, earlier adoption is permitted for years beginning after March 31, 2004 and also for years ending between March 31, 2004 and March 30, 2005. This standard requires that long-lived assets, except for those which are required to be accounted for as impaired assets in accordance with another accounting standard, be reviewed in order to determine whether an impairment loss is to be recognized, if there is any indication that impairment has developed. Under U.S. GAAP, FAS 144, ""Accounting for the Impairment or Disposal of Long-Lived Assets'', speciÑes that undiscounted cash Öows of an asset or grouping of assets must be estimated at the lowest identiÑable level once an indication of impairment exists and the asset are held and used. If undiscounted cash Öows exceed the carrying value, then fair value is determined and an impairment loss is recorded. Reversal of an impairment loss should facts and circumstances change is prohibited. 6.
Valuation of Inventories Under Japanese GAAP, inventories can be stated at cost or at the lower of cost or market. U.S. GAAP requires that all inventories be valued at the lower of cost or market.
7.
Leases Capitalized as Assets
Under Japanese GAAP, leases which transfer substantially all the risks and beneÑts of ownership are basically accounted for as capital leases. However, leases which do not transfer ownership of the asset to the lessee at or by the end of the lease term can be accounted for as operating leases with footnote disclosure of 122
the estimated acquisition cost, estimated accumulated depreciation and future estimated lease payments or receipts. Under U.S. GAAP, leases which transfer substantially all the risks and beneÑts of ownership are basically accounted for as capital leases for the lessee. For the lessor, such leases are accounted for as direct Ñnancing leases, sales-type leases or leveraged leases. 8.
Compensated Absences
Under Japanese GAAP, no accounting standard for compensated absences or the related liability exists at present. U.S. GAAP requires recognition of the liability representing employees' rights to receive compensation for future compensated absences when certain conditions are met. 9.
Pensions and Severance Costs
Under Japanese GAAP, the accounting standard for pension and severance costs requires that such costs be recognized based on the projected beneÑt obligation and the plan assets as of the balance sheet date in a manner similar to U.S. GAAP. The diÅerences between Japanese GAAP and U.S. GAAP relating to accounting for pension and severance costs are summarized as follows: Components of net periodic pension and severance costs Under the Japanese accounting standard for pension and severance costs, net periodic pension and severance costs consist of the following components: ""service cost'', interest cost on projected beneÑt obligation'', ""expected return on plan assets'', and ""amortization of unrecognized beneÑt obligation at transition'', as well as the amortization of all adjustments incurred during the current Ñscal year arising from revisions made to the actuarial assumptions (the ""actuarial assumption adjustment''). Components of net periodic pension and severance costs (continued) The actuarial assumption adjustment represents the diÅerence between the actual return and the expected return on the plan assets and the diÅerenced arising from computing the projected beneÑt obligation at the end of the year under certain assumptions made at the beginning of the year and the actual projected beneÑt obligation computed at the end of the year. The actuarial assumption adjustment is amortized over a period, which must fall within the average estimated remaining years of service of the active participants in the plan. Under U.S. GAAP, net periodic pension cost consists of Ñve components: ""service cost'', ""interest cost'', ""amortization of unrecognized prior service cost'', ""gain or loss (including the eÅect of any changes in assumptions) to the extent recognized'', and ""actual return on plan assets''. Gain or loss represents any changes in either the amount of the projected beneÑt obligation or the plan assets arising from the diÅerences between the anticipated balance and the actual balance, which have resulted from changes in the underlying assumptions. The unrecognized net gain or loss is generally amortized using the corridor approach. Recognition of liability Under the Japanese accounting standard for pension and severance costs, the excess of the projected beneÑt obligation (as adjusted for the unrecognized beneÑt obligation at transition, the unrecognized prior service cost and the actuarial assumption adjustment) over the fair value of the plan assets at the balance sheet date is accounted for as liability. Under U.S. GAAP, an additional minimum liability is accounted for if the accumulated beneÑt obligation is greater than the fair value of the plan assets at the balance sheet date (the ""unfunded accumulated beneÑt obligation''). This additional minimum liability is computed by adding the unfunded 123
prepaid pension cost to the accumulated beneÑt obligation, or by deducting the accrued pension cost from the unfunded accumulated beneÑt obligation. 10.
Capitalization of Interest Expenses
Interest expenses of debts utilized for the construction of electric utility power plants have been capitalized and included in the cost of the related assets pursuant to the accounting regulations (the ministerial ordinance No. 57 of June 15, 1965 of the Ministry of Economy, Trade and Industry) established by the Electricity Utilities Industry Law. Under U.S. GAAP, during the period in which the structures qualifying as assets are under construction, an entity is required to allocate and capitalize the related interest expense incurred. 11.
Derivatives and Hedging Activities
Under Japanese GAAP, all derivative instruments are carried at fair value with any changes in value credited or charged to current period income unless certain hedge accounting criteria are met. However, if the derivative instruments are used as hedges and meet the hedging criteria, any gain or loss arising resulting from changes in the fair value of the derivative instruments is deferred as either an asset or a liability until the related loss or gain on the underlying hedged items is recognized. In addition, when the principal terms of the interest-rate swaps are matched to the hedged assets or liabilities, the interest-rate swaps are not required to be measured at fair value but the respective periodic diÅerences in interest receipt and payment are recognized on a accrual basis and accounted for as adjustments to the interest income or expenses of the hedged assets or liabilities. Special hedge accounting for forward foreign exchange is described in Item 11. Under U.S. GAAP, all derivatives are recognized as assets or liabilities in the balance sheet and measured at fair value. Changes in the fair value of derivatives are included in earnings unless the derivative qualiÑes under speciÑc hedge accounting criteria. The method of accounting adopted for any changes in the fair value of derivatives, which qualify for hedge accounting, depends on the intended use. For derivatives designated as hedge against exposure to changes in the fair value of an asset or liability or a Ñrm commitment, the related gain or loss is recognized in earnings in the period of change, together with the oÅsetting fair value loss or gain on the hedged item. For derivatives designated as hedges against exposure to the variable cash Öows of a forecasted transaction, the eÅective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income. Gain or loss on cash Öow hedges included in other comprehensive income is reclassiÑed to earnings in the same period or in the periods during which the related asset or liability aÅects earnings. 12.
Reserve for Fluctuation in Water Levels
To oÅset Öuctuations in income caused by high water levels or by drought conditions in connection with hydroelectric power generation, the Company recorded reserve for Öuctuation in water levels under ""Ministerial Ordinance Concerning Reserve for Fluctuation in Water Levels'' (the ministerial ordinance No. 56 of June 15, 1965 of the Ministry of Economy, Trade and Industry) stipulated by Article 36 of the Electricity Utilities Industry Law. 13.
Foreign Currency Transactions
Under Japanese GAAP, forward foreign exchange contracts are carried at fair value with any changes in value credit charged to current income unless certain hedge accounting criteria are met. However, if the forward foreign exchange contracts qualify as hedges, gain or loss resulting from changes in fair value of derivative instruments are deferred as either an asset or liability until the related loss or gain on the hedged items is recognized. In addition, when the principal terms of foreign exchange contracts are matched to the hedged foreign currency denominated assets or liabilities, the foreign exchange contracts are not required to be measured at fair value but the hedged foreign currency denominated assets or liabilities are measured at the respective contract rates. 124
Under U.S. GAAP, all forward foreign exchange contracts are recognized as assets or liabilities in the balance sheet and measured at fair value. Changes in the fair value of derivatives are included in earnings unless the hedge accounting criteria described in Item 10 above are met. 14.
Goodwill
Under Japanese GAAP, goodwill recognized under the Commercial Code is amortized over a period of 5 years or less. Other goodwill recognized upon consolidation of the subsidiaries is amortized over a period of 20 years or less. Under U.S. GAAP, starting for Ñscal years ending after December 15, 2001, goodwill is not amortized but is subject to an annual impairment test under SFAS 142, ""Goodwill and Other Intangible Assets.'' To the extent that negative goodwill exists, after reassessing whether all assets acquired and liabilities assumed have been identiÑed and properly valued, an extraordinary gain should be recognized in the period in which the business combination is initially recognized. 15.
Extinguishment of Financial Liabilities
Under U.S. GAAP, the debtor derecognizes Ñnancial liabilities only if either of the following conditions is met: ‚
The debtor pays the creditor and is relieved of its obligation for the liability; or
‚
The debtor is legally released from being the primary obligor under the liability, either judicially or by the creditor.
Under Japanese GAAP as well, the debtor basically derecognizes Ñnancial liabilities only if either of the above conditions is met. However, special treatment is permitted for an in-substance defeasance of corporate debentures. Although an in-substance defeasance generally does not qualify for derecognition of a recourse to the issuer of the debentures is remote and if certain other conditions are met. 16.
Bonuses to Directors and Statutory Auditors
Under Japanese GAAP, bonuses to directors and statutory auditors are accounted for as an appropriation of retained earnings and are charged directly to retained earnings after approval by the shareholders. Under U.S. GAAP, such bonuses are accounted for as expenses and are charged to current operations for the year. 17.
Accounting for guarantees
Under Japanese GAAP, guarantee contracts that contain Ñnancial, performance, indemniÑcation and indirect guarantees are treated as oÅ-balance sheet and disclosed if material. Under U.S. GAAP, FASB Interpretation No. 45, ""Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others'', speciÑes that guarantees issued or modiÑed after December 31, 2002 are to be recorded and measured initially at its fair value. A guarantee contingently requires the guarantor to make payments to the guaranteed or indemniÑed party based on changes in an underlying that is related to an asset, liability or an equity security of the guaranteed party or based on another entity's failure to perform under and obligating agreement. 18.
Recent Changes in U.S. GAAP
The Financial Accounting Standards Board (""FASB'') issued Statement of Financial Accounting Standard (""SFAS'') No. 143, ""Accounting for Asset Retirement Obligations''. This Statement requires legal obligations associated with retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Initial adoption of SFAS 143 125
would result in a cumulative eÅect of a change in accounting principles. SFAS 143 is eÅective for years beginning after June 15, 2002. In January 2003, the FASB issued FASB Interpretation 46, ""Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51'' (FIN 46). In December 2003, the FASB modiÑed FIN 46 to make certain technical corrections and address variable interest entities (VIEs) and determining when a company should include the assets, liabilities, noncontrolling interests and results of activities of a VIE in its consolidated Ñnancial statements. FIN 46 addresses how a business enterprise should evaluate whether it has a controlling Ñnancial interest in an entity through means other than voting rights and accordingly should consolidate the entity. For non-public companies, the provisions of FIN 46, as revised, is eÅective, for all VIEs created before January 1, 2004, no later than the beginning of the Ñrst annual reporting period beginning after December 15, 2004.
126
