Annual Reports

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  • 20-F (Apr 24, 2017)
  • 20-F (Apr 29, 2016)
  • 20-F (Apr 30, 2015)
  • 20-F (Apr 30, 2014)
  • 20-F (Apr 30, 2013)

 
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Korea Electric Power 20-F 2009
Form 20-F
Table of Contents

As filed with the Securities and Exchange Commission on June 24, 2009

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 20-F

 

 

(Mark One)

 

¨ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

 

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

OR

 

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

For the transition period from              to             

Commission File Number: 001-13372

 

 

KOREA ELECTRIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

N/A   The Republic of Korea
(Translation of registrant’s name into English)   (Jurisdiction of incorporation or organization)

 

 

411 YOUNGDONG-DAERO, GANGNAM-GU, SEOUL 135-791, KOREA

(Address of principal executive offices)

 

 

Seung Bum Kim, +822 3456 4264, sbkim96@kepco.co.kr, +822 556 3694

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

 

 

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

 

Title of each class:

 

Name of each exchange on which registered:

Common stock, par value Won 5,000 per share*   New York Stock Exchange
American depositary shares, each representing
one-half of share of common stock
  New York Stock Exchange

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

None

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

7 3/4% Debentures due April 1, 2013

Twenty Year 7.40% Amortizing Debentures, due April 1, 2016

One Hundred Year 7.95% Zero-to-Full Debentures, due April 1, 2096

6% Debentures due December 1, 2026

7% Debentures due February 1, 2027

6 3/4% Debentures due August 1, 2027

 

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the last full fiscal year covered by the annual report:

641,567,712 shares of common stock, par value of Won 5,000 per share

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files):    Yes  ¨    No  ¨

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

Large accelerated filer  þ                    Accelerated filer  ¨                    Non-accelerated filer  ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP  ¨                 International Financial Reporting Standards as issued by the International Accounting Standards Board  ¨            Other  þ

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.    Item 17  ¨    Item 18  þ

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

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes  ¨    No  ¨

 

* Not for trading, but only in connection with the listing of American depositary shares on the New York Stock Exchange, pursuant to the requirements of the Securities and Exchange Commission.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page

CERTAIN DEFINED TERMS

   1

FORWARD-LOOKING STATEMENTS

   1

PART I

   2

        ITEM 1.

 

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

   2

        ITEM 2.

 

OFFER STATISTICS AND EXPECTED TIMETABLE

   2

        ITEM 3.

 

KEY INFORMATION

   2
 

Selected Financial Data

   2
 

Risk Factors

   5

        ITEM 4.

 

INFORMATION ON THE COMPANY

   13
 

History And Development

   13
 

Business Overview

   14
 

Property, Plant And Equipment

   57

        ITEM 4A.

 

UNRESOLVED STAFF COMMENTS

   58

        ITEM 5.

 

OPERATING AND FINANCIAL REVIEW AND PROSPECTS

   58
 

Operating Results

   58
 

Liquidity And Capital Resources

   69
 

Research And Development, Patents And Licenses, Etc.

   90
 

Trend Information

   90

        ITEM 6.

 

DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

   91
 

Directors And Senior Management

   91
 

Employees

   96

        ITEM 7.

 

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

   97
 

Major Shareholders

   97
 

Related Party Transactions

   97

        ITEM 8.

 

FINANCIAL INFORMATION

   99
 

Consolidated Statements And Other Financial Information

   99

        ITEM 9.

 

THE OFFER AND LISTING

   100

        ITEM 10.

 

ADDITIONAL INFORMATION

   105
 

Articles Of Incorporation

   105
 

Exchange Controls

   111
 

Taxation

   116
 

Documents On Display

   127

        ITEM 11.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   127

        ITEM 12.

 

DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

   132

PART II

   133

        ITEM 13.

 

DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

   133

        ITEM 14.

 

MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

   133

        ITEM 15.

 

CONTROLS AND PROCEDURES

   133

        ITEM 16A.

 

AUDIT COMMITTEE FINANCIAL EXPERT

   134

        ITEM 16B.

 

CODE OF ETHICS

   134

        ITEM 16C.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

   135

        ITEM 16D.

 

EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE

   135

        ITEM 16E.

 

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

   135

        ITEM 16F.

 

CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANTS

   135

        ITEM 16G.

 

CORPORATE GOVERNANCE

   136

PART III

   139

        ITEM 17.

 

FINANCIAL STATEMENTS

   139

        ITEM 18.

 

FINANCIAL STATEMENTS

   139

        ITEM 19.

 

EXHIBITS

   139


Table of Contents

CERTAIN DEFINED TERMS

All references to “Korea” or the “Republic” in this annual report on Form 20-F, or this report, are references to The Republic of Korea. All references to the “Government” in this report are references to the government of the Republic. All references to “we,” “us,” the “Company” or “KEPCO” in this report are references to Korea Electric Power Corporation and, as the context may require, its subsidiaries. All references to “the Ministry of Knowledge Economy” and “the Ministry of Strategy and Finance” include the respective predecessors thereof. All references to “tons” are to metric tons, equal to 1,000 kilograms, or 2,204.6 pounds. Any discrepancies in any table between totals and the sums of the amounts listed are due to rounding. All references to “Korean GAAP” in this report are references to the accounting guidelines under the Korea Electric Power Corporation Act, the Accounting Regulations for Public Enterprise Associate Government Agency and accounting principles generally accepted in the Republic of Korea, and all references to “U.S. GAAP” in this report are references to accounting principles generally accepted in the United States.

FORWARD-LOOKING STATEMENTS

This report includes future expectations, projections or “forward-looking statements” (as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934). The words “believe,” “expect,” “anticipate,” “estimate” and similar words identify forward-looking statements. In addition, all statements other than statements of historical facts included in this report are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report.

This report discloses, under the caption “Item 3. Key Information—Risk Factors” and elsewhere, important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”). All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the Cautionary Statements.

 

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PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

SELECTED FINANCIAL DATA

The following table sets forth certain selected consolidated financial data of us. The selected consolidated financial data in the table have been derived from our audited consolidated financial statements for each of the years in the five-year period ended December 31, 2008. The consolidated financial statements as of and for the years ended December 31, 2007 and 2008 have been audited by Deloitte Anjin LLC, a member firm of Deloitte Touche Tohmatsu. Deloitte Anjin LLC is a Korean independent registered public accounting firm, our current independent registered public accounting firm. The consolidated financial statements as of and for the years ended December 31, 2004, 2005, and 2006 have been audited by KPMG Samjong Accounting Corp., a Korean corporation, which is a member of KPMG International, a Swiss cooperative. The selected consolidated financial data should be read in conjunction with our consolidated financial statements and notes thereto as of December 31, 2007 and 2008 and for the years ended December 31, 2006, 2007 and 2008.

Our consolidated financial statements are prepared in accordance with the Korea Electric Power Corporation Act, the Accounting Regulations for Public Enterprise Associate Government Agency and Korean GAAP, which differ in certain significant respects from U.S. GAAP. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Reconciliation to U.S. GAAP” and Note 36 of the notes to our consolidated financial statements.

Consolidated Statement of Earnings Data

 

     2004    2005    2006    2007    2008  
     (in billions of Won and millions of US$, except per share data)  

Amounts in Accordance with Korean GAAP(1):

                

Operating revenues

   (Won) 23,956    (Won) 25,445    (Won) 27,409    (Won) 29,137    (Won) 31,560     $ 25,008  

Operating expenses

     19,488      21,523      24,014      26,316      34,358       27,225  

Operating income (loss)

     4,467      3,922      3,395      2,822      (2,798 )     (2,217 )

Income (loss) before income taxes

     4,700      3,825      3,369      2,393      (3,844 )     (3,046 )

Income tax expenses (benefits)

     1,795      1,392      1,123      926      (930 )     (737 )

Net income (loss)

     2,883      2,432      2,246      1,467      (2,914 )     (2,309 )

Earnings (loss) per share

                

Basic

     4,576      3,790      3,488      2,294      (4,746 )     (3.76 )

Diluted

     4,510      3,766      3,389      2,258      (4,746 )     (3.76 )

Earnings (loss) per ADS

                

Basic

     2,288      1,895      1,744      1,147      (2,373 )     (1.88 )

Diluted

     2,255      1,883      1,695      1,129      (2,373 )     (1.88 )

Dividends per share

     1,150      1,150      1,000      750      —         —    

 

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     2004    2005    2006    2007    2008  
     (in billions of Won and millions of US$, except per share data)  

Amounts in Accordance with U.S. GAAP(2):

                

Operating revenue(3)

   (Won) 23,995    (Won) 25,445    (Won) 27,408    (Won) 29,189    (Won) 31,634     $ 25,066  

Operating income (loss)

     4,860      4,380      3,727      3,231      (2,971 )     (2,354 )

Net income (loss)

     3,535      2,970      2,645      1,835      (3,819 )     (3,026 )

Earnings (loss) per share

                

Basic

     5,612      4,675      4,146      2,952      (6,134 )     (4.86 )

Diluted

     5,529      4,645      4,028      2,946      (6,134 )     (4.86 )

Earnings (loss) per ADS

                

Basic

     2,806      2,338      2,073      1,476      (3,067 )     (2.43 )

Diluted

     2,765      2,323      2,014      1,473      (3,067 )     (2.43 )

Dividend per share

     1,150      1,150      1,000      750      —         —    

Other Data:

                

Ratio of earnings to fixed charges(4):

                

Korean GAAP

     4.6      4.8      3.8      3.1      (3.2 )     (3.2 )

U.S. GAAP(2)

     5.0      5.3      4.2      3.7      (3.9 )     (3.9 )

Consolidated Balance Sheet Data

 

     As of December 31,  
     2004     2005     2006    2007     2008  
     (in billions of Won and millions of US$, except per share data)  

Amounts in Accordance with Korean GAAP(2):

             

Net working capital surplus (deficit)( 5)

   (Won) (2,291 )   (Won) (130 )   (Won) 171    (Won) (3 )   (Won) (197 )   $ (156 )

Property, plant and equipment, net

     55,809       56,651       56,874      57,739       59,618       47,241  

Construction in progress

     7,517       7,355       8,393      9,824       10,178       8,065  

Total assets

     73,654       74,737       79,241      82,929       88,199       69,888  

Total stockholders’ equity

     40,602       42,338       43,235      44,267       41,275       32,706  

Common stock

     3,204       3,208       3,208      3,208       3,208       2,542  

Long-term debt (excluding current portion)

     15,073       15,494       15,428      16,121       23,319       18,478  

Other long term liabilities

     9,719       9,767       11,924      13,204       13,069       10,356  

Amounts in Accordance with U.S. GAAP(2):

             

Total assets

     65,310       66,864       72,513      76,616       82,230       65,159  

Total liabilities

     31,563       30,892       34,601      37,403       46,687       36,994  

Total stockholders’ equity

     33,747       35,972       37,912      39,213       35,230       27,916  

 

Notes:

 

(1) See Item 5. “Operating and Financial Review and Prospects—Operating Results” for discussion of certain changes in Korean GAAP.
(2) For discussion of significant differences between the application of Korean GAAP and U.S. GAAP, see Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Reconciliation to U.S. GAAP” and Note 36 of the notes to our consolidated financial statements.
(3) For discussion of significant differences in revenue recognition under Korean GAAP and U.S. GAAP, see Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Reconciliation to U.S. GAAP” and Note 36(a) of the notes to our consolidated financial statements.

 

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(4) For purposes of computing ratios of earnings to fixed charges, earnings consist of earnings before income taxes and fixed charges. Fixed charges consist of interest expense (including capitalized interest) and amortization of bond discount and issue expenses.
(5) Net working capital means current assets minus current liabilities.

Currency Translations and Exchange Rates

In this annual report, unless otherwise indicated, all references to “Won” or “(Won)” are to the currency of the Republic, and all references to “U.S. dollars,” “Dollars,” “$” or “US$” are to the currency of the United States of America. Unless otherwise indicated, all translations from Won to U.S. dollars were made at (Won)1,262.00 to US$1.00, which was the noon buying rate in the City of New York for cable transfers as certified for customs purposes by the Federal Reserve Bank of New York (the “Noon Buying Rate”) as of December 31, 2008. The source of these rates is the Federal Reserve Bank of New York until December 31, 2008. Since January 1, 2009, the Federal Reserve Bank of New York discontinued publication of foreign exchange rates. The source of the rates since January 1, 2009 is the H.10 statistical release of the Federal Reserve Board. On June 12, 2009, the Noon Buying Rate was (Won)1,246.00 to US$1.00. The Noon Buying Rate has been highly volatile recently and the U.S. dollar amounts referred to in this report should not be relied upon as an accurate reflection of our results of operations. We expect this volatility to continue in the near future. No representation is made that the Won or U.S. dollar amounts referred to in this report could have been or could be converted into U.S. dollars or Won, as the case may be, at any particular rate or at all.

The following table sets forth, for the periods and dates indicated, certain information concerning the Noon Buying Rate in Won per US$1.00.

 

Year Ended December 31,

   At End of Period    Average(1)    High    Low
     (Won per US$1.00)

2004

   1,035.1    1,139.3    1,195.1    1,035.1

2005

   1,010.0    1,023.2    1,059.8    997.0

2006

   930.0    950.1    1,002.9    913.7

2007

   935.8    928.0    950.2    903.2

2008

   1,262.0    1,098.6    1,507.9    935.2

2009 (through June 12)

           

January

   1,380.0    1,356.3    1,391.5    1,292.3

February

   1,532.0    1,439.6    1,532.8    1,368.7

March

   1,372.3    1,449.6    1,570.1    1,334.8

April

   1,277.0    1,332.2    1,378.3    1,277.0

May

   1,249.0    1,254.3    1,277.0    1,232.9

June (through June 12)

   1,246.0    1,244.7    1,258.5    1,232.1

 

Source: Federal Reserve Bank of New York (for the periods ended on or prior to December 31, 2008) and Federal Reserve Board (for the period since January 1, 2009)

Note:

 

(1) Represents the average of the Noon Buying Rates on the last day of each month during the relevant period.

 

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RISK FACTORS

Our business and operations are subject to various risks, many of which are beyond our control. If any of the risks described below actually occurs, our business, financial condition or results of operations could be seriously harmed.

Risks Relating to KEPCO

The Government’s plan for restructuring the electricity industry in Korea may have a material adverse effect on us.

On January 21, 1999, the Ministry of Knowledge Economy announced a restructuring plan for the electricity industry in Korea, or the Restructuring Plan. For a detailed description of the Restructuring Plan, see Item 4 “Information on the Company—Business Overview—Restructuring of the Electricity Industry in Korea.” The Government promulgated the Law on Promotion of Restructuring of Electricity Industry and amended the Electricity Business Law on December 23, 2000, which allowed us to implement the Restructuring Plan. Pursuant to the Law on Promotion of Restructuring of Electricity Industry, in April 2001, the Government established the Korea Power Exchange to handle the sale of electricity and set out regulations governing the electricity industry to allow for electricity distribution through a competitive bidding process, a competitive bidding pool system for the sale and purchase of electricity, and the Korean Electricity Commission to regulate the restructured Korean electricity industry and ensure fair competition. As part of the effort to introduce competition in electricity generation, in April 2001, our non-nuclear and non-hydroelectric generation units were split into five wholly-owned generation subsidiaries and our nuclear and hydroelectric generation unit became a separate wholly-owned generation subsidiary of us. In September 2003, the Tripartite Commission, which included, among others, representatives from the Government and the leading businesses and labor unions in Korea, established the Joint Study Group on Reforming Electricity Distribution Network to propose a methodology of introducing competition for the distribution of electricity. In June 2004, based on a report published by this Joint Study Group, the Tripartite Commission issued a resolution that recommended halting the plan to form and privatize new distribution subsidiaries, and in lieu thereof, creating independent business divisions within us, namely, the “strategic business units,” as a way of improving operational efficiency and internal competition among the business divisions. This resolution was adopted by the Ministry of Knowledge Economy in June 2004, and we subsequently commissioned a third-party consultant to conduct a study on implementing plans related to the creation of the strategic business units and solicited comments on the study from various parties, including labor unions and the Government. Based on this study and the related comments, on September 25, 2006, we established nine strategic business units with a separate management structure having limited autonomy, separate financial accounting, and performance evaluation criteria, which, together with certain of our other business units, were restructured into 13 integrated business units with a focus on profit maximization in December 2008 following a two-year evaluation period.

Other than as set forth herein, we are not aware of any specific plan by the Government to resume the implementation of the Restructuring Plan or otherwise change the current structure of the electricity industry in the near future. However, for reasons relating to a change in Government policy, economic and market conditions and/or other factors, the Government may resume the implementation of the Restructuring Plan or initiate other steps that may change the structure of the Korean electricity. Any such measures may have a negative effect on our business, results of operation and financial condition.

In December 2008, the Government announced the fourth Basic Plan relating to the future supply and demand of electricity. The fourth Basic Plan focuses on, among other things, (1) ensuring that electricity generation conforms to the National Energy Basic Plan relating to the overall energy management policy for Korea, including in areas of demand management, target nuclear power generation, and a greater emphasis on renewable energy and (2) improving the accuracy of electricity supply forecast based primarily on expected fuel prices, generation efficiency and technological advances, in addition to the mandates under the previous third Basic Plan, including (3) establishing an optimal level and mix of generating capacity based on fuel types and the operational efficiency of each generation unit, (4) equilibrating the supply and demand of electricity at the regional level through region-specific planning for capacity expansion, (5) setting high priority to environmental

 

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issues by proactively addressing some of the concerns identified under the Kyoto Protocol to the United Nations Framework Convention on Climate Change, and (6) improving the transparency and accountability in the decision-making process for formulating the basic plan by formalizing more compartmentalized processes and procedures, including seeking advice from outside experts. We cannot assure that the fourth Basic Plan, or the plans subsequently adopted, will successfully achieve their intended goals, the foremost of which is to formulate a capacity expansion plan that will result in balanced overall electricity supply and demand in Korea at an affordable cost to the end users.

Further changes in the law and regulation relating to the electricity industry in Korea and the Government’s plan, including any amendments thereto, for the electricity industry in Korea or its restructuring may have a material adverse effect on our business, growth prospects, financial condition and results of operation.

Increases in fuel prices will adversely affect our results of operations and profitability, and we may not be able to pass on the increased cost to consumers at a sufficient level or on a timely basis.

Fuel costs constituted 49.8% and 45.8% of our operating revenues and operating expenses, respectively, in 2008. Our generation subsidiaries purchase substantially all of the fuel that they use (except for anthracite coal) from a limited number of suppliers outside Korea at prices determined in part by prevailing market prices in currencies other than Won. For example, most of the bituminous coal requirements are imported from a limited number of countries principally consisting of Indonesia, Australia and China, which accounted for approximately 40.6%, 34.3% and 11.2%, respectively, of the annual bituminous coal requirements of our generation subsidiaries in 2008. Approximately 82.6% of the bituminous coal requirements of our generation subsidiaries in 2008 were purchased under long-term contracts and the remaining 17.4% from the spot market. Pursuant to the terms of our long-term supply contracts, prices are adjusted annually in light of market conditions. In addition, our generation subsidiaries purchase a significant portion of their fuel requirements under contracts with limited duration. See Item 4. “Information on the Company—Business Overview—Fuel.”

In recent years, the prices of bituminous coal, oil and liquefied natural gas, or LNG, have fluctuated significantly, resulting in a higher fuel cost to us. For example, the average “free on board” Newcastle coal price index sharply rose from US$48.9 per ton in 2006, to US$65.3 per ton in 2007 and US$128.4 per ton in 2008, and was US$70.5 per ton as of June 19, 2009. The prices of oil and LNG are substantially dependent on the price of crude oil, and according to Bloomberg (Bloomberg Ticker: PGCRDUBA), the average daily spot price of Dubai crude oil rose from US$68.37 per barrel in 2007 to US$93.78 per barrel in 2008 and was US$71.09 per barrel on June 18, 2009. We expect that fuel prices will remain high throughout 2009 and thereafter. If fuel prices increase sharply within a short span of time, our generation subsidiaries may be unable to secure requisite bituminous coal supplies at prices comparable to those of prior periods. In addition, any significant interruption or delay in the supply of fuel, bituminous coal in particular, from any of their suppliers may cause our generation subsidiaries to purchase fuel on the spot market at prices higher than contracted, resulting in an increase in our fuel cost.

Because the Government regulates the rates we charge for the electricity we sell to our customers (see Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates”), our ability to pass on such cost increases to our customers is limited. In addition, partly because the Government may have to undergo a lengthy deliberative process to approve a rise in electricity tariff, which represents a key component of the consumer price index, we may not be able to adjust the electricity tariff to a level sufficient to ensure a fair rate of return to us in a timely manner or at all. For example, in 2008 for the first time in our operating history we incurred net losses in the amount of (Won)2,914 billion largely due to the rapid rise in fuel prices, and while the Government raised the overall average electricity tariff by 4.5% in November 2008, there is no assurance that such tariff increase will be sufficient to fully offset the adverse impact from the rise in fuel costs on our business or results of operation. We estimate that the recent spike in fuel prices may continue to have a material adverse effect on our results of operations and profitability in 2009 and beyond. We are currently negotiating with the Government for further tariff increase, but cannot assure that the Government will agree to such increase at the level desired by us or at all. If the fuel prices remain at the current level or continue to

 

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increase and the Government, out of concern for inflation or for other reasons, maintains the current level of electricity tariff or does not increase it to a level to sufficiently offset the impact of rising fuel prices, the fuel price increases will significantly narrow our profit margins or even cause us to suffer net losses and our business, financial condition, results of operations and cash flows would seriously suffer.

The movement of Won against the U.S. dollar and other currencies may have a material adverse effect on us.

The Won has fluctuated significantly against major currencies in recent years. In particular, as liquidity and credit concerns and volatility in the global financial markets increased significantly since the second quarter of 2008, the value of Won relative to the U.S. dollar has depreciated at an accelerated rate. The Noon Buying Rate per one U.S. dollar depreciated from (Won)936.6 on January 2, 2008 to (Won)1,570.1 on March 2, 2009, and was (Won)1,246.0 on June 12, 2009. The depreciation of Won against U.S. dollar and other foreign currencies in the past had resulted in a material increase in the cost of servicing our foreign currency debt and the cost of fuel materials and equipment purchased from overseas. As of December 31, 2008, approximately 29.4% of our long-term debt (including the current portion thereof) was denominated in foreign currencies, principally in U.S. dollar, Yen and Euro. The prices for substantially all of the fuel materials and a significant portion of the equipment we purchase are stated in currencies other than Won, generally in U.S. dollars. Since substantially all of our revenues are denominated in Won, we must generally obtain foreign currencies through foreign-currency denominated financings or from foreign currency exchange markets to make such purchases or service such debt. As a result, any significant depreciation of Won against U.S. dollar or other foreign currencies will have a material adverse effect on our profitability and results of operations.

The proliferation of a competing system which enables regional districts to independently source electricity would erode our market position and hurt our business, growth prospects, revenues and profitability.

In July 2004, the Government adopted the Community Energy System to enable regional districts to source electricity from independent power producers to supply electricity without having to undergo the cost-based pool system used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. A supplier of electricity under the Community Energy System must be authorized by the Korea Electricity Commission and be approved by the Minister of Knowledge Economy in accordance with the Electricity Business Act. The purpose of this system is to decentralize electricity supply and thereby reduce transmission costs and improve the efficiency of energy use. These entities do not supply electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System. As of April 30, 2009, six districts were using this system and 14 other districts were preparing to launch it. The generation capacity installed or under construction of the electricity suppliers in these 20 districts amounted to approximately 1% of the aggregate generation capacity of our generation subsidiaries as of April 30, 2009. Since the introduction of the Community Energy System in 2004, a total of 31 districts have obtained the license to obtain electricity supply through the Community Energy System, but 11 of such districts have reportedly abandoned plans to adopt the Community Energy System and four more districts are reportedly considering abandoning such plans, largely due to the relatively high level of capital expenditure required, the rise in fuel costs and the lower-than-expected electricity output per cost. However, if the Community Energy System is widely adopted, it will erode our market position in the generation and distribution of electricity in Korea, which has been virtually monopolized by us until recently, and may have a material adverse effect on our business, growth, revenues and profitability.

Labor unrest may adversely affect our operations.

As of December 31, 2008, approximately 64% of the employees of our non-nuclear generation subsidiaries were members of the Korean Power Plant Industrial Union, and approximately 61% of the employees of KHNP, our nuclear generation subsidiary were members of the Korean Hydro & Nuclear Power Labor Union. The Restructuring Plan and the privatization plan for our non-nuclear generation subsidiaries generated labor unrest in 2002. Labor unions to which our employees and the employees of our generation subsidiaries belong have

 

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opposed the Restructuring Plan from its inception. In particular, the prospect of privatizing some of our core assets has raised concerns among some of our employees. On February 25, 2002, employees belonging to labor unions of our five non-nuclear generation subsidiaries began a six-week strike to protest the Government’s plans to privatize the five non-nuclear generation subsidiaries. The Korean Confederation of Trade Unions, the second largest confederation of labor unions in Korea with over 650,945 members as of December 31, 2008, negotiated with the Government on behalf of the labor unions. After prolonged negotiations with the Government, the Korean Confederation of Trade Unions directed the labor unions of our five non-nuclear generation subsidiaries to end their strike on April 2, 2002. There was no material disruption in the operation of generation subsidiaries as a result of such labor strike.

In June 2005, the Government announced its policy to relocate the headquarters of government-invested enterprises, including us and our six generation and certain other subsidiaries, out of the Seoul metropolitan area to other provinces in Korea by the end of 2012. Pursuant to this policy, our headquarters are scheduled to be relocated to Naju in Jeolla Province, which is approximately 300 kilometers south of Seoul, by the end of 2012. In addition, the headquarters of certain of our subsidiaries are scheduled to be relocated to various other cities in Korea. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Capital Requirements” for further details. Under a special act related to such relation, we are required to sell the building and land for our current headquarters in Samseong-dong by the end of 2012. While we intend to comply with the relocation plan, there can be no assurance that the labor unions that our employees and the employees of our subsidiaries belong to will not oppose the relocation. We cannot assure you that a large-scale strike will not occur in the future, including, among others, as a result of the Government’s policy to move our headquarters out of the Seoul metropolitan area, or that any such labor unrest will be satisfactorily resolved. A large-scale strike may adversely affect our results of operations, including by severely disrupting the power supply as well as substantially hindering the implementation of our strategies and management policies.

Operation of nuclear power generation facilities inherently involves numerous hazards and risks, any of which could result in a material loss of revenues or increased expenses.

Through Korea Hydro & Nuclear Power Co., Ltd., or KHNP, our wholly-owned nuclear subsidiary, we currently operate 20 nuclear-fuel generation units. The operation of nuclear power plants is subject to certain hazards, including environmental hazards such as leaks, ruptures and discharge of toxic and radioactive substances and materials. These hazards can cause personal injuries or loss of life, severe damage to or destruction of property and natural resources, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Nuclear power has a stable cost structure, which is also least costly among the fuel types that comprise the base load and is the second largest source of Korea’s electricity supply, accounting for 35.6% of electricity generated in Korea in 2008. Due to significantly lower unit fuel costs compared to those for conventional power plants, our nuclear power plants are generally operated at full capacity with only routine shutdowns for check-up and overhaul lasting 32 days on average in 2008. In December 2003, in response to concerns of potential exposure to radioactive materials arising from a release incident, we shut down Younggwang-5, one of our nuclear power plants for assessment, inspection and overhaul. This nuclear power plant resumed its operations in April 2004. In November 2003, we shut down Younggwang-6, another of our nuclear power plants for planned overhaul, during which a mechanical problem was discovered giving rise to concerns of its safety. After the overhaul, this nuclear power plant resumed its operations in April 2004. The breakdown, failure or suspension of operation of a nuclear unit could result in a material loss of revenues, an increase in fuel costs related to the use of alternative power sources, additional repair and maintenance costs, greater risk of litigation and increased social and political hostility to the use of nuclear power, any of which could have a material adverse impact on our financial conditions and results of operation.

Opposition to the construction and operation of nuclear-fuel generation units may have an adverse effect on us.

In 2008, our nuclear generation units accounted for 35.6% of the electricity generated in Korea. In recent years, we have encountered increasing social and political opposition to the construction and operation of nuclear

 

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generation units. Although we and the Government have undertaken various community programs to address concerns of residents in areas near our nuclear units, community opposition to the construction and operation of nuclear units could result in delayed construction or relocation of planned nuclear units, which could have a material adverse impact on our business and results of operation. See Item 4. “Information on the Company—Business Overview—Power Generation—Korea Hydro & Nuclear Power Co., Ltd.,” “—Business Overview—Community Programs” and “—Business Overview—Insurance.”

The amount and scope of coverage of our insurance are limited.

Substantial liability may result from the operations of our nuclear generation units, the use and handling of nuclear fuel and possible radioactive emissions associated with such nuclear fuel. While KHNP carries insurance for its generation units and nuclear fuel transportation, the level of insurance is generally adequate and is in compliance with relevant laws and regulations, and KHNP is the beneficiary of a certain Government indemnity which covers a portion of liability in excess of the insurance, such insurance is limited in terms of amount and scope of coverage and does not cover all types or amounts of losses which could arise in connection with the ownership and operation of nuclear plants. Accordingly, material adverse financial consequences could result from a serious accident to the extent neither insured nor covered by the government indemnity.

In addition, our non-nuclear generation subsidiaries carry insurance covering certain risks, including fire, in respect of their key assets, including buildings and equipment located at their respective power plants, construction-in-progress and imported fuel and procurement in transit. Such insurance and indemnity, however, cover only a portion of the assets that we and our generation subsidiaries own and operate and do not cover all types or amounts of loss that could arise in connection with the ownership and operation of these power plants. In addition, unlike us, our generation subsidiaries are not permitted to self-insure, and accordingly have not self-insured, against risks of their uninsured assets or business. Accordingly, material adverse financial consequences could result from a serious accident to the extent uninsured.

Because we and our non-nuclear generation subsidiaries do not carry insurance against terrorist attacks, an act of terrorism would result in significant financial losses. See Item 4. “Information on the Company—Business Overview—Insurance.”

We may require a substantial amount of additional indebtedness to refinance existing debt and for future capital expenditures.

We anticipate that additional indebtedness will be required through the coming years in order to refinance existing debt and make capital expenditures for construction of generation plants and other facilities. The amount of such additional indebtedness may be substantial. We expect that a portion of our long-term debt will need to be raised through foreign currency borrowings and issuance of securities in international capital markets. The cost of such financing, especially in light of the significant depreciation of the Won against the U.S. dollar and other major foreign currencies in light of the recent global financial crisis and economic downturn, may not be acceptable to us.

We may not be able to raise equity capital in the future without the participation of the Government.

Under applicable laws, the Government is required to own directly, or through Korea Development Bank (a statutory banking institution wholly-owned by the Government), at least 51% of our issued capital stock. As of December 31, 2008, the Government, directly or through Korea Development Bank, owned 51.07% of our issued capital stock. Accordingly, without changes in the existing Korean law, it may be difficult or impossible for us to undertake, without the participation of the Government, any equity financing in the future (other than sales of treasury stock).

 

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Risks Relating to Korea and the Global Economy

Adverse developments in Korea may adversely affect us.

Our financial condition and results of operations are subject to political, economic, legal and regulatory risks specific to Korea, where most of our assets are located and where we generate most of our income.

Since July 2007, significant adverse developments in the U.S. sub-prime mortgage sector have created much disruption and volatility in financial markets globally. The ensuing contraction of liquidity and credit and deteriorations in asset values has had contagion effects on the overall economy. Starting in the second half of 2008, the world’s largest economies, including the United States, Europe and Japan, are widely considered to be in the midst of significant economic recessions, and export-driven emerging economies such as China and Korea have also suffered substantial weakening in their economies. The Korean economy experienced a contraction in real gross domestic product by 3.4% and 4.3% in the fourth quarter of 2008 and the first quarter of 2009 compared to corresponding quarters year on year, respectively. Partly as a result thereof, particularly the resulting slowdown in industrial activities, demand for electricity decreased by 2.3% from the first quarter of 2008 to the first quarter of 2009. There is no assurance when and to what extent the global or Korean economy will recover, as future recovery or growth of an economy is subject to many factors beyond our control. Events related to terrorist attacks, developments in the Middle East, higher oil and other commodity prices and the outbreak of endemics such as SARS or the H5N1 avian flu in Asia or the H1N1 swine flu in Mexico and other parts of the world have increased and may continue to increase the uncertainty of global economic prospects in general and the Korean economy in particular. Any further deterioration of the Korean economy could further lower demand for electricity in Korea, which would in turn negatively impact our financial condition and results of operations.

Developments that could hurt Korea’s economy in the future include:

 

   

financial and other problems of chaebols (Korean conglomerates) or their suppliers and their potential adverse impact on the Korean economy;

 

   

loss of investor confidence arising from corporate accounting irregularities and corporate governance issues at certain companies or introduction of new Government policies or regulations adverse to foreign investment;

 

   

a slowdown in consumer spending, a rising level of household debt and the resulting slowdown in the overall economy;

 

   

adverse changes or volatility in foreign currency reserve levels, commodity prices (including an increase in coal, oil and LNG prices), exchange rates (including depreciation of U.S. dollar or Yen or revaluation of Renminbi), interest rates and stock markets;

 

   

adverse developments in the economies in other markets, including countries that are important export markets for Korea, such as the United States, Japan and China, or in emerging economies in Asia or elsewhere that could result in a loss of confidence in the Korean economy;

 

   

the continued emergence of China, to the extent related benefits (such as increased exports to China) are outweighed by related costs (such as competition in export markets or for foreign investment and the relocation of the manufacturing base from Korea to China);

 

   

social and labor unrest;

 

   

a decrease in tax revenues and a substantial increase in the Government’s expenditures for unemployment compensation and other social programs that, together, would lead to an increased government budget deficit;

 

   

deterioration in economic or diplomatic relations between Korea and its trading partners or allies, including deterioration resulting from trade disputes or disagreements in foreign policy;

 

   

political uncertainty or increasing strife among or within political parties in Korea;

 

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hostilities involving oil producing countries in the Middle East and any material disruption in the supply of oil or increase in the price of oil resulting from those hostilities; and

 

   

an increase in the level of tensions or an outbreak of hostilities between the Democratic People’s Republic of Korea, or North Korea, and Korea and/or the United States.

Tensions with North Korea could have an adverse effect on us and the market value of our shares.

Relations between Korea and North Korea have been tense throughout Korea’s modern history. The level of tension between Korea and North Korea has fluctuated and may increase or change abruptly as a result of current and future events, including ongoing contacts at the highest levels of the governments of Korea and North Korea and the relationship between North Korea and the United States. In recent years, there have been heightened security concerns stemming from North Korea’s nuclear weapons and long-range missile programs and uncertainty regarding North Korea’s actions and possible responses from the international community. On March 9, 2009, North Korea suspended transport of personnel and materials via land route in and out of Gaeseong Industrial Complex in protest against an annual joint military exercise by Korea and the United States, but fully reopened the borders on March 17, 2009. On April 5, 2009, North Korea launched a long-range rocket into the Pacific Ocean, claiming that the launch was intended to put an orbital satellite into space. On April 13, 2009, the United Nations Security Council unanimously passed a resolution that condemned North Korea for the launch and decided to tighten sanctions against North Korea. In response, on April 14, 2009 North Korea announced that it would permanently withdraw from nuclear disarmament talks and restart its nuclear program. On May 25, 2009, North Korea announced that it had successfully conducted a second nuclear test and test-fired three short-range, surface-to-air missiles. In addition, there recently has been increased uncertainty about the future of North Korea’s political leadership and its implications for the economic and political stability in the region. There can be no assurance that the level of tension and instability in the Korean peninsula will not escalate in the future, or that the political regime in North Korea may not suddenly collapse. Any further increase in tension or uncertainty relating to the military, political or economic stability in the Korean peninsula, including a breakdown of diplomatic negotiations over the North Korean nuclear program, occurrence of military hostilities or heightened concerns about the stability of North Korea’s political leadership, could have a material adverse effect on our business, financial condition and results of operation and could lead to a decline in the market value of our common shares and our American depositary shares.

Unemployment and labor unrest in Korea may adversely affect us.

The economic downturn in Korea in 1997 and 1998 and the increase in the number of corporate reorganizations and bankruptcies thereafter caused layoffs and increasing unemployment in Korea, which partly contributed to large-scale protests and labor strikes in Korea in 1998 and 1999. There is no assurance that the ongoing difficulties of the Korean economy will not result in similar developments in the future. According to statistics from Korea National Statistical Office, the unemployment rate was 3.3% as of December 31, 2008 compared to 3.1% as of December 31, 2007. An increase in unemployment or labor unrest in Korea could adversely affect our operations and the financial conditions of Korean companies in general, depressing the price of securities on the Korean securities exchanges and the value of the Won relative to other currencies. These developments would likely have an adverse effect on the price of our common stock and our American depositary shares.

Financial instability in Korea and other countries, particularly emerging market countries, may adversely affect us.

The Korean market and economy are influenced by economic and market conditions in other countries, including emerging market countries. Past financial turmoil in Asia and elsewhere in the world has adversely affected the Korean economy. Although economic conditions are different in each country, investors’ reactions to developments in one country, such as Argentina or Brazil, could have adverse effects on the price of securities of companies in other countries, including Korea. A loss of investor confidence in the financial systems of

 

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emerging and other markets, including as a result of the ongoing weakness in the global credit and financial markets, has recently increased volatility in the Korean financial markets and may continue to do so and may even worsen. We cannot assure you that the financial crisis of the type that occurred in emerging markets in Asia in 1997 and 1998 will not happen again or be managed with minimal harm, either of which contingency may have a material adverse effect on our business and results of operation.

Our consolidated financial statements are prepared in accordance with Korean GAAP, which differ in significant respects from U.S. GAAP.

Our consolidated financial statements are prepared in accordance with Accounting Regulations for Public Enterprise Associate Government Agency and Korean GAAP, which differ in certain significant respects from U.S. GAAP.

Korean GAAP and U.S. GAAP differ, among other ways, in respect of the following issues:

 

   

treatment of asset revaluation;

 

   

treatment of foreign exchange translation gains and losses; and

 

   

the establishment of regulatory asset and liability to offset the impact of foreign exchange translation losses and gains on our income statement, deferred income taxes and reserves for self-insurance; and

 

   

treatment of liabilities for decommissioning costs.

See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Reconciliation to U.S. GAAP” and Note 36 of the notes to our consolidated financial statements.

We are generally subject to Korean corporate governance and disclosure standards, which differ in significant respects from those in other countries.

Companies in Korea, including us, are subject to corporate governance standards applicable to Korean public companies which differ in many respects from standards applicable in other countries, including the United States. As a reporting company registered with the Securities and Exchange Commission and listed on the New York Stock Exchange, we are, and will continue to be, subject to certain corporate governance standards as mandated by the Sarbanes-Oxley Act of 2002, as amended. However, foreign private issuers, including us, are exempt from certain corporate governance standards required under the Sarbanes-Oxley Act or the rules of the New York Stock Exchange. For a description of significant differences in corporate governance standards, see Item 16G. “Corporate Governance.” There may also be less publicly available information about Korean companies, such as us, than is regularly made available by public or non-public companies in other countries. Such differences in corporate governance standards and less public information could result in less than satisfactory corporate governance practices or disclosure to investors in certain countries.

 

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ITEM 4. INFORMATION ON THE COMPANY

HISTORY AND DEVELOPMENT

General Information

Our legal and corporate name is Korea Electric Power Corporation. We were established by the Government on December 31, 1981 as a statutory juridical corporation in Korea under the Korea Electric Power Corporation (“KEPCO”) Act as the successor to Korea Electric Company. Our registered office is located at 411 Youngdong-daero, Gangnam-Gu, Seoul, Korea, and our telephone number is 82-2-3456-4264. Our website address is www.kepco.co.kr. Our agent in the United States is Korea Electric Power Corporation, New York Office, located at 16th Floor, 400 Kelby Street, Fort Lee, NJ 07024.

The Korean electric utility industry traces its origin to the establishment of the first electric utility company in Korea in 1898. On July 1, 1961, the industry was reorganized by the merger of Korea Electric Power Company, Seoul Electric Company and South Korea Electric Company, which resulted in the formation of Korea Electric Company. From 1976 to 1981, the Government acquired the private minority shareholdings in Korea Electric Company. After the Government acquired all the remaining shares of Korea Electric Company, Korea Electric Company dissolved, and we were incorporated in 1981 and assumed the assets and liabilities of Korea Electric Company. We ceased to be wholly-owned by the Government in 1989 when the Government sold 21.0% of our common stock. As of December 31, 2008, the Government owned in aggregate 51.07% (including indirect holdings by Korea Development Bank, which is wholly-owned by the Government) of the outstanding shares of our common stock, and there has been no change in such percentage ownership to-date.

Under relevant laws of Korea, the Government is required to own, directly or through Korea Development Bank, at least 51% of our capital. Direct or indirect ownership of more than 50% of our outstanding common stock enables the Government to control the approval of certain corporate matters which require a stockholders’ resolution, including approval of dividends. The rights of the Government and Korea Development Bank as holders of our common stock are exercised by the Ministry of Knowledge Economy, based on the Government’s ownership of our common stock and a proxy received from Korea Development Bank in consultation with the Ministry of Strategy and Finance.

We operate under the general supervision of the Ministry of Knowledge Economy. The Ministry of Knowledge Economy, in consultation with the Ministry of Strategy and Finance, is responsible for approving the electric power rates we charge after review by the Korean Electricity Commission. See Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates.” We furnish reports to officials of the Ministry of Knowledge Economy, the Ministry of Strategy and Finance and other Government agencies and regularly consult with such officials on matters relating to our business and affairs. See Item 4. “Information on the Company—Business Overview—Regulation.” Our non-standing directors, which comprise the majority of our board of directors, must be appointed by the Ministry of Strategy and Finance following the review and resolution of the Public Agencies Operating Committee from a pool of candidates recommended by our director nomination committee, and our President must be appointed by the President of the Republic upon the motion of the Ministry of Knowledge Economy following the nomination by our director nomination committee, the review and resolution of the Public Agencies Operating Committee and an approval at the general meeting of shareholders. See Item 6. “Directors, Senior Management and Employees—Board of Directors.”

 

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BUSINESS OVERVIEW

Introduction

We are an integrated electric utility company engaged in the transmission and distribution of substantially all of the electricity in Korea. Through our six consolidated generation subsidiaries, we also generate substantially all of the electricity produced in Korea. As of December 31, 2008, we and our generation subsidiaries owned approximately 87.6% of the total electricity generating capacity in Korea (excluding plants generating electricity primarily for private or emergency use). In 2008, we sold 385 billion kilowatt-hours of electricity. Of the 405 billion kilowatt-hours of electricity we purchased in 2008, 36.1% was generated by Korea Hydro & Nuclear Power Co., Ltd., our wholly-owned nuclear and hydroelectric power generation subsidiary. We also wholly own our five non-nuclear generation subsidiaries, Korea South-East Power Co., Ltd, or KOSEP, Korea Midland Power Co., Ltd., or KOMIPO, Korea Western Power Co., Ltd., or KOWEPO, Korea Southern Power Co., Ltd., or KOSPO, and Korea East-West Power Co., Ltd., or EWP , each of which is incorporated in Korea. We derive substantially all of our revenues and profit from Korea.

In 2008, we had consolidated operating revenues of (Won)31,560 billion (US$25,008 million) and consolidated net loss of (Won)2,914 billion (US$2,309 million). In 2007, we had consolidated operating revenues of (Won)29,137 billion and consolidated net income of (Won)1,467 billion. Our operating revenues increased primarily as a result of a 4.5% increase in kilowatt hours of electricity sold in 2008. The increase in electricity sold was primarily attributable to a 4.4% increase in kilowatt hours of electricity sold to the industrial sector, a 5.6% increase in kilowatt hours of electricity sold to the commercial sector and a 2.8% increase in kilowatt hours of electricity sold to the residential sector. See Item 5. “Operating and Financial Review and Prospects—Operating Results.

Demand for electricity in Korea grew at a compounded average rate of 5.6% per annum for the five years ended December 31, 2008 compared to real gross domestic product, GDP, which grew at a compounded growth rates of approximately 4.2% for the same period according to The Bank of Korea. The GDP growth rate was 2.2% for 2008 as compared to 5.1% in 2007. Demand for electricity in Korea increased by 4.5% from 2007 to 2008.

Historically, we have made substantial expenditures for the construction of generation plants and other facilities to meet increased demand for electric power. Subject to the Restructuring Plan as discussed in “—Restructuring of the Electricity Industry in Korea” below, we and our generation subsidiaries plan to continue to make substantial expenditures to expand and enhance our generation, transmission and distribution system in the future. See Item 5. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Capital Requirements.”

Prior to the corporate reorganization effected on April 2, 2001, which created six generation subsidiaries wholly owned by us, we were the principal electricity generation company in Korea. We continue to be the principal electricity transmission and distribution company in Korea, and we expect to remain so subject to the implementation of the Restructuring Plan.

We play an important role in the implementation of the Government’s national energy policy, which is established in consultation with us. As an entity formed to serve public policy goals of the Government, we seek to maintain an overall level of profitability which allows us to strengthen our equity base in order to support the growth in our business.

Our electricity rates are established by the Government pursuant to procedures that take into account, among others, our needs to recover the costs of operations, make capital investments and provide a fair return to our security holders, as well as the Government’s overall policy considerations, such as inflation. See Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates.”

 

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Recent Developments

Tariff Increase

In light of the rapid rise in fuel prices following the general rise in commodity prices (including oil) worldwide in the second half of 2007 and the first half of 2008 which seriously undermined our profitability, effective November 13, 2008, the Ministry of Knowledge Economy increased the industrial, commercial, educational and street lighting rates by 8.1%, 3.0%, 4.5% and 4.5%, respectively, while making no changes to the residential and agricultural rates. These rate changes are expected to result in an increase one-time by 4.5% in our overall average rate. In addition, apart from the tariff increase, in December 2008, the Government provided us with a subsidy in the amount of (Won)668 billion to compensate us, at least partly, for the sharp rise in fuel prices. We do not believe that such rate increase will be sufficient to fully offset the adverse impact from the rise in fuel costs on our business or results of operations. There is no assurance that the Government will further raise the tariff rates in the future to a level or in an amount sufficient to fully offset the adverse impact from the rise in fuel costs or at all. We are currently negotiating with the Government for further tariff increases, but cannot guarantee that the Government will agree to such increase at the level desired by us or at all.

The Fourth Basic Plan Relating to the Supply and Demand of Electricity in Korea

In December 2008, the Government announced the fourth Basic Plan relating to the future supply and demand of electricity. The fourth Basic Plan focuses on, among other things, (1) ensuring that electricity generation conforms to the National Energy Basic Plan relating to the overall energy management policy for Korea, including in areas of demand management, target nuclear power generation, and a greater emphasis on renewable energy and (2) improving the accuracy of electricity supply forecast based primarily on expected fuel prices, generation efficiency and technological advances, in addition to the mandates under the previous third Basic Plan, including (3) establishing an optimal level and mix of generating capacity based on fuel types and the operational efficiency of each generation unit, (4) equilibrating the supply and demand of electricity at the regional level through region-specific planning for capacity expansion, (5) setting high priority to environmental issues by proactively addressing some of the concerns identified under the Kyoto Protocol to the United Nations Framework Convention on Climate Change, and (6) improving the transparency and accountability in the decision-making process for formulating the basic plan by formalizing more compartmentalized processes and procedures, including seeking advice from outside experts. We cannot assure that the fourth Basic Plan, or any other plan subsequently adopted, will successfully achieve its intended goals, the foremost of which is to formulate a capacity expansion plan that will result in balanced overall electricity supply and demand in Korea at an affordable cost to the end users.

Internal Corporate Reorganization

Following two-year evaluations of our pre-existing organizational model and in response to the rapidly changing economic conditions in light of the global liquidity and economic crisis beginning in the second half of 2008, we effected in December 2008 internal corporate reorganization, the primary goal of which was to transform us into a more efficient and profit-oriented organization by aligning our business units along the lines of profit generation rather than cost control. As a result, based on positive customer feedback relating to the nine strategic units, we have expanded the concept of autonomous business units to apply sales offices as well as other branch offices and the electricity management division so that our business will be managed by 13 autonomous integrated regional business units, each of which is responsible for transmission, distribution and sales of electricity in a given region. We also plan to strengthen performance evaluation systems based on profit-oriented metrics and adopt a six-sigma approach to further foster quality control in our operations. See “—Restructuring of the Electricity Industry in Korea—Suspension of the Plan to Form and Privatize Distribution Subsidiaries.”

Audit Committee

In September 2007, we amended our Articles of Incorporation to establish, in lieu of the pre-existing board of auditors, an audit committee meeting the requirements under the Sarbanes-Oxley Act. At an extraordinary

 

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general meeting of our shareholders held on December 8, 2008, we appointed three members of our board of directors, namely Kang, Seong-Chul, Kim, Sun-Jin and Kim, Jung-Kook, to the newly established audit committee. These members currently remain as members of our committee and all such members of the audit committee are independent within the meaning of the Korea Stock Exchange listing standards, the regulations promulgated under the Financial Investment Services and Capital Markets Act and the New York Stock Exchange listing standards. For more information, see Item 6. “Directors, Senior Management and Employees—Audit Committee.”

Restructuring of the Electricity Industry in Korea

On January 21, 1999, the Ministry of Knowledge Economy published the Restructuring Plan. The overall objectives of the Restructuring Plan are to:

 

   

introduce competition and thereby increase efficiency in the Korean electricity industry,

 

   

ensure a long-term, inexpensive and stable electricity supply, and

 

   

promote consumer convenience through the expansion of consumer choice.

The KEPCO Act requires that the Government own at least 51% of our capital stock. Direct or indirect ownership of more than 50% of our outstanding common stock enables the Government to control the approval of certain corporate matters which require a stockholders’ resolution, including approval of dividends. The rights of the Government and Korea Development Bank as holders of our common stock are exercised by the Ministry of Knowledge Economy in consultation with the Ministry of Strategy and Finance. The Government currently has no plan to cease to own, directly or indirectly, at least 51% of our outstanding common stock.

The following is a description of the Restructuring Plan and the Government’s position relating to the Restructuring Plan as of the date of this report.

Phase I

During Phase I, which was the preparation stage for Phase II and ran from January 1999 to April 2001, we continued to be the principal electricity generator, with a few independent power producers supplying electricity to us under existing power purchase agreements. In February 2001, our board of directors approved a plan to split our non-nuclear and non-hydroelectric generating capacity into five separate wholly-owned generation subsidiaries, namely, KOMIPO, KOSEP, KOWEPO, KOSPO and EWP, each with its own management structure, assets and liabilities. Our hydroelectric and nuclear generating capacity was transferred into a separate wholly-owned generation subsidiary, KHNP. On March 16, 2001, our shareholders approved the plan to establish the generation subsidiaries in April 2001.

The Government’s objectives in dividing the power generation capacity into separate generation subsidiaries were principally to:

 

   

introduce competition and thereby increase efficiency in the electricity generation industry in Korea, and

 

   

ensure the stable supply of electricity in Korea.

Following the implementation of Phase I, we retained, until the adoption of the Community Energy System in July 2004 as further discussed in “—Transmission and Distribution” below, our monopoly position with respect to the transmission and distribution of electricity in Korea.

While our ownership percentage of the non-nuclear and non-hydroelectric generation subsidiaries will depend on the ultimate form of the Restructuring Plan approved by the Government, we plan to continue to retain 100% ownership of both KHNP and our transmission and distribution business.

 

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Phase II

Phase II, which is the current phase, began in April 2001. For Phase II, the Government introduced a competitive or bidding pool system under which we purchase power from the generation subsidiaries and other companies for transmission and distribution to customers. Such competitive bidding pool system was established in April 2001 and is a cost-based system. For a further description of the pool system, see “—Power Purchase—Cost-based Pool System” below.

Pursuant to the Electricity Business Law, the Government established the Korea Power Exchange in April 2001 to deal with the sale of electricity and implement regulations governing the electricity market to allow for electricity distribution through a competitive bidding process. The Government also established the Korea Electricity Commission in April 2001 to regulate the restructured Korean electricity industry and to ensure fair competition. As part of this process, the Korea Power Exchange established the Electricity Market Rules relating to the operation of the bidding pool system. To amend the Electricity Market Rules, the Korea Power Exchange must have the proposed amendment reviewed by the Korea Electricity Commission and then obtain the approval of the Ministry of Knowledge Economy.

The Korea Electricity Commission’s main functions include implementation of necessary standards and measures for electricity market operation and review of matters relating to licensing participants in the Korean electricity industry. The Korea Electricity Commission also acts as an arbitrator in disputes involving utility rates and participants in the Korean electricity industry and consumers and investigates illegal or deceptive activities of the participants in the Korean electricity industry.

Privatization of Non-nuclear Generation Subsidiaries

In April 2002, the Ministry of Knowledge Economy released the basic privatization plan for five of our generation subsidiaries other than our nuclear and hydroelectric power generation subsidiary. Pursuant to this plan, we commenced the process for selling Korea South-East Power Co., Ltd., or KOSEP, in 2002. According to the original plan, this process was, in principle, to take the form of a sale of management control, potentially supplemented by an initial public offering as a way of broadening the investor base. In November 2003, KOSEP submitted its application to the Korea Exchange for a preliminary screening review, which was approved in December 2003. However, in June 2004, KOSEP made a request to the Korea Exchange to delay its stock listing due to unfavorable stock market conditions at that time. We intend to resume the stock listing process for KOSEP in due course, after taking into consideration the overall stock market conditions and other pertinent matters. The aggregate foreign ownership of our generation subsidiaries is limited to 30% of total power generation capacity in Korea. In consultation with us, the Government will determine the size of the ownership interest to be sold and the timing of sales, with a view to encouraging competition and assuring adequate electricity supply and debt service capability.

We believe the Government currently has no specific plans to resume the public offering of KOSEP or commence the same for any of our other generation subsidiaries in the near future, and neither we nor any of our generation subsidiaries were mentioned as targets of privatization as announced by the Government in August and October, 2008. However, we cannot assure that our generation subsidiaries will not become part of Government-led privatization initiatives in the future for reasons relating to a change in Government policy, economic and market conditions and/or other factors.

Suspension of the Plan to Form and Privatize Distribution Subsidiaries

In September 2003, the Tripartite Commission, which included, among others, representatives from the Government and the leading businesses and labor unions in Korea, established the Joint Study Group on Reforming Electricity Distribution Network to propose a methodology of introducing competition for the distribution of electricity. In June 2004, based on a report published by this Joint Study Group, the Tripartite Commission issued a resolution that recommended halting the plan to form and privatize new distribution

 

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subsidiaries, and in lieu thereof, creating independent business divisions within us, namely, the “strategic business units,” as a way of improving operational efficiency and internal competition among the business divisions. This resolution was adopted by the Ministry of Knowledge Economy in June 2004, and we subsequently commissioned a third-party consultant to conduct a study on implementing plans related to the creation of the strategic business units and solicited comments on the study from various parties, including labor unions and the Government. Based on this study and the related comments, in September 2006, we established nine strategic business units with a separate management structure having limited autonomy, separate financial accounting, and performance evaluation criteria

Following two-year evaluations of this organization model and in response to the rapidly changing economic conditions in light of the global liquidity and economic crisis beginning in the second half of 2008, in December 2008, we effected internal corporate reorganization, the primary goal of which was to transform us into a more efficient and profit-oriented organization by aligning our business units along the lines of profit generation rather than cost control. As a result, based on positive customer feedback relating to the nine strategic units, we have expanded the concept of autonomous business units to apply to sales offices as well as other branch offices and the electricity management division so that our businesses will be managed by 13 autonomous integrated regional business units, each of which is responsible for transmission, distribution and sales of electricity in a given region. We also plan to strengthen performance evaluation systems based on profit-oriented metrics and adopt a six-sigma approach to further foster quality control in our operations.

Other than as set forth herein, we are currently unaware of any Government initiative to restructure the electricity industry in Korea, including with respect to creating new distribution subsidiaries.

Power Purchase

Cost-based Pool System

Since April 2001, the purchase and sale of electricity in Korea is required to be made through the Korea Power Exchange, which is a statutory not-for-profit organization established under the Electricity Business Act with responsibilities for setting the price of electricity, handling the trading and collecting relevant data for the electricity market in Korea. The suppliers of electricity in Korea consist of our six generation subsidiaries, which were spun off from us in April 2001, and independent power producers, which numbered 288 as of December 31, 2008. We distribute electricity purchased through the Korea Power Exchange to the end users.

We have certain relationships with the Korea Power Exchange as follows: (i) we and our six generation subsidiaries are member corporations of the Korea Power Exchange and collectively own 100% of its share capital; (ii) three of the 10 members of the board of directors of the Korea Power Exchange are currently our or our subsidiaries’ employees; and (iii) one of our employees is currently a member in three of the key committees of the Korea Power Exchange that are responsible for evaluating the costs of producing electricity, making rules for the Korea Power Exchange and gathering and disclosing information relating to the Korean electricity market. Notwithstanding the foregoing relationships, however, we have neither control nor significant influence over the Korea Power Exchange or its policies since, among others, (i) the Korea Power Exchange, its personnel, policies, operations and finances are closely supervised and controlled by the Government, namely through the Ministry of Knowledge Economy, and are subject to a host of laws and regulations, including, among others, the Electricity Business Act and the Public Agencies Management Act, as well as the Articles of Incorporation of the Korea Power Exchange, (ii) we are entitled to elect no more than one-third of the Korea Power Exchange directors and our representatives represent only a minority of its board of directors and committees (with the other members being comprised of representatives of the Ministry of Knowledge Economy, employees of the Korea Power Exchange, businesspersons and/or scholars) and (iii) the role of our representatives in the policy making process for the Korea Power Exchange is primarily advisory based on their technical expertise derived from their employment at us or our generation subsidiaries. Consistent with this view, the Finance Supervisory Service issued a ruling on April 12, 2005 that stated that we are not deemed to have significant influence or control over the decision-making process of the Korea Power Exchange relating to its business or financial affairs.

 

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The price of electricity in the Korean electricity market is determined principally based on the cost of generating electricity using a system known as the “cost-based pool” system. Under the cost-based pool system, the price of electricity has two principal components, namely the marginal price (representing in principle the variable cost of generating electricity) and the capacity price (representing in principle the fixed cost of generating electricity).

Marginal price

The primary purpose of the marginal price is to compensate the generation companies for fuel costs, which represents the principal component of the variable costs of generating electricity. The concept of marginal price under the cost-based pool system has undergone several changes in recent years in large part due to the sharp fluctuations in fuel prices. For example, prior to December 31, 2006, the marginal price operated on a two-tiered structure, namely, a “base load” marginal price applicable to electricity generated from nuclear fuels and coals, which tend to be less expensive per unit of electricity generated from liquefied natural gas, oil and hydroelectric power to which a “non-base load” marginal price applied. The base load marginal price and the non-base marginal price were generally set at levels so that electricity generated from cheaper fuels could be utilized first while ensuring a relatively fair rate of return to all generation units. However, when the price of coal rose sharply beginning in the second half of 2006, the pre-existing base load marginal price was abolished and a market cap by the name of “regulated market price” was introduced in its stead for electricity generated from base load fuels, with the regulated market price being set at a level higher than the pre-existing base load marginal price in order to compensate the generation subsidies for the rapid rise in the price of coal. However, when the price of coal continued to rise sharply above the level originally assumed in setting the regulated market price, this had the effect of undercutting our profit margin as the purchaser of electricity from our generation subsidiaries, although the generation subsidiaries were able to maintain a better margin under the regulated market price regime than under the pre-existing base load marginal price regime. Accordingly, on May 1, 2008, the regulated market price regime was abolished, and the current system of “system marginal price” was introduced in order to set the marginal price in a more flexible way by using the concept of an “adjustment coefficient” tailored to each fuel type.

Under the system marginal price regime currently in effect, the marginal price of electricity at which our generation subsidiaries sell electricity to us is determined using the following formula:

Variable cost + [System marginal price – Variable cost] * Adjusted coefficient

The system marginal price represents, in effect, the marginal price of electricity at a given hour at which the projected demand for electricity and the projected supply of electricity for such hour intersect, as determined by the merit order system, which is a system used by the Korea Power Exchange to allocate which generation units will supply electricity for such hour and at what price. To elaborate, the projected demand for electricity for a given hour is determined by the Korea Power Exchange based on forecast one day prior to trading, and such forecast takes into account, among others, historical statistics relating to demand for electricity nationwide by day and by hour, including seasonality and peak-hour versus non-peak hour demand analysis. The projected supply of electricity at a given hour is determined as the aggregate of the available capacity of all generation units that have submitted bids to supply electricity for such hour; such bids are submitted to the Korea Power Exchange one day prior to trading.

Under the merit order system, the generation unit with the lowest variable cost of producing electricity among all the generation units that have submitted a bid for a given hour is first awarded a purchase order for electricity up to the available capacity of such unit as indicated in its bid. The generation unit with the next lowest variable cost is then awarded a purchase order up to its available capacity, and so forth, until the projected demand for electricity for such hour is met. We refer to the variable cost of the generation unit that is the last to receive the purchase order for such hour as the system marginal price, which also represents the most expensive

 

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price at which electricity can be supplied at a given hour given the demand and supply for such hour. Generation units whose variable costs exceed the system marginal price for a given hour do not receive purchase orders to supply electricity for such hour. The variable cost of each generation unit is determined by the Cost Evaluation Committee on a monthly basis based on the evaluation of the average unit production cost of generating electricity at such unit during two months prior to such evaluation. The final allocation of electricity supply, however, is further adjusted on the basis of other factors, including the proximity of a generation unit to the geographical area to which power is being supplied, network and fuel constraints and the amount of power loss.

The purpose of the merit order system is to encourage the generating companies to reduce the production costs of generating electricity by making the production process more efficient, sourcing fuels from most cost-effective sources or through other cost savings programs. The additional adjustment mechanism is designed to improve the overall cost-efficiency in the distribution and transmission of electricity to the end-users by adjusting for the distribution and transmission losses.

Under the merit order system, the electricity purchase allocation, the system marginal price and the final allocation adjustment are automatically determined based on an objective formula. The adjusted coefficient, the capacity price and the variable costs are determined in advance of trading by the Cost Evaluation Committee. Accordingly, a supplier of electricity cannot exercise control over the merit order system or its operations to such supplier’s strategic advantage.

The adjusted coefficient applies uniformly to all generation units that use the same type of fuel, and is generally higher for generation units that use fuel types that inherently entail higher construction and maintenance costs, such as nuclear plants. The adjusted coefficient is determined by the Cost Evaluation Committee in principle on an annual basis, although in cases of significant volatility in terms of external factors such as fuel costs and electricity tariff rates, the adjusted coefficient can be adjusted on a quarterly basis.

Capacity Price

In addition to the variable cost of generating electricity, our generation subsidiaries receive payment in the form of capacity price, the purpose of which is to compensate them for the costs of constructing generation facilities and to provide incentives for new construction. The capacity price is determined annually by the Cost Evaluation Committee based on the construction costs and maintenance costs of a standard generation unit and is paid to each generation company for the amount of available capacity indicated in the bids submitted the day before trading. From time to time, the capacity price is adjusted in ways to soften the impact of changes in the marginal pricing over the years on the expected rate of return for our generational subsidiaries. Currently, the capacity price is (Won)7.70/kWh and since January 1, 2009 has applied equally to all generation units, regardless of fuel types used.

Effective as of January 1, 2007, a regionally differentiated capacity price system was introduced by setting a standard capacity reserve ratio in the range of 12% to 20% in order to prevent excessive capacity build-up as well as induce optimal capacity investment at the regional level. The capacity reserve ratio is the ratio of peak demand to the total available capacity. Under this system, generation units in a region that do not meet the standard capacity reserve ratio (which indicates that in such region available capacity is not sufficient to meet demand for electricity) receive increased capacity price. On the other hand, generation units in a region that exceeds the standard capacity reserve ratio (which indicates that in such region available capacity exceeds demand for electricity) receive reduced capacity price. Other than such potential regional variation, the capacity price applies uniformly to all generation units regardless of fuel types used.

In connection with the currently suspended plan to form and privatize the distribution subsidiaries (see “—Restructuring of the Electricity Industry in Korea—Suspension of the Plan to Form and Privatize Distribution Subsidiaries”), there was a discussion of replacing the current cost-based pool system with a more market-oriented system known as a two-way bidding pool system based on bidding by a pool of generating companies

 

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on the supply side and a pool of retail distributors (rather than us as the distributor of substantially all of electricity in Korea) on the demand side. However, we believe that due to the indefinite suspension of the restructuring plan, the two-way bidding pool system is unlikely to be adopted in the near future absent any unexpected change in government policy.

Power Trading Results

The power trading results for our generation subsidiaries for the year ended December 31, 2008 through the Korea Power Exchange are as follows:

 

    

For the Year Ended December 31, 2008

    

Items

   Volume
(Gigawatt
hours)
   Percentage
of Total
Volume
   Sales to
KEPCO
(in billions
of Won)
   Percentage
of
Total Sales
   Unit Price
(Won/kWh)

Generation Companies

   KHNP    145,531    37.1    5,808    21.6    39.9
  

KOSEP

   48,799    12.4    3,104    11.5    63.6
  

KOMIPO

   41,067    10.5    3,606    13.4    87.8
  

KOWEPO

   45,266    11.5    3,687    13.7    81.4
  

KOSPO

   48,767    12.4    4,649    17.3    95.3
  

EWP

   48,282    12.3    3,886    14.5    80.5
  

Others(1)

   14,717    3.8    2,140    8.0    145.4
                           
  

Total

   392,431    100.0    26,880    100.0    68.5
                           

Energy Sources

   Nuclear    144,255    36.8    5,642    21.0    39.1
  

Bituminous coal

   160,404    40.9    8,219    30.6    51.2
  

Anthracite coal

   6,326    1.6    744    2.8    117.6
  

Oil

   8,941    2.3    1,717    6.4    192.1
  

LNG

   4,534    1.2    743    2.8    163.9
  

Combined-cycle

   60,984    15.5    8,690    32.3    142.5
  

Hydro

   3,008    0.8    404    1.5    134.4
  

Pumped-storage

   2,480    0.6    527    2.0    212.4
  

Others

   1,499    0.4    194    0.7    129.7
                           
  

Total

   392,431    100.0    26,880    100.0    68.5
                           

Load

   Base load    309,717    78.9    14,447    53.8    46.7
  

Non-base load

   82,714    21.1    12,432    46.2    150.3
                           
  

Total

   392,431    100.0    26,919    100.0    68.5
                           

 

Note:

 

(1) Others represent independent power producers that trade electricity through the cost-based pool system of power trading.

Power Purchased from Independent Power Producers

In 2008, we purchased an aggregate of 12,389 gigawatt hours of electricity generated by independent power producers under existing power purchase agreements. These purchase were made outside of the cost-based pool system of power trading. These independent power producers had an aggregate capacity of 3,835 megawatts as of December 31, 2008.

Power Generation

The electricity generating systems of our generation subsidiaries as of December 31, 2008 consisted of a total of 444 generation units, including nuclear, thermal, hydro and internal combustion units, which had an aggregate installed generating capacity of 63,529 megawatts as of December 31, 2008. Our thermal units produce

 

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electricity using steam turbine generators and include units fired by coal and oil. Internal combustion units are diesel-fired gas turbine and combined-cycle units. Combined-cycle units consist of either LNG-fired combined-cycle units or oil-fired combined-cycle units. We also purchase power from several generation plants not owned by our generation subsidiaries.

The table below sets forth as of and for the year ended December 31, 2008 the number of units, installed capacity and the average capacity factor for each type of generating facilities owned by our generation subsidiaries.

 

     Number
of Units
   Installed
Capacity(1)
   Average Capacity
Factor(2)
          (Megawatts)    (Percent)

Nuclear

   20    17,716    93.4

Thermal:

        

Coal

   49    23,705    88.8

Oil

   19    4,489    20.2

LNG

   6    1,538    11.2
              

Total thermal

   74    29,732    72.9

Internal combustion

   176    307    30.9

Combined-cycle

   90    11,288    56.4

Hydro

   57    4,450    9.8

Wind

   12    24    24.4

Solar

   13    11    13.5

Fuel cell

   2    0.6    50.3
              

Total

   444    63,529    71.5
              

 

Notes:

 

(1) Installed capacity represents the level of output that may be sustained continuously without significant risk of damage to plant and equipment.
(2) Average capacity factor represents the total number of kilowatt hours of electricity generated in the indicated period divided by the total number of kilowatt hours that would have been generated assuming continuous operation of generation units at installed capacity expressed as a percentage.

The useful life of a unit, assuming no substantial renovation, is approximately as follows: nuclear and thermal, over 40 and 30 years, respectively; internal combustion, over 25 years; and hydroelectric, over 55 years. Substantial renovation can extend the useful life of thermal units by up to 20 years.

We attempt to achieve efficient use of generating resources and diversification of generating capacity by fuel type. In the past, we relied principally upon oil-fired thermal generation units for electricity generation. Since the oil shock in 1974, however, Korea’s power development plans have emphasized the construction of nuclear generation units. While nuclear units are more expensive to construct than non-nuclear units of comparable capacity, nuclear fuel is less expensive than fossil fuels in terms of electricity output per unit cost. However, efficient operation of nuclear units requires that such plants be run continuously at relatively constant energy output levels. As it is impractical to store large quantities of electrical energy, we seek to maintain nuclear power production capacity at approximately the level at which demand for electricity is continuously stable. For production during those times when actual demand exceeds the level of continuous demand, we rely on units fired by fossil fuels and hydroelectric units, which can be started and shut down more quickly and efficiently than nuclear units. Bituminous coal is currently the cheapest thermal fuel per kilowatt-hour of electricity produced, and therefore we seek to maximize the use of bituminous coal for generation needs in excess of the stable demand level, except for meeting short-term surges in demand which require rapid start-up and shutdown. Thermal units fired by LNG, hydroelectric units and gas turbine internal combustion units are the most efficient

 

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types of units for rapid start-ups and shutdowns, and therefore we use such units principally to meet short-term surges in demand. Anthracite coal is a less efficient fuel source than bituminous coal in terms of electricity output per cost.

Our generation subsidiaries have constructed and recommissioned thermal and internal combustion units in order to help meet power demand. Subject to market conditions, our generation subsidiaries plan to continue to add additional thermal and internal combustion units. Such units are generally completed more quickly than new nuclear units.

The table below sets forth for each of the five years ended December 31, 2008 the amount of electricity generated by facilities linked to our grid system and the amount of power used or lost in connection with transmission and distribution.

 

     2004    2005    2006    2007    2008    % of 2008
Gross
Generation(1)
     (in gigawatt hours, except percentages)

Electricity generated by generation subsidiaries:

                 

Nuclear

   130,715    146,779    148,749    142,937    150,958    35.8

Thermal:

                 

Coal

   128,547    134,892    140,346    155,684    174,156    41.2

Oil

   16,084    15,529    14,307    15,703    7,981    1.9

LNG

   733    786    1,258    2,028    1,518    0.4
                             

Total thermal

   145,364    151,207    155,911    173,415    183,655    43.5

Internal combustion

   407    575    677    579    503    0.1

Combined-cycle

   47,652    48,311    54,174    60,465    55,909    13.2
                             

Hydro

   3,042    2,867    2,914    2,779    3,836    0.9
                             

Wind

   11    19    21    21    53    —  
                             

Solar and fuel cells

   —      —      1    5    15    —  

Total generation

   327,191    349,758    362,447    380,201    394,929    93.5

Electricity purchased from others:

                 

Thermal

   12,137    12,559    16,429    20,660    25,699    6.1

Hydro

   2,820    2,322    2,305    2,263    1,727    0.4
                             

Total purchased

   14,957    14,881    18,734    22,923    27,426    6.5

Gross generation

   342,148    364,639    381,181    403,124    422,355    100.0

Auxiliary use(2)

   15,268    16,452    15,812    16,613    17,374    4.1

Pumped-storage(3)

   1,994    1,980    2,315    1,817    3,243    0.8
                             

Total net generation(4)

   324,886    346,207    363,054    384,694    401,726    95.1
                             

Transmission and distribution losses( 5)

   14,490    15,615    14,587    15,345    16,106    4.0

 

Notes:

 

(1) Unless otherwise indicated, the percentages are based on gross generation.
(2) Auxiliary use represents electricity consumed by generation units in the course of generation.
(3) Pumped-storage represents electricity consumed during low demand periods in order to store water which will be utilized to generate hydroelectric power during peak demand periods.
(4) Total net generation is gross generation subtracted by auxiliary and pumped-storage use.
(5) Total transmission and distribution losses divided by total net generation.

 

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The table below sets forth our total capacity at the end of each period (including units generating electricity primarily for sale to us) and peak and average loads in each of the five years ended December 31, 2008.

 

     2004    2005    2006    2007    2008
     (Megawatts)

Total capacity

   59,961    62,258    65,514    68,268    72,491

Peak load

   51,264    54,631    58,994    62,285    62,794

Average load

   39,058    41,625    43,514    46,019    48,082

Korea Hydro & Nuclear Power Co., Ltd.

We commenced nuclear power generation activities in 1978 when our first nuclear generation unit, Kori-1, began commercial operations. On April 2, 2001, we transferred all of our nuclear and hydroelectric power generation assets and liabilities to Korea Hydro & Nuclear Power Co., Ltd, or KHNP.

Currently, KHNP owns and operates 20 nuclear generation units at four power plant complexes in Korea, located in Kori, Wolsong, Yonggwang and Ulchin as well as 27 hydroelectric generation units and 2 solar generation units and 1 wind generation unit.

The table below sets forth as of and for the year ended December 31, 2008 the number of units, installed capacity and the average capacity factor for the three types of generating facilities.

 

     Number of Units    Installed Capacity(1)    Average Capacity
Factor(2)
          (Megawatts)    (Percent)

Nuclear

   20    17,716    93.4

Hydroelectric

   27    537    27.5

Wind

   1    1    6.7

Solar

   2    3    15.3
            

Total

   50    18,257   
            

 

Notes:

 

(1) Installed capacity represents the level of output that may be sustained continuously without significant risk of damage to plant and equipment.
(2) Average capacity factor represents the total number of kilowatt hours of electricity generated in the period divided by the total number of kilowatt hours that would have been generated assuming continuous operation of generation units at installed capacity expressed as a percentage.

We are currently building six additional nuclear generation units, four with a 1,000-megawatt capacity and two with a 1,400 megawatt capacity at the Shin-Kori and Shin-Wolsong sites, respectively. We expect to complete these units between 2010 and 2014. In addition, we plan to build two additional nuclear units, each with a 1,400 megawatt capacity, at the Shin-Ulchin site.

 

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Table of Contents

Nuclear

The table below sets forth certain information with respect to the nuclear generation units of KHNP as of December 31, 2008.

 

Unit

   Reactor
Type(1)
   Reactor
Design(2)
   Turbine and
Generation(3)
   Commencement
of operations
   Installed
Capacity
                         (Megawatts)

Kori-1

   PWR    W    GEC    1978    587

Kori-2

   PWR    W    GEC    1983    650

Kori-3

   PWR    W    GEC    1985    950

Kori-4

   PWR    W    GEC    1986    950

Wolsong-1

   PHWR    AECL    P    1983    679

Wolsong-2

   PHWR    AECL, H    H, GE    1997    700

Wolsong-3

   PHWR    AECL, H    H, GE    1998    700

Wolsong-4

   PHWR    AECL, H    H, GE    1999    700

Yonggwang-1

   PWR    W    W    1986    950

Yonggwang-2

   PWR    W    W    1987    950

Yonggwang-3

   PWR    H, CE    H, GE    1995    1,000

Yonggwang-4

   PWR    H, CE    H, GE    1996    1,000

Yonggwang-5

   PWR    D, CE    D, GE    2002    1,000

Yonggwang-6

   PWR    D, CE    D, GE    2002    1,000

Ulchin-1

   PWR    F    A    1988    950

Ulchin-2

   PWR    F    A    1989    950

Ulchin-3

   PWR    H, CE    H, GE    1998    1,000

Ulchin-4

   PWR    H, CE    H, GE    1999    1,000

Ulchin-5

   PWR    D, CE    D, GE    2004    1,000

Ulchin-6

   PWR    D, CE    D, GE    2005    1,000
                

Total nuclear

               17,716
                

 

Notes:

 

(1) PWR means pressurized light water reactor; PHWR means pressurized heavy water reactor.
(2) W means Westinghouse Electric Company (U.S.A.); AECL means Atomic Energy Canada Limited (Canada); F means Framatome (France); H means Hanjung; CE means Combustion Engineering (U.S.A.); D means Doosan Heavy Industries.
(3) GEC means General Electric Company (UK); P means Parsons (Canada and UK); W means Westinghouse Electric Company (U.S.A.); A means Alsthom (France); H means Hanjung; GE means General Electric (U.S.A.); D means Doosan Heavy Industries.

 

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Table of Contents

The table below sets forth certain information for 2008 with respect to each nuclear generation unit of KHNP. In 2008, the average fuel cost was (Won)4.12 per kilowatt hour.

 

Unit

   Average Capacity
Factor
   Average Fuel Cost Per
kWh
     (Percent)    (Won)

Kori-1

   91.9    4.23

Kori-2

   88.3    4.55

Kori-3

   88.7    4.33

Kori-4

   97.4    4.01

Wolsong-1

   93.0    5.39

Wolsong-2

   92.2    4.99

Wolsong-3

   93.0    5.31

Wolsong-4

   94.5    5.50

Yonggwang-1

   101.0    3.89

Yonggwang-2

   90.1    4.17

Yonggwang-3

   90.3    3.95

Yonggwang-4

   91.7    4.01

Yonggwang-5

   90.1    3.81

Yonggwang-6

   91.0    3.84

Ulchin-1

   98.9    3.76

Ulchin-2

   88.2    3.84

Ulchin-3

   92.0    3.75

Ulchin-4

   100.6    3.31

Ulchin-5

   100.3    3.71

Ulchin-6

   92.9    3.75
         

Total nuclear

   93.4    4.12
         

The average capacity factor of all of our nuclear units in aggregate has been maintained at 87.3% or more in each year since 1995.

Under extended-cycle operations, nuclear units can be run continuously for periods longer than the conventional 12-month period between scheduled shutdowns for refueling and maintenance. This operational strategy of extended cycle has been adopted for all of our pressurized light water reactor units since 1987 and will spread to newly commenced units. The duration of shutdown for routine fuel replacement and maintenance was 32 days on average in 2008.

KHNP’s nuclear units experienced an average of 0.35 unplanned shutdowns per unit in 2008. In the ordinary course of operations, KHNP’s nuclear units routinely experienced damage and wear and tear and were repaired during routine shutdown periods or during unplanned temporary suspensions of operations. No significant damage has occurred in any of KHNP’s nuclear reactors, and no significant nuclear exposure or release incidents have occurred at any of KHNP’s nuclear facilities since the first nuclear plant commenced operations in 1978. See Item 3. “Key Information—Risk Factors—Risks Relating to KEPCO—Operation of nuclear power generation facilities inherently involves numerous hazards and risks, any of which could result in a material loss of revenues or increased expenses.”

 

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Hydroelectric

The table below sets forth as of and for the year ended December 31, 2008 certain information regarding each hydroelectric plant of KHNP.

 

Name (Number of Plants)

  

Classification

   Year Built    Installed Capacity    Average Capacity
Factor for the twelve
months ended
December 31, 2008
               (Megawatts)    (Percent)

Hwacheon

   Dam waterway    1944    108    26.4

Chuncheon

   Dam    1965    60    26.6

Euiam

   Dam    1967    45    36.4

Cheongpyung

   Dam    1943    79    35.4

Paldang

   Dam    1973    120    34.8

Seomjingang

   Basin deviation    1945    35    40.7

Boseonggang

   Basin deviation    1937    4.5    38.0

Kwoesan

   Dam    1957    3    25.6

Anheung

   Dam waterway    1978    0.5    34.2

Kangreung

   Basin deviation    1991    82    —  
               

Total hydroelectric

         537    27.5
               

Solar/Wind

The table below sets forth as of and for the year ended December 31, 2008 certain information regarding each solar and wind plant of KHNP.

 

Name (Number of Plants)

  

Classification

   Year Built    Installed Capacity    Average Capacity
Factor for the Year
Ended

December 31, 2008
               (Megawatts)    (Percent)

Yonggwang

   Solar    2008    3    15.3

Kori

   Wind    2008    1    6.7
               

Total Solar and Wind

         4    —  
               

The Government-owned Korea Water Resources Corporation assumes full control of multi-purpose dams, while KHNP maintains the dams used for power generation. Existing hydroelectric power plants have exploited most of the water resources in the Republic available for commercially viable hydroelectric power generation. Consequently, we expect that no new major hydroelectric power plants will be built in the foreseeable future. Due to the ease of its start-up and shut-down mechanism, hydroelectric power generation is reserved for peak periods.

 

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Table of Contents

Korea South-East Power Co., Ltd.

As of December 31, 2008, Korea South-East Power Co., Ltd., or KOSEP, had a total installed capacity of 8,941 megawatts.

The table below sets forth as of and for the year ended December 31, 2008, for each fuel type, the weighted average age, installed capacity, average capacity factor and average fuel cost of the generation units of KOSEP based upon the net amount of electricity generated.

 

     Weighted
Average Age
of Units
   Installed
Capacity
   Average
Capacity

Factor
   Average Fuel
Cost per kWh
     (Years)    (Megawatts)    (Percent)    (Won)

Bituminous:

           

Samchunpo #1, 2, 3, 4, 5, 6

   17    3,240    89.48    39.64

Yong Hung #1, 2

   2    3,340    74.24    41.87

Anthracite:

           

Yongdong #1, 2

   32    325    72.14    79.12

Oil-fired:

           

Yosu #1, 2

   32    529    13.32    142.96
                   

Total thermal

   12    7,434    76.87    42.35
                   

Combined-cycle and Internal Combustion:

           

Bundang gas turbine #1,2,3,4,5,6,7,8; steam turbine #1, 2

   15    900    48.07    165.33

Pumped-storage:(1)

           

Muju #1, 2

   14    600    7.32    99.29

 

Note:

 

(1) During periods of low energy usage, the pumped-storage stations use electricity from other generating plants to pump water from lower to higher elevations to be available for increased production during periods of peak energy usage or to supplement production in case of unplanned shutdowns at other generating plants.

 

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Table of Contents

Korea Midland Power Co., Ltd.

As of December 31, 2008, Korea Midland Power Co., Ltd., or KOMIPO, had a total installed capacity of 9,505 megawatts.

The table below sets forth as of and for the year ended December 31, 2008, for each fuel type, the weighted average age, installed capacity, average capacity factor and average fuel cost of the generation units of KOMIPO based upon the net amount of electricity generated.

 

     Weighted
Average Age
of Units
   Installed
Capacity
   Average
Capacity

Factor
   Average Fuel
Cost per kWh
     (Years)    (Megawatts)    (Percent)    (Won)

Bituminous:

           

Boryeong #1, 2, 3, 4, 5, 6

   13.9    4,000    92.50    40.64

Anthracite:

           

Seocheon #1, 2

   25.4    400    57.10    100.43

Oil-fired:

           

Jeju #1, 2, 3, 4, 5

   15.5    255    53.03    165.53

LNG-fired:

           

Seoul #4, 5

   38.7    388    26.29    213.01

Incheon #1, 2, 3, 4

   33.3    1,150    6.17    178.13
                   

Total thermal

   21.5    6,193    48.65    55.98
                   

Combined-cycle and internal combustion:

           

Boryeong gas turbine #1, 2, 3, 4, 5, 6, 7, 8; steam turbine #1, 2, 3, 4

   9.7    1,800    39.63    137.29

Incheon gas turbine #1, 2; steam turbine #1

   3.5    504    79.03    131.33
                   

Total

   8.5    2,304    48.24    135.50
                   

Wind-powered:

           

Yangyang #1, 2

   2.6    3    18.21    4.57

Pumped-storage:

           

Yangyang #1, 2, 3, 4

   2.6    1,000    7.82    94.31

Hydroelectric:

           

Yangyang

   3.4    1.4    31.13    0.52

 

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Table of Contents

Korea Western Power Co., Ltd.

As of December 31, 2008, Korea Western Power Co., Ltd., or KOWEPO, had a total installed capacity of 8,885 megawatts.

The table below sets forth as of and for the year ended December 31, 2008 for each fuel type, the weighted average age, installed capacity, average capacity factor and average fuel costs of the generation units of KOWEPO based upon the net amount of electricity generated.

 

     Weighted
Average Age
of Units
   Installed
Capacity
   Average
Capacity

Factor
   Average Fuel
Cost per kWh
     (Years)    (Megawatts)    (Percent)    (Won)

Bituminous:

           

Taean #1, 2, 3, 4, 5, 6, 7, 8

   8.4    4,000    93.5    38.00

Oil-fired:

           

Pyeongtaek #1, 2, 3, 4

   27.1    1,400    15.7    141.97
                   

Total thermal

   13.2    5,400    73.3    43.83
                   

Combined-cycle:

           

Pyeongtaek combined-cycle

   15.8    480    21.7    153.70

West Incheon combined-cycle

   16.5    1,800    65.9    134.65
                   

Total combined-cycle

   16.4    2,280    56.6    136.18
                   

Pumped-storage:

           

Samryangjin #1, #2

   23.1    600    6.8    90.68

Cheongsong #1, #2

   2.1    600    9.2    92.98
                   

Total Pumped-storage

   12.6    1,200    8.0    92.00
                   

Small Hydro:

           

Taean site

   1.3    2.2    20.3    N/A
                   

Total Hydro

   12.6    1,202.2    8.0    92.00
                   

Photovoltaic power generation:

           

Taean site

   3.4    0.12    12.4    N/A

Samryangjin site

   1.1    3    14.8    N/A
                   

Total Photovoltaic

   1.2    3.12    14.7    N/A
                   

Total

   13.9    8,885.32    60.2    67.60
                   

 

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Table of Contents

Korea Southern Power Co., Ltd.

As of December 31, 2008, Korea Southern Power Co., Ltd., or KOSPO, had a total installed capacity of 8,267 megawatts.

The table below sets forth as of and for the year ended December 31, 2008 for each fuel type, the weighted average age, installed capacity, average capacity factor and average fuel cost of the generation units of KOSPO based upon the net amount of electricity generated.

 

    Weighted
Average Age
of Units
  Installed
Capacity
  Average
Capacity

Factor
  Average Fuel
Cost per kWh
    (Years)   (Megawatts)   (Percent)   (Won)

Bituminous:

       

Hadong #1, 2, 3, 4, 5, 6, 7

  9   3,500   99.85   37

Oil-fired:

       

Youngnam #1, 2

  38   400   12.51   170

Nam Jeju #1, 2, 3, 4

  3   200   67.25   175
               

Total thermal

  16   4,100   88.47   45
               

Shin Incheon combined-cycle #9, 10, 11, 12

  12   1,800   81.18   135

Busan combined-cycle #1, 2, 3, 4

  6   1,800   72.86   129

Hallim combined-cycle

  12   105   2.60   270

Nam Jeju internal combustion

  18   40   27.96   145
               

Total combined-cycle and internal combustion

  12   3,745   74.18   132
               

Cheongpyeong Pumped-storage

  30   400   3.13   56

Hankyung Wind

  4   21   26.09   8

Solar

  1   1   13.42   N/A

Korea East-West Power Co., Ltd.

As of December 31, 2008, Korea East-West Power, Co., Ltd., or EWP, had a total installed capacity of 9,501 megawatts.

The table below sets forth as of and for the year ended December 31, 2008, for each fuel type, the weighted average age, installed capacity, average capacity factor and average fuel cost of the thermal units of EWP based upon the net amount of electricity generated.

 

    Weighted
Average Age
of Units
  Installed
Capacity
  Average
Capacity

Factor
  Average Fuel
Cost per kWh
    (Years)   (Megawatts)   (Percent)   (Won)

Bituminous:

       

Dangjin #1, 2, 3, 4, 5, 6,7,8

  5.6   4,000   92.20   38.59

Honam #1, 2

  35.8   500   84.40   57.83

Anthracite:

       

Donghae #1, 2

  9.8   400   81.50   45.20

Oil-fired:

       

Ulsan #1, 2, 3, 4, 5, 6

  32.8   1,800   19.60   144.32
               

Total thermal

  21.0   6,700   71.48   48.39
               

Combined-cycle:

       

Ulsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3

  12.5   1,200   42.88   134.53

Ilsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2

  15.0   900   44.85   174.81
               

Total combined-cycle and internal combustion

  7.3   2,100   43.72   154.67
               

Pumped-storage:

       

Sancheong #1, 2

  11.6   700   7.60   85.55

 

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Table of Contents

The high average age of the oil-fired thermal units owned by our generation subsidiaries is attributable to our historic reliance on oil-fired thermal units as our primary means of electricity generation until mid-1970s. Since then, we have diversified our fuel sources and constructed fewer oil-fired thermal units than units of other fuel types.

Power Plant Remodeling and Recommissioning

Our generation subsidiaries supplement power generation capacity through remodeling or recommissioning of thermal units. The recommissioning includes installation of anti-pollution devices, modification of control systems and overall rehabilitation of existing equipment.

Power Plant Recommissioning

 

Power Plant

 

Capacity

 

Completed (Year)

  Extension   Company

Taean #1~8

 

4,000MW

(500MW×8)

 

FGD(1): 1998 to 2007

SCR(2): 2005 to 2007

EP(3): 1995 to 2007

LNCS(4):1995 to 2007

  Anti-pollution   KOWEPO

Pyeongtaek #1-4

 

1,400 MW

(350×4)

 

FGD(1): 2005

SCR(2): 2006 to 2007

EP(3): 1992

  Anti-pollution   KOWEPO

Seoincheon CC

 

1,800 MW

(gas turbines

150 MW ×8)

(steam turbines

75 MW ×8)

 

LNCS(4): 1992

Gas turbine upgrade

(2003 to 2006)

  Anti-pollution

Efficiency
improvement

  KOWEPO

Honam #1

  250MW   2010   10 years   EWP

Honam #2

  250MW   2010   10 years   EWP

Boryeong #3-6

 

2,000 MW

(500×4)

 

FGD(1): 1996 to 1999

SCR(2): 2006 to 2007

LNCS(4): 1993 to 1994

EP(3): 1984 to 1993

  Anti-pollution   KOMIPO

Incheon #1-4

 

1,150 MW

(250×2,)

(325×2)

 

SCR(2): 2002 to 2005

LNCS(3): 2002 to 2005

  Anti-pollution   KOMIPO

Seoul #4,5

 

287.5MW

(137.5×1)

(250×1)

  SCR(2): 2001 to 2002   Anti-pollution   KOMIPO

Seocheon #1,2

 

400MW

(200×2)

 

FGD(1): 1998

LNCS(4): 2004 to 2005

EP(3): 1982 to 1983

  Anti-pollution   KOMIPO

Incheon #1,2

 

500MW

(250×2)

 

1996(#1)

2002(#2)

  10 years   KOMIPO

Yosu #2

  335MW   2011   30 years   KOSEP

Hadong #1~7

 

3,500MW

(500MW× 7)

 

FGD(1) : 1998 to 2008

EP(3) : 1997 to 2008

LNCS(3) :1997 to 2008

SCR(2): 2006 to 2008

  Anti-pollution   KOSPO

Shin-Incheon CC

 

1,800 MW

(gas turbines
150 MW × 8)

(steam turbines 150 MW × 4)

  LNCS(4): 1996   Anti-pollution   KOSPO

 

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Table of Contents

Power Plant

 

Capacity

 

Completed (Year)

  Extension   Company

Busan CC

 

1,800 MW

(gas turbines
150 MW × 8)

(steam turbines 150 MW × 4)

  LNCS(4) : 2003 to 2004   Anti-pollution   KOSPO

Youngnam #1~2

 

200MW

(100MW × 2)

 

FGD(1): 1999

SCR(2): 2002

EP(3): 1988 to 1990

LNCS(4): 2002-

  Anti-pollution   KOSPO

Namjeju T/P #3~4

 

100MW

(100×2)

 

FGD(1): 2006 to 2007

SCR(2): 2006 to 2007

EP(3): 2006 to 2007

  Anti-pollution   KOSPO

Namjeju D/P #1~4

 

40MW

(10×4)

 

SCR(2): 1999 to 2000

EP(3): 1990 to 1991

  Anti-pollution   KOSPO

 

Notes:

 

(1) FGD means a flue gas desulphurization system.
(2) SCR means a selective catalytic reduction system.
(3) EP means an electrostatic precipitation system.

(4)

LNCS means a low nitrodioxide (NO2) combustion system.

Transmission and Distribution

We currently transmit and distribute substantially all of the electricity in Korea. In addition to us, there were 16 electricity suppliers that are licensed to distribute electricity in 20 districts of Korea as of April 30, 2009. These entities do not supply electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System authorized by the Korea Electricity Commission and approved by the Minister of Knowledge and Economy in accordance with the Electricity Business Act. We also transmit and distribute electricity to these districts. As of April 30, 2009, six districts were using this system, and 14 other districts were preparing to launch it. The generation capacity installed or under construction of the electricity suppliers in the 20 districts amounted to approximately 1% of the generation capacity of our generation subsidiaries as of April 30, 2009. Since the introduction of the Community Energy System in 2004, a total of 31 districts have obtained the license to obtain electricity supply through the Community Energy System, but 11 of such districts have reportedly abandoned plans to adopt the Community Energy System and four more districts are reportedly considering abandoning such plans, largely due to the relatively high level of capital expenditure required, the rise in fuel costs and the lower-than-expected electricity output per cost.

As of December 31, 2008, our transmission system consisted of approximately 29,929 circuit kilometers of lines of 765 kilovolts and others including high voltage direct current lines, and we had 693 substations with an aggregate installed transformer capacity of 237,300 megavolt-amperes.

Our distribution system consists of 96,866 megavolt-amperes of transformer capacity and approximately eight million units of support with a total line length of 410,015 circuit kilometers.

In recent years, we have made substantial investments in our transmission and distribution systems to increase capacity and improve efficiency. Our current projects include increasing capability of the existing lines. Our transmission and distribution loss was 4.01% in 2008. In light of the increased damage to large-scale transmission and distribution facilities due to the global warming, we plan to reinforce stability of our transmission and distribution facilities through stricter design and material specifications. In addition, we also plan to expand underground transmission and distribution facilities to meet customer demand for more

 

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environment-friendly facilities. In order to reduce the interruption time in power distribution, which is an indicator of the quality of electricity transmission, we are also continuing to make investments in upgrading our evaluation technologies, automation of electricity transmission and development of new transmission technologies.

As we anticipate making substantial additions to our generating capacity in the near term, we will need to make significant investments in expanding our transmission and distribution facilities. We will need to make additional capital expenditures to improve existing facilities, strengthen our nationwide power grids and increase the proportion of underground distribution lines.

Some of the facilities we own and use in our distribution system use rights of way and other concessions granted by municipal and local authorities in areas where our facilities are located. These concessions are generally renewed upon expiration.

Fuels

Nuclear

Uranium, the principal fuel source for nuclear power, accounted for 41.0%, 37.6%, and 38.3% of our fuel requirements for electricity generation in 2006, 2007 and 2008, respectively.

All uranium ore concentrates are imported from, and conversion and enrichment of such concentrates are provided by, sources outside Korea (including the United States, United Kingdom, Kazakhstan, France, Russia, Canada and Australia) and are paid for with currencies other than Won, primarily in U.S. dollars.

In order to ensure stable supply, KHNP enters into long-term and medium-term contracts with various suppliers and such supplies are supplemented with fuels purchased in spot markets.

In 2008, KHNP purchased 100%, or 2,499 tons, of its uranium concentrate requirement under long-term supply contracts with suppliers in Australia, Canada, Kazakhstan, France and the United States. Under the long-term supply contracts, the purchase prices of uranium concentrates are adjusted annually based on base prices and spot market prices prevailing at the time of actual delivery. Non-Korean suppliers provide the conversion and enrichment of uranium concentrate, and Korean suppliers provide fabrication of fuel assemblies. Except for certain fixed contract prices, contract prices for processing of uranium are adjusted annually in accordance with the general rate of inflation. KHNP intends to obtain its uranium requirements in the future, in part, through purchases under long-term and medium-term contracts and, in part, through spot market purchases.

Coal

Bituminous coal accounted for 37.1%, 39.4% and 42.2% of our fuel requirements for electricity generation in 2006, 2007 and 2008, respectively, and anthracite coal accounted for 15.8%, 15.9% and 17.6% of our fuel requirements for electricity generation in 2006, 2007 and 2008, respectively.

In 2008, our generation subsidiaries purchased 64.2 million tons of bituminous coal, of which approximately 40.6%, 34.3%, 11.2%, 9.5% and 4.4% were imported from Indonesia, Australia, China, Russia and others, respectively. Approximately 82.6% of the bituminous coal requirements of our generation subsidiaries in 2008 were purchased under long-term contracts with the remaining 17.4% purchased in the spot market. Some of our long-term contracts relate to specific generating plants and extend through the end of the projected useful lives of such plants, subject in some cases to periodic renewal. Pursuant to the terms of our long-term supply contracts, prices are adjusted annually based on market conditions. The average cost of bituminous coal per ton purchased under such contracts was approximately (Won)98,248 in 2008, compared to (Won)55,519 in 2007 and (Won)48,923 in 2006. In recent years, the price of bituminous coal has increased significantly. Due to such price increases as well as increased shipping cost for bituminous coal, our generation subsidiaries may not be able to secure their respective bituminous coal supply at prices comparable to those of prior periods.

 

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See Item 3. “Key Information—Risk Factors—Risks Relating to KEPCO—Increase in fuel prices will adversely affect our results of operations and profitability, and we may not be able to pass on the increased cost to consumers at a sufficient level or on a timely basis.”

In 2008, our generation subsidiaries purchased 2.7 million tons of anthracite coal. Our generation subsidiaries purchase our anthracite coal requirements in Korea under long-term contracts with Korea Coal Corporation, which is wholly-owned by the Government, and the Korea Coal Mines Cooperative. The prices for anthracite coal under such contracts are set by the Government. The average cost of anthracite coal per ton purchased under such contracts was approximately (Won)121,416 in 2008, compared to (Won)97,833 in 2007 and (Won)91,895 in 2006.

Oil

Oil (including diesel for internal combustion) accounted for 4.1%, 4.3% and 2.2% of our fuel requirements for electricity generation in 2006, 2007 and 2008, respectively.

In 2008, our generation subsidiaries purchased approximately 12.6 million barrels of fuel oil (including gasoline for internal combustion), of which 85.9% was purchased through competitive open bidding among five Korean refiners for three-month terms of supply, and the remainder was purchased through international open bidding (including local refineries and traders) for individual cargoes. Purchase prices are based on the spot market price in Singapore. The average cost per barrel was approximately (Won)98,243 in 2008, compared to (Won)62,480 in 2007 and (Won)56,840 in 2006.

LNG

LNG accounted for 15.3%, 16.4% and 14.6% of our fuel requirements for electricity generation in 2006, 2007 and 2008, respectively.

In 2008, we purchased approximately 7.7 million tons of LNG from Korea Gas Corporation, a Korean corporation of which we own 24.5%. Under the terms of the LNG contract with Korea Gas Corporation, our annual minimum purchase quantity is determined by our negotiations with Korea Gas Corporation, subject to the Government’s approval, and may be adjusted through negotiations between the parties. Our generation subsidiaries are under a “take-or-pay” obligation to Korea Gas Corporation to the extent of our annual minimum purchase quantity. The annual purchase price for LNG is determined by our negotiations with Korea Gas Corporation, subject to approval by the Ministry of Knowledge Economy. Korea Gas Corporation imports LNG primarily from Indonesia, Malaysia, Brunei, Qatar, Oman, Australia, Egypt and Nigeria and supplies LNG to us and other Korean gas companies. The average cost per ton of LNG under such contract was approximately (Won)953,667 in 2008, compared to (Won)598,028 in 2007 and (Won)590,033 in 2006. The LNG supply contract with Korea Gas Corporation has a term of 20 years and expires in December 2026. Under this contract, all of our five non-nuclear generation subsidiaries are jointly and severally liable for a “take-or-pay” obligation to Korea Gas Corporation to the extent of our annual minimum purchase quantity in the amount of approximately 8.2 million tons. In addition, the annual minimum purchase quantity of LNG to be purchased from Korea Gas Corporation will exclude any amount of LNG purchased from a source other than Korea Gas Corporation. We believe the quantities of LNG provided under such contract will be adequate to meet the needs of our generation subsidiaries for LNG for the next several years.

Hydroelectric

As of December 31, 2008, 7.0% of our total installed generating capacity was represented by plants generating hydroelectric power.

The availability of water for hydroelectric power depends on rainfall and competing uses for available water supplies, including residential, commercial, industrial and agricultural consumption. Pumped-storage enables us to increase the available supply of water for use during periods of peak demand.

 

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Sales and Customers

Our results of operations, sales in particular, are dependent upon demand for electricity in Korea and the rates we charge for the electricity we sell.

Demand for electricity in Korea grew at a compounded average rate of 5.6% per annum for the five years ended December 31, 2008. According to The Bank of Korea, the real gross domestic product, or GDP, compounded growth rate was approximately 4.2% for the same period. The GDP growth rate was 5.1% and 2.2% in 2007 and 2008, respectively. However, in light of the recent downturn in the Korean economy following the global liquidity crisis and the resulting slowdown in industrial activities, demand for electricity decreased by 2.3% to 100,271 gigawatt hours in the first quarter of 2009 compared to the first quarter of 2008.

Following the Asian financial crisis in 1998, electricity demand contracted in Korea for several years, but resumed stable growth in the early 2000s with an annual growth rate between 5% and 8%. Demand for electricity increased by 5.7% from 2006 to 2007 and by 4.5% from 2007 to 2008. In 2008, demand for electricity grew faster than the GDP, which grew by 2.2% over the same period, primarily due to a slight increase in demand for electricity from the industrial sector related to good performance in the export sectors. Demand for electricity from the industrial sector grew by 6.5% in 2007 compared to 2006 and 4.4% in 2008 compared to 2007, and represented 52.9% and 52.8% of the total demand for electricity in 2007 and 2008, respectively. Demand for electricity from the commercial sector grew by 5.7% in 2007 compared to 2006 and 5.6% in 2008 compared to 2007, and represented 22.3% and 22.5% of the total demand for electricity in 2007 and 2008, respectively. For residential sector, electricity demand grew by 3.3% in 2007 compared to 2006 and 2.8% in 2008 compared to 2007, and represented 20.4% and 20.1% of the total demand for electricity in 2007 and 2008, respectively. We cannot assure you that demand for electricity will grow at an equal or faster rate than the GDP growth in the future.

The table below sets forth, for the periods indicated, the annual rate of growth in Korea’s gross domestic product, or GDP, and the annual rate of growth in electricity demand (measured by total annual electricity consumption).

 

         2004             2005             2006             2007             2008      

Growth in GDP (at 2005 constant prices)

   4.6 %   4.0 %   5.2 %   5.1 %   2.2 %

Growth in electricity consumption

   6.3 %   6.5 %   4.9 %   5.7 %   4.5 %

Electricity demand in Korea varies within each year for a variety of reasons other than the general growth in demand. Electricity demand tends to be higher during daylight hours due to heightened commercial and industrial activities and electrical appliance use. Due to the use of heating, electricity demand is higher during the winter than during any other season. Variation in weather conditions may also cause significant variation in electricity demand.

We do not use any marketing channels, including any special sales methods, to sell electricity to our customers, other than to install electricity meters on-site and take monthly readings of such meters, based upon which invoices are sent to our customers.

 

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Demand by the Type of Usage

The table below sets forth the consumption of electric power by the type of usage (in gigawatt hours) for the periods indicated.

 

    2004   YoY
growth

(%)
  2005   YoY
growth

(%)
  2006   YoY
growth

(%)
  2007   YoY
growth

(%)
  2008   YoY
growth

(%)
  % of
Total

2008

Residential

  65,490   4.9   69,555   6.2   72,730   4.6   75,148   3.3   77,269   2.8   20.1

Commercial

  67,476   9.5   73,716   9.2   77,809   5.6   82,208   5.7   86,827   5.6   22.5

Educational

  3,774   12.6   4,309   14.2   4,790   11.2   5,304   10.7   5,783   9.0   1.5

Industrial

  166,223   5.3   174,945   5.2   183,067   4.6   194,936   6.5   203,475   4.4   52.8

Agricultural

  6,766   10.1   7,318   8.2   7,636   4.3   8,215   7.6   8,869   8.0   2.3

Street lighting

  2,367   7.7   2,570   8.6   2,687   4.6   2,794   4.0   2,847   1.9   0.7
                                           

Total

  312,096   6.3   332,413   6.5   348,719   4.9   368,605   5.7   385,070   4.5   100.0
                                           

The industrial sector represents the largest segment of electricity consumption in Korea. While demand from the industrial sector (including the agricultural sector) has increased steadily as a result of economic expansion in Korea, it has gradually declined as a percentage of total demand from 62.6% in 1997 to 55.1% in 2008. Demand from the industrial sector increased by 4.5% to 212,344 gigawatt hours in 2008 from 2007.

Demand from the commercial sector has increased in recent years, both in absolute terms and as a percentage of total demand. The rapid expansion of the service sector of the Korean economy has resulted in increased office building construction, office automation and use of air conditioners. Growth in the commercial sector is also attributable to the construction industry and the expansion of the leisure and distribution industries. Demand from the commercial sector increased by 5.6% to 86,827 gigawatt hours in 2008 from 2007.

In 2008, we provided electricity to 18 million households, which represent substantially all of the households in Korea. Continuing increase in demand from the residential sector is primarily due to population growth and increased use of air conditioners and other electrical appliances. Demand from the residential sector increased by 2.8% to 77,269 gigawatt hours in 2008 from 2007.

Demand Management

Our ability to provide an adequate supply of electricity is principally measured by the facility capacity reserve ratio and the supply capability reserve ratio. The facility capacity reserve ratio represents the difference between the peak usage during a year and the installed capacity at the time of such peak usage, expressed as a percentage of such installed capacity. The supply capability reserve ratio represents the difference between the peak usage in a year and the average available capacity at the time of such peak usage, expressed as a percentage of such peak usage. The following table sets forth our facility capacity reserve ratio and supply capability reserve ratio for the periods indicated.

 

         2004            2005            2006            2007            2008    

Facility reserve ratio

   15.3    13.0    9.8    7.9    12.0

Supply reserve ratio

   12.2    11.3    10.5    7.2    9.1

While we seek to meet the growing demand for electricity in Korea primarily by continuing to expand our generating capacity through the addition of new generating facilities, we also implement several measures to curtail electricity consumption, especially during peak periods. The principal measure we take is to apply, for large-scale customers, time-of-use rate schedules, which are structured to the effect that higher tariffs are charged at the time of peak demand. We also apply a progressive rate structure for the residential use of electricity. We also provide other incentives to customers who curtail electricity consumption from public fund through demand-side management programs including demand adjustment program of advance notice and demand adjustment program of designated period for load reduction during summer peak hours. We have been leading to reduce not

 

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only energy consumption but also greenhouse gases by spreading out various high efficient devices such as energy efficient lightings. Furthermore, we replace lightings for low-income households for free as part of government’s energy welfare policy.

Electricity Rates

The Electricity Business Law and the Price Stabilization Act of 1975, as amended, prescribe the procedures for the approval and establishment of rates charged for the electricity we sell. We submit our proposals for revisions of rates or changes in the rate structure to the Ministry of Knowledge Economy. The Ministry of Knowledge Economy then reviews these recommendations and, upon consultation with the Electricity Rates Expert Committee of the Ministry of Knowledge Economy and the Ministry of Strategy and Finance, makes the final decision. Under the Electricity Business Law, the Korea Electricity Commission must review our proposals prior to the Ministry of Knowledge Economy’s final decision.

Under the Electricity Business Law and the Price Stabilization Act, electricity rates are established at levels that will permit us to recover our operating costs attributable to our basic electricity generation, transmission and distribution operations in addition to receiving a fair investment return on capital used in those operations. For the purposes of rate approval, operating costs are the sum of our operating expenses plus our adjusted income taxes.

Fair investment return is equal to the rate base multiplied by the rate of return. The rate base is equal to the sum of:

 

   

net utility plant in service (which is equal to utility plant minus accumulated depreciation minus revaluation reserve),

 

   

working capital for two months (equal to one-sixth of annual operating expenses other than depreciation expenses and any other non-cash expenses),

 

   

our equity interests in generation subsidiaries, and

 

   

the portion of construction-in-progress which is charged from our retained earnings.

The amounts used for the variables in the rates are those projected by us for the periods to be covered by the rate approval. There is no provision for prior period adjustments to compensate us.

For the purpose of determining the fair rate of return, the rate base is divided into two components proportionate to our total stockholders’ equity and our total debt. The rate of return permitted in relation to the debt component of the rate base is set at a level designed to approximate the weighted average interest cost on all types of borrowing for the periods covered by the rate approval. The rate of return permitted in relation to the equity component of the rate base is set by applying the capital asset pricing model which takes account of the risk-free rate, the return on the Korea Stock Price Index, KOSPI, a Korean equity market index, and the correlation of the stock price of our company with KOSPI. In 2008, the approved rate of return on the debt component of the rate base was 4.2% while the approved rate of return on the equity component of the rate was 6.1%. As a result of such approved rates of returns, the fair rate of return in 2008 was determined as 5.6%.

The Electricity Business Law and the Price Stabilization Act do not specify a basis for determining the reasonableness of operating expenses or any other items (other than the level of the fair investment return) for the purposes of the rate calculation. However, the Government exercises substantial control over our budgeting and other financial and operating decisions.

In addition to the calculations described above, a variety of other factors are considered in setting overall rate levels. These other factors include consumer welfare, our projected capital requirements, the effect of electricity rates on inflation in Korea and the effect of rates on demand for electricity.

In the latter half of the 1980s, our actual rate of return on equity generally exceeded the rate of return on equity assumed for the purposes of rate approvals, principally as a result of declining fuel costs and a higher than

 

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expected growth in demand. As a result, the rates were reduced by an average of 6.5% per annum during the period from 1987 to 1990. However, primarily because of changes in fuel prices and the growth in capital investment, and in order to encourage conservation of electricity and secure internal cash for capital expenditures, the rates were increased by an average of 3.0% per annum during the period from 1991 to 1995. During the period from 1996 to 2000, in order to compensate for the Won depreciation which caused our fuel expenditure to increase, rates were increased by an average of 4.3% per annum, and during the period 1997 through 2000, our actual rate of return on invested capital was generally below the rate of return assumed for the purpose of rate approvals. During the period 2004 to 2008, rates were increased by an average of 1.6% per annum to compensate for high fuel costs and facility investment costs, and our actual rate of return on invested capital was generally below the rate of return assumed for the purpose of rate approvals. On November 13, 2008, the rate was increased by 4.5%. We currently expect this rate increase will raise our actual rate of return on invested capital by approximately 1.8%.

The Ministry of Knowledge Economy adjusts the rate schedule from time to time. For example, on January 15, 2007, the Ministry of Knowledge Economy increased each of the industrial rates and street-lighting rates by 4.2%, while making no changes to the other rates, which resulted in an increase by 2.1% in our overall average rate. In addition, on January 1, 2008, as part of a plan to improve the electricity tariff structure, the Ministry of Knowledge Economy approved a raise of the average industrial rates and average night power usage rates by 1.0% and 18.0%, respectively, while reducing the average commercial rates by 3.0%, which had no material effect on our overall average rate. Furthermore, in light of the rapid rise in fuel prices following the general rise in commodity prices (including oil) worldwide from the second half of 2007 and the first half of 2008 which seriously undermined our profitability, effective November 13, 2008, the Ministry of Knowledge Economy approved a raise of the industrial, commercial, educational and street lighting rates by 8.1%, 3.0%, 4.5% and 4.5%, while making no changes to the residential and agricultural rates, which is expected to result in an increase by 4.5% in our overall average rate. There is no assurance, however, that such rate increase will be sufficient to fully offset the adverse impact from the rise in fuel costs on our business or results of operations.

The rates we charge for electricity vary among the different classes of consumers, which principally consist of industrial, commercial, residential, educational and agricultural consumers. The rates also vary depending upon the voltage used, the season, the time of day, the rate option selected by the user and, in the residential sector, the amount of electricity used per household, as well as other factors. Beginning with the first six months of 1995, we adjusted seasonal rate variations by removing the month of June from the summer period when peak rates are in effect and increasing the rates for the months of October, November, December, January, February and March to correspond more closely to peak demand variations. On April 1, 2007, we adjusted the winter period to consist of November, December, January and February, to reflect the changes in monthly usage levels in October and March.

Our current rate schedule, which became effective as of November 13, 2008, is summarized below by the type of consumer:

Industrial. The basic charge varies from (Won)4,100 per kilowatt to (Won)6,180 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from (Won)34.7 per kilowatt hour to (Won)140.5 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

Commercial. The basic charge varies from (Won)5,160 per kilowatt to (Won)6,510 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from (Won)39.3 per kilowatt hour to (Won)155.6 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

Residential. Residential rates include a basic charge ranging from (Won)370 for electricity usage of less than 100 kilowatt hours to (Won)11,750 for electricity usage in excess of 500 kilowatt hours. Residential rates also include an energy usage charge ranging from (Won)52.4 to (Won)643.9 per kilowatt hour for electricity usage depending on the amount of usage and voltage.

 

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Educational. The basic charge varies from (Won)4,280 per kilowatt to (Won)5,200 per kilowatt depending on the voltage used and the rate option. The energy usage charge varies from (Won)45.1 per kilowatt hour to (Won)76.3 per kilowatt hour depending on the voltage used, the season and the rate option.

Agricultural. The basic charge varies from (Won)340 per kilowatt to (Won)1,070 per kilowatt depending on the type of usage. The energy usage charge varies from (Won)20.6 per kilowatt-hour to (Won)36.4 per kilowatt hour depending on the type of usage.

Street-lighting. The basic charge is (Won)4,210 per kilowatt and the energy usage charge is (Won)57.8 per kilowatt hour. For electricity capacity of less than 1 kilowatt or for places where the installation of the electricity meter is difficult, the fixed rate of (Won)25.2per watt applies, with the minimum charge per month of (Won)820.

In April 2001, as part of implementing the Restructuring Plan, the Ministry of Knowledge Economy established the Electric Power Industry Basis Fund to enable the Government to take over certain public services previously performed by us. Since the establishment of this fund in April 2001, 4.591% of the tariff we collected from our customers was transferred to this fund prior to our recognizing sales revenue. This percentage was reduced to 3.700% on December 28, 2005.

Power Development Strategy

The Government typically announces a Long-Term Electricity Supply and Demand Basic Plan, or a Basic Plan, every two years to reflect demand growth projections, availability and cost of financing, changes in prices and availability of fuel, ability to acquire necessary plant sites, environmental considerations, community opposition and other factors.

In December 2008, the Government announced the fourth Basic Plan relating to the future supply and demand of electricity. The fourth Basic Plan focuses on, among other things, (1) ensuring that electricity generation conforms to the National Energy Basic Plan relating to the overall energy management policy for Korea, including in areas of demand management, target nuclear power generation, and a greater emphasis on renewable energy and (2) improving the accuracy of electricity supply forecast based primarily on expected fuel prices, generation efficiency and technological advances, in addition to the mandates under the previous third Basic Plan, including (3) establishing an optimal level and mix of generating capacity based on fuel types and the operational efficiency of each generation unit, (4) equilibrating the supply and demand of electricity at the regional level through region-specific planning for capacity expansion, (5) setting high priority to environmental issues by proactively addressing some of the concerns identified under the United Nations Framework Convention on Climate Change and the Kyoto Protocol, and (6) improving the transparency and accountability in the decision-making process for formulating the basic plan by formalizing more compartmentalized processes and procedures, including seeking advice from outside experts. We cannot assure that the fourth Basic Plan, or the plans subsequently adopted, will successfully achieve their intended goals, the foremost of which is to formulate a capacity expansion plan that will result in balanced overall electricity supply and demand in Korea at an affordable cost to the end users.

Capital Investment Program

The table below sets forth, for each of the three years ended December 31, 2008, the amounts of capital expenditures (including capitalized interest) for the construction of generation, transmission and distribution facilities:

 

2006

  2007   2008
(In billions of Won)
(Won)7,469   (Won) 8,545   (Won) 8,925

In accordance with the fourth Basic Plan, our generation subsidiaries currently intend to add new installed capacity of 27,620 megawatts during the period from 2009 to 2022 by newly constructing 12 nuclear units, 7 coal-fired units, 8 LNG-combined units, and two pumped-storage hydroelectric units and others. According to

 

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the fourth Basic Plan, the total capacity of all generating facilities at the end of 2022 will be 100,891 megawatts, of which nuclear power plants will account for 32.6% of the total capacity, coal-fired plants 29.2%, LNG combined plants 22.9%, oil-fired plants 3.6% and hydroelectric and other plants 11.8%.

The table below sets forth the currently estimated date of completion and installed capacity of new or expanded generation units to be completed by our generation subsidiaries according to the fourth Basic Plan in each year through the year 2012.

 

Year

   Number of Units   

Type of Units

   Total Installed Capacity
     (Megawatts)

2009

   1
1
  

Coal-fired

LNG-combined

   500
509

2010

   1
2
  

Nuclear power

LNG-combined

   1,000
1,571

2011

   1

2

1

  

LNG-combined

Pumped-storage hydroelectric

Nuclear power

   900

800

1,000

2012

   3

1

  

LNG-combined

Nuclear power

   1,700

1,000

In the years between 2013 and 2022, our generation subsidiaries plan to complete nine nuclear units with an aggregate installed capacity of 12,200 megawatts, six coal-fired units with an aggregate installed capacity of 5,740 megawatts, and one LNG-combined unit with an aggregate installed capacity of 700 megawatts.

As part of our capital investment program, we also intend to add new transmission lines and substations, continue to replace overhead lines with underground cables and improve the existing transmission and distribution systems.

The actual number and capacity of generation units and transmission and distribution facilities we and our generation subsidiaries construct and the timing of such construction are subject to change depending upon a variety of factors, including, among others, demand growth projections, availability and cost of financing, changes in fuel prices and availability of fuel, ability to acquire necessary plant sites, environmental considerations and community opposition.

The table below sets forth, for the years from 2009 to 2012, the budgeted amounts of capital expenditures (including capitalized interest) for the construction of generation, transmission and distribution facilities pursuant to our generation subsidiaries’ and our capital investment program. The budgeted amounts may vary from the actual amounts of our generation subsidiaries’ capital expenditures for a variety of reasons, including, among others, the implementation of the Restructuring Plan, changes in the number of units to be constructed, the actual timing of such construction, changes in rates of exchange between the Won and foreign currencies and changes in interest rates.

 

     2009    2010    2011    2012    Total
     (in billions of Korean won)

Generation:

              

Nuclear

   5,235    6,281    5,406    5,593    22,515

Thermal

   2,563    3,006    3,150    3,878    12,597
                        

Sub-total

   7,798    9,287    8,556    9,471    35,112
                        

Transmission and Distribution:

              

Transmission

   2,300    2,564    1,925    2,217    9,006

Distribution

   2,097    2,170    2,748    2,962    9,977

Others

   324    474    583    665    2,046
                        

Sub-total

   4,721    5,208    5,256    5,844    21,029
                        

Total

   12,519    14,495    13,812    15,315    56,141
                        

 

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We have been financing, and plan to finance in the future, our capital investment programs primarily through net cash provided by our operating activities and financing in the form of debt securities and loans from domestic financial institutions, and to a lesser extent, from overseas financial institutions. In addition, in anticipation of potential liquidity shortage, we maintain several credit facilities with domestic financial institutions in the aggregate amount of (Won)725 billion, the full amount of which was available as of December 31, 2008. In addition, in September 2008, we have established a global medium-term notes program up to an aggregate amount of US$1 billion, which may be drawn down wholly or in part, depending on the market conditions. See also “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Capital Resources.”

Environmental Programs

The Environmental Policy Basic Act, the Air Quality Preservation Act, the Water Quality Preservation Act, the Marine Pollution Prevention Act and the Waste Management Act, collectively referred in this report as the Environmental Acts, are the major laws of Korea that regulate atmospheric emissions, waste water, noise and other emissions from our facilities, including power generators and transmission and distribution units. Our existing facilities are currently in material compliance with the requirements of these environmental laws and international agreements, such as the United Nations Framework Convention on Climate Change, the Montreal Protocol on Substances that Deplete the Ozone Layer, the Stockholm Convention on Persistent Organic Pollutants and the Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and Their Disposal. In order to foster coordination among us and our generation subsidiaries in respect of climate change and development of renewable energy sources, we formed the Committee on Climate Change and the Committee on Renewable Energy in 2005.

In 2005, we became the first Korean company to join the United Nations Global Compact, an international voluntary initiative designed to hold a forum for corporations, United Nations agencies, labor and civic groups to promote reforms in environmental and social policy. As part of our involvement with such initiative, since September 2005, we issue an annual report named the “Sustainability Report” to disclose our activities from the perspectives of economy, environment, society and humanity, in accordance with the reporting guidelines launched by the Global Reporting Initiative, the official collaborating center of the United Nations Environment Programme that works in cooperation with United Nations Secretary General. In January 2008, our report on the Communication of Progress was reviewed favorably by the United Nations Global Compact in recognition of our strong commitment to compliance with the United Nations Global Compact and the clarity and specificity of our action plans related to sustainability.

Atmospheric emissions from generating plants burning fossil fuels include, among others, sulfur dioxide, nitrogen oxide and particulates. The Environmental Acts establish emissions standards relating to, among other things, sulfur dioxide, nitrogen oxide and particulates. Such standards have become more stringent from January 1999 to reduce the amount of permitted emissions.

The table below sets forth the number of emission control equipment installed at coal-fired power plants by our generation subsidiaries as of December 31, 2008.

 

     KOSEP    KOMIPO    KOWEPO    KOSPO    EWP

Flue Gas Desulphurization System

   10    7    8    7    11

Selective Non-Catalytic Reduction System

   —      —      —      —      2

Selective Catalytic Reduction System

   6    11    8    7    11

Electrostatic Precipitation System

   12    12    8    7    18

Low NO2 Combustion System

   6    18    8    7    10
                        

Total

   34    48    32    28    52
                        

 

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The table below sets forth the amount of annual emission from all generating facilities of our generation subsidiaries. In 2008, the amount of CO2 emissions decreased by 5% compared to 2007, principally due to the increased use of more environmentally friendly advanced generation technology and a relative increase in the capacity of hydro and nuclear generation, which increased by 10.3% and 5.6%, respectively, from December 31, 2007 to December 31, 2008. We expect that CO2 emissions will increase in 2009 and 2010 as additional coal thermal power stations are constructed during these years until 2010 but will decrease thereafter, principally due to increased use of nuclear power and renewable energy.

 

Year

   Sox
(g/MWh)
   NOx
(g/MWh)
   Dust
(g/MWh)
   CO2
(kg/MWh)

2006

   186    315    9    423

2007

   187    300    9    443

2008

   167    288    9    423

In order to comply with the current and expected environmental standards and address related legal and social concerns, we intend to continue to install additional equipment, make related capital expenditures and undertake several environmentally friendly measures to foster community goodwill. For instance, in October 2004, we and our generation subsidiaries reached an agreement with the Ministry of Environment and civic organizations to completely remove polychlorinated biphenyl, or PCB, a toxin, from the insulating oil of our transformers by 2015. In addition, when constructing certain large new transmission and distribution facilities, we assess and disclose their environmental impact at the planning stage of such construction, as well as consult with local residents, environmental groups and technical experts to generate community support for such projects. We exercise additional caution in cases where such facilities are constructed near ecologically sensitive areas such as wetlands or preservation areas. We also make reasonable efforts to minimize any negative environmental impact, for instance, by using more environmentally friendly technology and hardware. In addition, we also undertake measures to minimize the transmission and distribution loss factor by making our power distribution network more energy-efficient in terms of loss of power, as well as to lower consumption of energy, water and other natural resources. In addition, we and our subsidiaries have obtained the ISO 14001 certification which is an environmental management system widely adopted internationally and have made it a high priority to make our electricity generation and distribution more environmentally friendly.

Our environmental measures, including the use of environmentally friendly but more expensive parts and equipment and budgeting capital expenditures for the installation of such facilities, may result in increased operating costs and liquidity requirement. The actual cost of installation and operation of such equipment and related liquidity requirement will depend upon a variety of factors which may be beyond our control. There is no assurance that we will continue to be in material compliance with legal or social standards or requirements in the future in relation to the environment.

Renewable Energy

Some of the generation facilities owned by us and our generation subsidiaries are powered by renewable energy sources, such as solar energy, wind power and hydraulic power. While such facilities are currently insignificant as a proportion of the total generating capacity or the generation volume of our generation subsidiaries, we expect that the portion will increase in the future.

The following table sets forth the generating capacity and generation volume in 2008 of the generation facilities owned by us and our generation subsidiaries that are powered by renewable energy sources.

 

     Generating Capacity
(megawatts)
    Generation Volume
(gigawatt-hours)
 

Hydraulic Power

   550.49     1,343.9  

Wind Power

   24.75     53.0  

Solar Energy

   11.42     12.7  

Fuel Cells

   0.55     2.4  

Subtotal

   587.21     1,412.0  

As percentage of total(1)

   0.92 %   0.36 %

 

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Note:

 

(1) As a percentage of the total generating capacity or total generation volume, as applicable, of all of our generation subsidiaries.

In July 2005, nine government-invested utilities companies, including us, entered into a Renewable Portfolio Agreement with the Government in order to expand the generation and distribution of renewable energy. This agreement contemplates two phases of capacity build-up for the generation and distribution of renewable energy. During Phase I, which lasted from 2006 to 2008, we and our generation subsidiaries made capital expenditures of (Won)520.1 billion to construct renewable energy generation capacity of 810 megawatts. During Phase II of 2009 to 2011, we and our generation subsidiaries are scheduled to make capital expenditures of (Won)1,968.0 billion to construct renewable energy generation capacity of 288 megawatts.

The following tables provide breakdowns of the renewable energy generation capacity by type and related capital expenditures by each phase under the Renewable Portfolio Agreement.

 

     Phase I (2006 – 2008)    Phase II (2009 – 2011)
     Generating Capacity
(Megawatts)
   Generating Capacity
(Megawatts)

Tidal Power

   104    21

Hydraulic Power

   17    79

Wind Power

   53    327

Solar Energy

   12    8

Fuel Cells(1)

   1    26

Others(2)

   101    349
         

Total(3)

   288    810
         

 

Notes:

 

(1) Consists of molten carbonate fuel cells and solid oxide fuel cells.
(2) Consists of bioenergy, hydrogen energy, geothermal energy, energy from integrated gasification combined-cycles and energy from recycling waste.
(3) The breakdown of capital expenditures for Phase I and Phase II under the Renewable Portfolio Agreement by type of expenditure is as follows:

 

     Phase I (2006 – 2008)    Phase II (2009 – 2011)
     (in billions of Won)

Facilities investment

   (Won) 380.0    (Won) 1,864.3

Research and development

     127.6      93.0

Promotion and other

     12.5      10.7
             

Total

   (Won) 520.1    (Won) 1,968.0
             

We have been financing, and plan to finance in the future, our capital investment programs primarily through net cash provided by our operating activities and financing in the form of debt securities and loans from domestic financial institutions, and to a lesser extent, from overseas financial institutions. In addition, in anticipation of potential liquidity shortage, we maintain several credit facilities and have established a global medium-term notes program up to an aggregate amount of US$1 billion. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Capital Resources.”

 

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Community Programs

Building goodwill with local communities has been important for us and our generation subsidiaries in light of concerns among the local residents and civic groups in Korea regarding construction and operation of generation units, particularly nuclear generation units. The Act for Supporting the Communities Surrounding Power Plants requires that the generating companies and the affected local governments carry out various activities up to a certain amount annually to addresses neighboring community concerns. Pursuant to this Act, we and our generation subsidiaries, in conjunction with the affected local and municipal governments, undertake various programs, including scholarships and financial assistance to low-income residents.

Until 2005, activities required to be undertaken pursuant to the Act for Supporting the Communities Surrounding Power Plants were funded only by the Electric Power Industry Basis Fund, or EPIBF. See Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates.” Following amendments to this Act in July 2005, however, such activities are currently required to be funded partly by the EPIBF and partly by KHNP’s revenues. KHNP is required to make annual contributions to the affected local communities in an amount equal to (Won)0.25 per kilowatt of electricity generated by its nuclear generation units during the one-year period before the immediately preceding fiscal year.

In addition, under a Korean tax law amendment in December 2005, which levied a new local tax on nuclear generation units, KHNP is required to pay such tax starting in 2006 in an amount equal to (Won)0.50 per kilowatt of its generation volume in the affected areas.

Prior to the construction of a generation unit, our generation subsidiaries perform an environmental impact assessment which is designed to evaluate public hazards, damage to the environment and concerns of local residents. A report reflecting this evaluation and proposing measures to address the problems identified must be submitted to and approved by the Ministry of Environment prior to the construction of the unit. Our generation subsidiaries are then required to implement the measures reflected in the approved report.

Despite these activities, community opposition to the construction and operation of generation units (including nuclear units) could adversely impact our construction plans for generation units (including nuclear units) and have a material adverse effect on our results of operations and cash flows.

Nuclear Safety

KHNP has adopted nuclear safety as its top priority and continues to focus on ensuring the safe and reliable operation of nuclear power plants. KHNP has been also focusing on enhancing corporate ethics and transparency in the operation of the plants.

KHNP instituted its corporate code of ethics in September 2002 and declared its strong commitment to enhancing nuclear safety, developing new technologies and improving transparency. In December 2003, KHNP also established the “Statement of Safety Policy for Nuclear Power Plants” to ensure the highest level of nuclear safety. Furthermore, KHNP has invested approximately 5% of its total annual sales into research and development for the enhancement of nuclear safety and operational performance.

KHNP has implemented comprehensive programs to monitor, ensure and improve safety of nuclear power plants. In order to enhance nuclear safety through risk-informed assessment, KHNP conducts probabilistic safety assessments for all its nuclear power plants. In order to systematically verify nuclear safety and identify the potential areas for safety improvements, KHNP performs periodic safety reviews on a 10-year frequency basis for all its operating units. These reviews have been completed for Kori units 1, 2, 3 and 4, Yonggwang units 1, 2, 3 and 4, Ulchin units 1 and 2 and Wolsong units 1 and 2. In order to enhance nuclear safety and plant performance, in 2003, KHNP established a maintenance effectiveness monitoring program in accordance with the maintenance rules issued by the United States Nuclear Regulatory Commission. The program was initially implemented at Kori units 3 and 4 and Ulchin units 3 and 4 in 2007 as a pilot program. The program will be

 

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expanded into all pressurized light water reactor plants by June 2009. KHNP is also developing unprecedented maintenance rule implementation technologies for pressurized heavy water reactor plants.

KHNP has developed the Risk Monitoring System for operating nuclear power plants, and has implemented such system in all of its nuclear power plants. The Risk Monitoring System is intended to help ensure nuclear plant safety. In addition, KHNP has developed and implemented the Severe Accident Management Guidelines in order to manage severe accidents for all of its nuclear power plants, except for four pressurized heavy water reactors in Wolsong. The Severe Accident Management Guidelines for the pressurized heavy water reactors are currently under development.

KHNP has conducted various activities to enhance nuclear safety such as quality assurance audits, reviews by the KHNP Nuclear Review Board, and reviews by the KHNP operational safety review team, which consists of former employees of KHNP and experts from academia and internal research institutes. KHNP maintains a close relationship with international nuclear organizations in order to enhance nuclear safety. In particular, KHNP invites international safety review teams such as the World Association of Nuclear Operators (“WANO”) Peer Review Team, the International Atomic Energy Agency (“IAEA”), the Operational Safety Review Team (“OSART”) and the Institute of Nuclear Power Operations (“INPO”) Technical Exchange Visit Team, to its nuclear plants for purposes of meeting international standards for independent review of its facilities. KHNP actively exchanges relevant operational information and technical expertise with its peers in other countries.

In October 2008, Yonggwang Unit 5 and 6 hosted the OSART follow-up visit to evaluate the actions taken in response to the findings of OSART Review conducted in April 2007 and were reconfirmed by OSART as some of the best plants in the world. Commemorating the 30 year anniversary of commercial nuclear power plant operation in Korea, KHNP has also conducted a Special Safety Review of its 20 operating units from May 13, 2008 to July 4, 2008 in order to assess their safety performance and identify any areas that need improvement.

Following the operational reforms and upgrades implemented in 1992, the average level of radiation dose per unit has continuously decreased to 0.51 man-Sv in 2008, which is substantially lower than the global average of 1.03 man-Sv/year as reported in the WANO performance indicator report.

Low and intermediate level waste, or LILW, and spent fuels are stored in temporary storage facilities at each nuclear site. The temporary LILW storage facilities at Ulchin, Wolsong, Yonggwang and Kori reached their full capacity in 2008 and are expected to reach their full capacity by 2008, 2009, 2012 and 2014, respectively.

On November 3, 2005, the Government designated Gyeongju City, approximately 300 kilometers southeast of Seoul, as the site of a disposal facility for LILW. In order to determine the disposal type, KHNP organized the “Disposal Method Selection Committee,” which consists of experts and representatives from the local government and communities. KHNP estimates that the construction of this facility will cost approximately (Won)1,522 billion, including the one-time cash contribution of (Won)300 billion made on May 9, 2006 by KHNP to Gyeongju City pursuant to the Act. KHNP submitted an application to the Ministry of Knowledge Economy, for the approval of project implementation plan on January 11, 2007 and to the Ministry of Education, Science and Technology, for construction permit and operating licenses on January 15, 2007. KHNP obtained the approval of the project implementation plan from the Ministry of Knowledge Economy on July 12, 2007, and commenced the site grading and infrastructure construction of the facility. The application for construction permit and operation license was reviewed by the Ministry of Education, Science and Technology and has been approved on July 31, 2008. KHNP commenced construction of the LILW disposal facility in January 2006, and has obtained the construction permit and operation license on July 31, 2008. KHNP plans to complete construction of the facility by the end of 2009 and begin operating the facility in 2010.

In order to increase the storage capacity of temporary storage facilities for spent fuels, KHNP has been pursuing various projects, such as installing high density racks in spent fuel pools, building dry storage facilities and transporting the spent fuels to other nuclear units within a nuclear site. Through these activities, KHNP

 

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expects that the storage capacity for spent fuels in all nuclear sites will be sufficient to accommodate all the spent fuels produced by 2016. The policy for spent fuel management options is currently under development.

All of KHNP’s nuclear plants are in compliance with Korean law and regulations and the safety standards of the International Atomic Energy Agency.

Since the submission of our annual report in 2008, there have been no significant safety-related events or accidents in KHNP’s nuclear power plants that would have a material adverse effect on us.

Decommissioning

Decommissioning of a nuclear power unit is the process whereby the unit is shut down at the end of its life, the fuel is removed and the unit is eventually dismantled. KHNP has adopted a dismantling strategy under which dismantling would take place five to ten years after the unit’s permanent shutdown. Kori unit-1, the first nuclear power plant in Korea, commenced its operation in 1978 and reached the end of its intended life on June 18, 2007. KHNP submitted an extension application to the Ministry of Education, Science and Technology to extend the terms of operation for Kori-1 unit for another 10 years. The application was approved on December 11, 2007, and Kori unit-1 recommenced its commercial operations in January 9, 2008.

KHNP retains financial responsibility for decommissioning its units although it does not carry a cash reserve for its decommissioning liability. KHNP has accumulated the decommissioning cost as a liability since 1983. The decommissioning costs of nuclear facilities were first estimated in 1992, based on an engineering study. In 2003 and 2004, KHNP obtained new engineering studies from third parties and updated its estimate of the expected decommissioning dates for its nuclear power plants. For the accounting treatment of decommissioning costs, see Item 5 “Operating and Financial Review and Prospects—Operating Results—Critical Accounting Policies—Decommissioning Costs.”

Research and Development

We maintain a research and development program concentrated on developing self-reliant core technology and leading national technology advancement programs in the electric power business.

In order to achieve the goal of bringing our electric technologies up to international standards by the first half of the 21st century, we have adopted the “Electric Technology Development Plan toward 2010” which is expected to be modified in the near future to reflect the “2020 Mid- and Long-term Strategic Management Plan” that we announced in August 2008. This strategic plan is being implemented across all areas of our in-house research and development programs. In addition, we and our six generation subsidiaries have made a “Technology Roadmap” to develop technologies in the area of thermal and nuclear generation.

The basic goal of our current research and development program is to acquire highly advanced electric power technology necessary to become a global leader in the electric power industry. To promote research and development for enhancing economical efficiency and to provide a reliable supply of electric power, in 2008 we invested (Won)196 billion in R&D Projects, (Won)11 billion in technological development and (Won)26 billion in building up infrastructure for the education of human resources and the development of computer equipment.

In the field of hydroelectric and thermal power, our research and development efforts are primarily focused on developing technologies required for the efficient operation of thermal power plants, such as our “Development of Advanced Thermal Power Plant” project using the “Ultra-Super Critical Technology.” We also emphasize enhancing plant maintenance, which has proven to be of great importance in maintaining a competitive edge in this field, through accurate damage analysis, environment-friendly inspections and various other protective and optimization measures.

 

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In the field of nuclear power, our research and development efforts are primarily focused on developing technology for enhancing the safety and economy of nuclear plants, such as our “Life Time Management for Nuclear Power Plant” project. Our research and development objective for this field is to obtain technologies necessary to perform reactor/plant safety analysis, radiation control and radioactive waste reduction and seismic monitoring and analysis.

KHNP’s investment in research and development amounted to approximately (Won)70 billion and (Won)67 billion in 2007 and 2008, respectively, and its investment in the education of human resources and the development of computer equipment amounted to approximately (Won)49 billion in 2007 and (Won)53 billion in 2008. Also, pursuant to relevant law, KHNP contributed approximately (Won)179 billion and (Won)172 billion in 2007 and 2008, respectively, to the Nuclear R&D Fund, which is operated by the Ministry of Education, Science and Technology.

In the field of electric power systems, we have focused our research and development efforts on developing required technology and providing technical support for the stable and reliable operation of electrical power systems, such as the “Development of Smart Transmission System Technology.” We have developed the technology for an efficient distribution system, preventive maintenance for substations, system automation, power utilization and power line communication.

We are committed to developing environment-friendly technology and are focused on developing technology for environmental protection and new sources of energy.

We invested approximately (Won)249 billion in 2007 and (Won)233 billion in 2008 on research and development. We had approximately 499 employees engaged in research and development activities as of December 31, 2008.

In addition, we have been cooperating closely with many foreign electric utilities and research institutes on a diverse range of projects.

As part of our strategy for future growth, we have placed a high priority in the development of environmentally friendly technology. As part of this effort, we have developed a gasification test bed and evaluation of gasification processes for a 300 megawatt integrated gasification combined-cycle plant in Korea, a five-kilowatt solid oxide fuel cell system, a 100 kilowatt superconductor flywheel energy storage technology and a “smart” electricity distribution system.

As a result of our research over the past three years, the number of our applications for intellectual property rights and grants has increased. Approximately 859 such applications were submitted in Korea and abroad from 2006 to 2008. In addition, we are currently constructing management infrastructure to facilitate development of high value-added intellectual properties. We also seek to market the technologies we have developed by identifying key items that have market potential in light of intellectual property, overseas market condition and cost-efficiency issues. We are continuously upgrading our research and development programs, restructuring our research and development organization and reallocating and reassigning research personnel.

Overseas Activities

We are actively engaged in a number of overseas activities. We believe that such activities help us to diversify our revenue streams by leveraging the operational experience of us and our subsidiaries gathered from providing a full range of services, power plant construction, specialized engineering and maintenance services in Korea, as well as to establish strategic relationships with a number of countries that are or may become providers of fuels.

 

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The table set below summarizes the overseas projects that we are currently pursuing based on binding agreements.

 

Region

  

Project Period

  

Project Description

Malaya, Philippines

   September 1995 to January 2011    650-megawatt oil-fired power plant (ROMM(1))

Ilijan, Philippines

   March 1999 to June 2022    1,200-megawatt combined-cycle power plant project (BOT(2))

Naga, Philippines

   February 2006 to March 2012    206-megawatt power plant (ROMM)(1)

Shanxi, China

   April 2007 to April 2056    4,872-megawatt coal-fired power plants (BOO(3)) and coal mine project

Yumen, China

   September 2005 to August 2026    49.3-megawatt wind power plant (BOO)(3)

Inner Mongolia, China

   May 2007 to October 2028    369 megawatt wind power plant (BOO)(3)

Lebanon

   February 2006 to February 2011    870-megawatt combined-cycle power plant operation and maintenance service

Nigeria

   March 2006 to February 2011    Exploration of oil and gas for two offshore blocks

West Africa

   September 2008 to December 2009    Line Route and Environmental and Social Impact Assessment Study

Egypt

   December 2008 to November 2009    Developing and Automating the Electricity Distribution System Project

NSW, Australia

   2008 to 2028    Moolarben coal mine development

QLD, Australia

      Share subscription of Cockatoo Coal Limited

Canada

   December 2007 to November 2011    Uranium exploration project in the Cree East

Canada

      Share subscription of Denison Mines, a uranium development company, and uranium procurement

 

Notes:

 

(1) Represents “rehabilitation, operation, maintenance and management” projects.
(2) Represents “build, operate and transfer” projects.
(3) Represents “build, own and operate” projects.

While strategically important, we believe that our overseas activities, as currently being conducted, are not in the aggregate material to us in terms of scope or amount. In addition, a number of the overseas contracts currently being pursued are based on non-binding memoranda of understanding and the details of such projects may significantly change during the stage of negotiating the definitive agreements.

A description of the material overseas activities by us and our subsidiaries by key geographic region is provided below.

Asia

In September 2005 and April 2006, we and China Datang Corporation formed two joint ventures to build four wind-powered generation projects in China, consisting of a unit in the Yumen province with total capacity of 49.3 megawatts and three units in Inner Mongolia with total capacity of 139.4 megawatts and added five more units with total capacity of 229.6 megawatts. We hold a 40% equity interest in the joint ventures while China Datang Corporation holds the remaining 60%. The joint ventures were capitalized with RMB 3,784 million for the Inner Mongolia projects and RMB466 million for the Yumen project. One-third of the investment was funded with equity contribution and the remaining two-thirds with debt. These projects are currently in operation and generate further revenue in the form of clean development mechanism, or CDM, business. We and China Datang Corporation are currently building wind-power generation units in Yumen province and in Inner Mongolia with total additional capacity of 328 megawatts.

 

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We formed a limited partnership with Shanxi International Electricity Group and Deutsche Bank in China to develop and operate power projects and coal mines in Shanxi province, China, which was approved by the Chinese government in April 2007. The total estimated installed capacity of this is 4,872 megawatts and our equity ownership in the partnership is 34%, representing 1,656 megawatts in installed capacity.

We are currently engaged in four major power projects in the Philippines, (i) a “rehabilitate, operate, maintain, manage” 650-megawatt oil-fired power plant project in Malaya, with target completion in January 2011; (ii) a “build, operate and transfer” 1,200-megawatt combined-cycle power plant project in Ilijan, construction of which began in November 1997 and completed in June 2002; the project cost of the Ilijan project was US$710 million, for which project finance on a limited recourse basis was provided; (iii) acquisition in February 2006 of 40% equity interest in SPC Power Corporation, an independent power producer operating a 206-megawatt Naga power complex in Cebu, the Philippines; and (iv) construction, which began in February 2008, of 200-megawatt CFBC coal power plant in Naga, Cebu where the current 206-megawartt Naga power complex exists, with target completion in May 2011.

In March 2009, a consortium comprised of us and Samsung C&T was selected as a preferred bidder for the construction and operation of a coal power project in Balkash, Kazakhstan. We signed a framework agreement with Samruk Energy, Kazakh state-owned energy company. The “build-own-operate” project will produce 1,200~1,500 megawatts coal power plants in Kazakhstan, with target completion in 2014. We also acquired a priority right to construct an additional power project if the Kazakh government decides to build more plants in Balkhash area under its power supply plan. We believe this project provides us with an attractive opening to explore business opportunities into Central Asia with respect to its natural resources.

Middle East

In March 2008, a consortium consisting of us and Xenel was selected as the preferred bidder for a gas-fired power plant project located in Al Qatrana, near Amman, Jordan. The power plant is expected to have an installed capacity of 373 megawatts, cost US$460 million to construct and be subject to an operational term of 25 years. The construction for the “build-own-operate” project is expected to commence after execution of all necessary agreements, currently expected in the third quarter of 2009. We and Xenel are expected to hold a 65:35 equity interest, respectively, of the joint venture which will oversee the project. We believe that this project will help us to expand our business in the Middle East and position ourselves as a competitive power producer in the global market.

On December 1, 2008, we formed a consortium with ACWA Power International of Saudi Arabia and submitted a bid for the 1,204MW oil-fired power project in Rabigh, Saudi Arabia. On March 2009, we were selected as the preferred bidder against competitors that included Suez of Belgium, IP of Britain and Oger of Saudi Arabia. The project’s target completion date is 2013 and the project will involve operation of the plant for 20 years with an estimated project cost of US$2.5 billion. We are expected to hold a 40% equity interest in the joint venture which will oversee the project.

Since February 2006, we have been operated and provided maintenance services for combined cycle power plants in Lebanon with total capacity of 870 megawatts.

North America

On December 14, 2007, a consortium consisting of four Korean companies, namely us, Korea Resources Corporation, Hanwha Corporation and SK Energy Co., Ltd., entered into an agreement with CanAlaska Uranium, Ltd., a uranium exploration company located in Canada (“CanAlaska”), to carry out a joint uranium exploration project to search for uranium deposits across mines in the Cree East area in Canada. Under the terms of the agreement, the consortium and CanAlaska each hold a 50% equity interest in the project, whose term is for four years. The estimated capital expenditure for the project is C$19 million, all of which is to be borne by the consortium through cash contributions over the term of the project. Our share of the estimated cash contribution is C$4.75 million for which we have received a 12.5% equity interest in the project. If additional capital expenditure is required, the amount in excess of C$19 million is to be shared equally between CanAlaska and the consortium.

 

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On January 30, 2008, a consortium consisting of us, KHNP, our wholly-owned nuclear generation subsidiary, Korea Nuclear Fuel Co., Ltd., Hanwha Corporation and Gravis Capital Corp., a Canadian company, entered into an agreement with Fission Energy Corp., a uranium exploration company located in Canada, to carry out a joint uranium exploration project to develop a uranium mine near Waterbury Lake, Canada. Under the terms of the agreement, the consortium and Fission Energy Corp. each hold a 50% equity interest in the project, whose term is for three years. The estimated capital expenditure for the project is C$15 million, all of which is to be borne by the consortium through cash contributions over the term of the project. Under the terms of the agreement, the consortium is to purchase the 50% equity interest in the project held by Fission Energy Corp. upon the final payment of cash contributions by the consortium during the term of the project. We have a 20% equity interest in the project and are expected to make estimated cash contribution of C$6 million. KHNP holds a 15% equity interest and is expected to make estimated cash contribution of C$4.5 million. The other members of the consortium each hold a 5% equity interest in the project and are each expected to make an estimated cash contribution of C$1.5 million.

On June 15, 2009, we and KHNP, our wholly-owned nuclear generation subsidiary, entered into a definitive agreement with Denison Mines Corporation (“Denison”) to purchase 58.0 million shares, or 17.0%, of the share capital of Denison for an aggregate purchase price of C$75.4 million. As a result of such share purchase, we are expected to become the largest shareholder of Denison. Under the terms of the agreement, we will be entitled to procure up to 300 metric tons of uranium per annum, which amounts to approximately 20% of Denison’s current annual uranium production, during the period from 2010 to 2015. For the period from 2016, we will also be entitled to procure up to 20% of Denison’s then annual uranium production so long as we beneficially own 10% or more of Denison’s share capital.

Australia

On November 7, 2007, we and Korea East-West Power Corporation, or EWP, our wholly-owned generation subsidiary, entered into a share subscription agreement with Cockatoo Coal Limited, a coal exploration and mining company located in Australia. Under the terms of agreement, we and EWP acquired 40 million ordinary shares of Cockatoo Coal in equal proportions, representing approximately 9.5% of total equity ownership in Cockatoo Coal, for cash in the amount of A$16.8 million. We intend to participate in coal exploration projects or development projects with Cockatoo in the future. On February 26, 2009, EWP entered into another share subscription agreement for 9.9 million ordinary shares for A$5 million, which leads to 10.5% of total equity ownership.

On January 2, 2008, a consortium consisting of Korea Resources Corporation, Hanwha Corporation, us and four of our wholly owned generation subsidiaries, namely, Korea South-East Power Corporation, Korea Midland Power Corporation, Korea Western Power Corporation, Korea Southern Power Corporation, entered into an agreement with Felix Resources Limited, an Australian coal mining company, to develop a coal mine located in Moolarben, New South Wales, Australia. Under the terms of agreement, the consortium purchased 10% equity interest in the Moolarben project from Felix Resources, of which we and our four generation subsidiaries own an aggregate of 5%. Felix holds 80% equity interest of the project. The consortium will participate in the mine development and operation through cash contribution which is equal to 10% of capital expenditure incurred on the project, and the amount is estimated around AU$110 million for the life of mine, which is currently expected to be 21 years. Our four generation subsidiaries also have a coal offtake agreement for 2.5 million tons of coal per annum, and the mining will commence by March 2010. The reserve is approximately 300 million tons of high quality thermal coal with average production capacity of 10 million tons per annum.

Africa

In August 2005, a consortium consisting of us, Korea National Oil Corporation, a state-controlled enterprise, and Daewoo Shipbuilding & Marine Engineering won a bid from the federal government of Nigeria for exploration and production of oil in two off-shore blocks. This consortium holds 60% of the equity interest in the special purpose vehicle established to carry out the project regarding these two blocks and we hold 8.775% of

 

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the interest in the consortium. In March 2006, the consortium entered into production sharing contracts with the Nigerian National Petroleum Corporation in connection with this project. Under these contracts, if the consortium is successful in finding oil, it will be entitled to operate the related facilities for 20 years. However, in January 2009, the leader of the consortium, Korea National Oil Corporation, was informed of a unilateral decision by the government of Nigeria to void allocation of the oil blocks granted to the consortium based on a claim that the consortium failed to pay full amount of the consideration. Korea National Oil Corporation has filed a suit in the Nigerian court challenging this assertion. The case is currently pending.

Another consortium consisting of us, KNOC and POSCO Engineering & Construction commenced the development of the downstream projects in Nigeria in 2006. While an in-principle agreement with the Nigerian authorities regarding the project development was made in October 2008, due the court proceedings discussed above, the downstream projects are currently on hold.

In October 2007, we invested US$9.1 million in KEPCO Energy Resource Nigeria Ltd., or KERNL, a joint venture with the Nigerian government, for a 30% equity capital in KERNL. We currently own 30% of KERNL’s equity capital. In May 2007, KERNL entered into a share purchase agreement with the Nigerian government for the purchase of 51% of the equity capital of Egbin Power Plc in Nigeria, which owns and operates the Egbin power plant, for a consideration of approximately US$280 million, of which US$28 million has been paid to-date.

North Korea

Kaesong Complex

In March 2005, we began providing electricity to the industrial complex located in Kaesong, North Korea, which was established pursuant to an agreement made during the summit meeting of the two Koreas in June 2000. The Kaesong complex is the largest economic project between the two Koreas and is designed to combine the Republic’s capital and entrepreneurial expertise with the availability of land and labor of North Korea. The size of this industrial complex is expected to be increased in a number of phases, with the first phase involving the laying of the groundwork for the complex measuring 3.3 million square-meters, and will ultimately be increased to 66 million square-meters. The construction for plot preparation was completed at the end of 2007. In May 2004, we were selected as electricity supplier for the phase one development by the Ministry of Reunification. In December 2004, a memorandum of understanding between the two Koreas for electricity supply was reached, enabling us to design, build and operate all of the electricity supply facilities in and connecting to the Kaesong complex. In March 2005, we built a 22.9 kilovolt distribution line from Munsan substation in Paju, Gyeonggi Province to the Kaesong complex and became the first to supply electricity to pilot zones such as ShinWon Ebenezer. In April 2006, we started to construct a 154 kilovolt, 16 kilometer transmission line connecting Munsan substation to the Kaesong complex as well as Pyunghwa substation in the complex and began operations in May 2007. As of December 31, 2008, we supplied electricity to 253 units, including administrative agencies and support facilities and 93 companies, using a tariff structure identical to that of South Korea. No assurance can be given that we will not experience any material losses from this project as a result of, among other things, project suspension or failure of the project as a result of a breakdown in the relationship between the Republic and North Korea. See Item 3. “Key Information—Risk Factors—Risks Relating to Korea and the Global Economy—Tensions with North Korea could have an adverse effect on us and the market value of our shares.”

The Light Water Reactor Project

The Korean Peninsula Development Organization, or KEDO, was chartered in March 1995 as an international consortium stipulated by the Agreed Framework, which was signed by the United States and North Korea in October 1994. KEDO signed an agreement with North Korea in December 1995 to construct two light water reactors in North Korea in return for certain nuclear non-proliferation steps to be taken by North Korea. KEDO designated us as its prime contractor to build two units of pressurized light water reactors with total capacity of 2,000 megawatts. We entered into a fixed price turnkey contract with KEDO, which became effective on February 3, 2000.

 

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However, when North Korea did not meet the conditions required for the continuation of the project, KEDO suspended the project in December 2003. Following the suspension, KEDO notified us of the termination of the project and the related turnkey contract between KEDO and us. The executive board of KEDO decided to terminate the light water reactor project on May 31, 2006. On December 12, 2006, we entered into a termination agreement with KEDO. According to the termination agreement, we assumed substantially all of KEDO’s rights and obligations related to the light water reactor outside of North Korea. In exchange, we waived the right to claim any expenses incurred and any potential claims by subcontractors to KEDO. We recorded the equipment transferred under the termination agreement as other non-current assets in the amount of (Won)94 billion, and the estimated claims by subcontracts as other long-term liabilities in the amount of (Won)17 billion.

Pursuant to the terms of the termination agreement, we are required to report the disposal or reuse of the transferred equipment to KEDO, and the gains and losses under the termination agreement are shared with KEDO through mutual negotiation. Our management believes that ultimate gains or losses could not be reasonably estimated as of December 31, 2008, as they are contingent upon disposal or reuse of the related assets and settlement of obligations.

Insurance

We carry insurance covering against certain risks, including fire, in respect of our key assets, including buildings, equipment, machinery, construction-in-progress and procurement in transit, as well as, in the case of KEPCO, directors’ and officers’ liability insurance.

We maintain casualty and liability insurance against risks related to our business to the extent we consider appropriate and otherwise self-insure against such risks to the extent permitted by law. We do not separately insure against terrorist attacks.

These insurance and indemnity policies, however, cover only a portion of the assets that we and our generation subsidiaries own and operate and do not cover all types or amounts of loss that could arise in connection with the ownership and operation of these assets.

Substantial liability may arise from the operation of nuclear-fueled generation units and from the use and handling of nuclear fuel and possible radioactive emissions associated with such nuclear fuel. KHNP maintains property and liability insurance against risks of its business to the extent required by the related law and regulations or considered as appropriate and otherwise self-insure against such risks. KHNP carries insurance for its generation units against certain risks, including property damage, nuclear fuel transportation and liability insurance for personal injury and property damage. Each of KHNP’s four power plant complexes has property damage insurance coverage of up to US$1 billion per accident in respect of such plant complex. KHNP maintains a nuclear liability insurance for personal injury and third-party property damage for a coverage of up to (Won)50 billion per accident per plant complex, for a total coverage of (Won)200 billion. KHNP is also the beneficiary of a Government indemnity with respect to such risks for damage claims of up to (Won)50 billion per nuclear plant complex, for a total coverage of (Won)200 billion. Under the Nuclear Damage Compensation Act of 1969, as amended, KHNP is liable only up to 300 million Special Drawing Rights, or SDRs, approximately US$454 million, at the rate of 1 SDR = US$1.51363 as posted on the Internet homepage of the International Monetary Fund on May 11, 2009 per single accident; provided that such limitation will not apply where KHNP intentionally caused the harm or knowingly failed to prevent the harm from occurring. KHNP will receive the Government’s support, subject to the approval of the National Assembly, if (i) the damages exceed the insurance coverage amount of (Won)50 billion and (ii) the Government deems such support to be necessary for the purposes of protecting damaged persons and supporting the development of nuclear energy business. The amount of Government’s support to KHNP for such qualifying nuclear incident would be 300 million SDRs, or the limit of KHNP’s liability, minus the coverage amount of up to (Won)50 billion as determined by the National Assembly. KHNP also carries insurance against terrorism with the insurance coverage being up to US$300 million on property and (Won)50 billion on liabilities. While KHNP carries insurance for its generation units and nuclear fuel transportation, the level of insurance is generally adequate and is in compliance with relevant laws and

 

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regulations, and KHNP is the beneficiary of a certain Government indemnity which covers a portion of liability in excess of the insurance, such insurance is limited in terms of amount and scope of coverage and does not cover all types or amounts of losses which could arise in connection with the ownership and operation of nuclear plants. Accordingly, material adverse financial consequences could result from a serious accident to the extent neither insured nor covered by the government indemnity.

Other than KHNP, neither we nor our generation subsidiaries carry any insurance against terrorist attacks specifically.

See Item 3. “Key Information—Risk Factors—Risks Relating to KEPCO—The amounts and scope of coverage of our insurance are limited.”

Affiliated Companies

We define our principal affiliates as companies in which we hold at least 20% and not more than 50% of the share capital, whose accounts are not required to be consolidated in our financial statements. We record these affiliates as investments under the equity method of accounting. See Note 6 of the notes to our consolidated financial statements. The table below sets forth for each of our principal affiliates the name and year of incorporation, our percentage shareholding and their principal activities as of December 31, 2008.

 

    Year of
Incorporation
  Ownership
(Percent)
 

Principal Activities

Korea Gas Corporation

  1983   24.5   Sales of liquefied natural gas

Korea District Heating Co. Ltd.

  1985   26.1   Provision of heat

Korea Electric Power Industrial Development Co., Ltd.

 

 

1990

 

 

49.0

  Disposal of power-plant ash and electric meter reading

YTN(1)

  1993   21.4   Broadcasting

LG Powercom Corporation(2)

  2000   38.8   Communication line leasing

Gangwon Wind Power Co., Ltd.(3)

  2001   15.0   Communication line leasing

Gansu Datang Yumen Windpower
Co., Ltd.

 

 

2005

 

 

40.0

  Construction and operation of utility plant

Cheongna Energy Co., Ltd.

  2005   27.0   Generating and distributing steam and hot and cold water

SPC Power Corporation

  2006   40.0   Operation of utility plant

Datang Chifang Renewable Co., Ltd.

  2006   40.0  

Construction and operation of

utility plant

Gemeng International Energy Group
Co., Ltd.

 

 

2007

 

 

34.0

 

Construction and operation of

utility plant

KEPCO Energy Resource Nigeria Ltd.

  2007   30.0  

Construction and operation of

utility plant

Hyundai Green Power Co., Ltd.

  2007   29.0   Generating electricity

PT.Cirebon Electric Power

  2008   27.5  

Construction and operation of

utility plant

 

Notes:

 

(1) KEPCO Data Network Co., Ltd., a wholly-owned subsidiary of KEPCO, owns the 21.4% equity interest in YTN.
(2) In November 2008, LG Powercom completed an initial public offering of common shares. We did not participate in this offering, but as a result of the offering, our share ownership in LG Powercom was diluted to 38.8% from 43.1%.
(3) Although we hold less than 20%, we deem Gangwon Wind Power as a principal affiliate as we can influence the major policies of this company through our voting power at the board of directors’ level.

 

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Competition

We currently transmit and distribute substantially all of the electricity in Korea. In addition to us, there were 16 electricity suppliers that are licensed to distribute electricity in 20 districts of Korea as of April 30, 2009. These entities do not supply electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System authorized by the Korea Electricity Commission and approved by the Minister of Knowledge and Economy in accordance with the Electricity Business Act. We also transmit and distribute electricity to these districts. As of April 30, 2009, 6 districts were using this system, and 14 other districts were preparing to launch it. The generation capacity installed or under construction of the electricity suppliers in these 20 districts amounted to approximately 1% of the generation capacity of our generation subsidiaries as of April 30, 2009. Since the introduction of the Community Energy System in 2004, a total of 31 districts have obtained the license to obtain electricity supply through the Community Energy System, but 11 of such districts have reportedly abandoned plans to adopt the Community Energy System and four more districts are reportedly considering to abandon such plans, largely due to the relatively high level of capital expenditure required, the rise in fuel costs and the lower-than-expected electricity output per cost. However, if the system is widely adopted, it will erode our market position in the generation and distribution of electricity in Korea, which has been virtually monopolized by us until recently, and may have a material adverse effect on our business, growth, revenues and profitability.

The power generation industry, which began its liberalization process with the establishment of our power generation subsidiaries in April 2001, may become further liberalized in accordance with the Restructuring Plan.

In the residential sector, consumers may use natural gas, oil and coal for space and water heating and cooking. However, currently there is no practical substitute for electricity for lighting and for many household appliances.

In the commercial sector, electricity is the dominant energy source for lighting, office equipment and air conditioning. Its other uses, such as space and water heating, natural gas and, to a lesser extent, oil, provide competitive alternatives to electricity.

In the industrial sector, currently there is no practical substitute for electricity in a number of applications, including lighting and power for many types of industrial machinery and processes. For other uses, such as space and water heating, electricity competes with oil and natural gas and potentially with gas-fired combined heating and power plants.

Regulation

We are a statutory juridical corporation established under the KEPCO Act for the purpose of ensuring stabilization of the supply and demand of electric power and further contributing toward the sound development of the national economy through expediting development of electric power resources and carrying out proper and effective operation of the electricity business. The KEPCO Act contemplates that we engage in the following activities:

 

   

development of electric power resources;

 

   

generation, transmission, transformation, distribution of electricity and other related business;

 

   

investment, research and technology development related to the businesses mentioned in items 1 and 2;

 

   

overseas business related to the businesses mentioned in items 1 through 3;

 

   

investments or contributions related to the businesses mentioned in items 1 through 4;

 

   

businesses incidental to items 1 through 5; and

 

   

other businesses entrusted by the Government.

The KEPCO Act currently requires that our profits be applied in the following order of priority:

 

   

first, to make up any accumulated deficit;

 

   

second, to set aside as a legal reserve of 20% or more of profits until the accumulated reserve reaches one-half of our capital;

 

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third, to pay dividends to stockholders;

 

   

fourth, to set aside a reserve for expansion of our business;

 

   

fifth, to set aside a voluntary reserve for the equalization of dividends; and

 

   

sixth, to carry forward surplus profit.

Based on our consolidated financial results as of December 31, 2008, the legal reserve was (Won)1,604 billion, the reserve for business expansion was (Won)19,009 billion, and the reserve for investment of social overhead capital was (Won)5,277 billion.

We are under the supervision of the Ministry of Knowledge Economy, which has principal responsibility with respect to director and management appointments and rate approval.

Because the Government owns part of our capital stock, the Government’s Board of Audit and Inspection may audit our books.

The Electricity Business Act requires that licenses be obtained in relation to the generation, transmission and distribution and sale of electricity, with limited exceptions. We hold the license to generate, transmit, distribute and sell electricity. Several other companies have received a license solely for power generation. See “Business Overview—Power Purchase—Cost-based Pool System.” Each of our six generation subsidiaries holds an electricity generation license. We and 16 other suppliers of electricity under the Community Energy System authorized by the Korea Electricity Commission and approved by the Minister of Knowledge Economy in accordance with the Electricity Business Act have a license for the distribution of electricity. The Electricity Business Act also governs the formulation and approval of electricity rates in Korea. See “—Electricity Rates” above.

Our operations are subject to various laws and regulations relating to environmental protection and safety. See “—Community Programs” above.

Proposed Sale by Us of Certain Power Plants and Equity Interests

Set forth below is our plan of selling certain assets as currently contemplated. The completion of our plans, however, is subject to, among other considerations, Government policies relating to us and market conditions.

 

Subsidiaries and affiliates

 

Primary business

  Book value
as of
December 31,
2008
  Ownership percentage
as of
December 31,
2008
  Ownership
percentage
to be sold
        (in billions of Won)

Korea District Heating Co., Ltd.

 

Generating and distributing electricity and heat

  187   26.1   Not determined

Korea Electric Power Industrial Development Co., Ltd.

  Electricity metering   29   49.0   Not determined

LG Powercom Corporation

  Leasing telecommunication lines and providing internet access   385   38.8   28.8

Korea Gas Corporation

  Importing and wholesaling LNG   1,023   24.5   Not determined

KPS Co., Ltd.

  Overhauling and repairing power plants   287   80.0   20.0

Korea Power Engineering Co., Ltd.

 

Designing and engineering power plants

  26   97.9   40.0

 

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Korea Power Engineering Co., Ltd.

Pursuant to the Third Phase of the Public Institution Reform Plan announced by the Government in August 2008, we currently plan to sell approximately 40% of Korea Power Engineering’s equity by the end of 2012 after taking into consideration the opportunities for acquiring advance technology and/or overseas expansion of the nuclear generation business, among others.

KPS Co., Ltd.

In December 2007, we have completed the initial public offering of KPS Co., Ltd, formerly our wholly-owned subsidiary, by listing approximately 20% of its equity interest on the Korea stock exchange for an aggregate consideration of (Won)120 billion. Pursuant to the Third Phase of the Public Institution Reform Plan, we currently plan to sell an additional 20% of KPS Co., Ltd’s equity interest by the end of 2012.

Korea Electric Power Industrial Development Co., Ltd.

In February 2003, we privatized Korea Electric Power Industrial Development, formerly our wholly-owned subsidiary, by selling 51% of its equity interest to Korea Freedom Federation. Pursuant to the Fifth Phase of the Public Institution Reform Plan announced by the Government in January 2009, we currently plan to sell the remaining 49% of Korea Electric Power Industrial Developments equity interest based on considerations of economic and market conditions, among others.

LG Powercom Corporation

In January 2000, we established LG Powercom (formerly PowerComm Corporation) as a wholly-owned subsidiary to foster fair use and competition in the use of the power lines for communication purposes as well as to dispose of non-core businesses. Following a series of sales that began in July 2000 and a public offering in November 2008 of equity interests in LG Powercom, we currently own 38.8% equity interest in LG Powercom. Pursuant to the Fifth Phase of the Public Institution Reform Plan, we currently plan to sell the remaining 49% of LG Powercom’s equity interest based on considerations of economic and market conditions, among others.

On September 27, 2007, the investment trust management agreement among Prudential Asset Management Co. Ltd., Hana Daetoo Securities Co., Ltd., Korea Investment & Securities Co., Ltd., collectively as investment managers, was terminated upon expiration of its term under the contract. Under this agreement, the aforementioned investment managers managed the assets contributed by us into a special purpose vehicle, established in December 1992 for the purpose of market stabilization of the Korea Stock Exchange, into which we and certain other companies in Korea made an investment by way of in-kind contribution of our and their respective treasury stock. Following the termination of the investment trust management agreement, our treasury stock contributed into such vehicle was sold in the market, and we received the net proceeds thereof in the amount of (Won)84 billion. The aggregate amount of our assets at the time of initial contribution under the investment trust management agreement was (Won)50 billion.

PROPERTY, PLANT AND EQUIPMENT

Our property consists mainly of power generation, transmission and distribution equipment and facilities in Korea. See “—Business Overview—Power Generation,” “—Transmission and Distribution” and “—Capital Investment Program.” In addition, we own our corporate headquarters building complex at 411 Youngdong-daero, Gangnam-gu, Seoul 135-791, Korea. On June 24, 2005, the Government announced its policy to relocate the headquarters of government-invested enterprises, including us and certain of our subsidiaries, out of the Seoul metropolitan area to other provinces in Korea by the end of 2012. As of December 31, 2008, the net book value of our property was (Won)69,795 billion. No significant amount of our properties is leased. There are no material encumbrances on our properties, including power generation, transmission and distribution equipment and facilities.

 

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ITEM 4A. UNRESOLVED STAFF COMMENTS

On September 29, 2008, we received a letter from the staff of the U.S. Securities and Exchange Commission commenting on our annual report on Form 20-F for the fiscal year ended December 31, 2007. On November 17, 2008 and December 5, 2008, we submitted our response to such comments from the staff. We have prepared this annual report in light of the staff’s comments contained in the letter dated September 28, 2007.

We do not have any unresolved comments from regarding our periodic reports under the Securities Exchange Act of 1934, as amended.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

You should read the following discussion together with our consolidated financial statements and the related notes which appear elsewhere in this report. We expect that the implementation of the Restructuring Plan will over time materially change the environment in which we operate, and, accordingly, our historic performance may not be indicative of our future results of operations and capital requirements and resources. See Item 4. “Information on the Company—Business Overview—Restructuring of the Electricity Industry in Korea” and Item 3. “Key Information—Risk Factors—Risks Relating to KEPCO—The Government’s plan for restructuring the electricity industry in Korea may have a material adverse effect on us.”

OPERATING RESULTS

Overview

In 2006, 2007 and 2008, we had consolidated operating revenues of (Won)27,409 billion, (Won)29,137 billion and (Won)31,560 billion (US$25,008 million), respectively, principally from the sale of electricity. As we are a predominant market participant in the Korean electricity industry, our business is heavily regulated by the Government with respect to the rates we charge to customers for the electricity we sell. In addition, our business requires a high level of capital expenditures and is subject to a number of variable factors, including demand for electricity in Korea and fluctuation in costs, such as fuel prices which are impacted by the movements in the exchange rates between the Won and other currencies.

In 2008, we recorded net loss of (Won)2,914 billion (US$2,309 million) compared to net income of (Won)1,467 billion and (Won)2,246 billion in 2007 and 2006, principally due to the rapid rise in fuel costs.

Under the Electricity Business Law and the Price Stabilization Act, electricity rates are generally established at levels that will permit us to recover our operating costs attributable to our basic electricity generation, transmission and distribution operations in addition to receiving a fair investment return on capital used in those operations. For a detailed description of fair investment return, see Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates.” Accordingly, we have recorded net profit for every operating year since our inception in 1981 until 2007. However in 2008, for the first time in our operating history, we recorded a net loss. This was largely due to a rapid increase in fuel prices, which was not offset by an increase in the electricity rates that we charge to our customers. The Government raised the tariff rates in November 2008, following an extensive deliberative process, including public debates, and provided us with a one-time subsidy in the amount of (Won)668 billion in December 2008. However, there is no assurance that such tariff increase will be sufficient to fully offset the adverse impact from the rise in fuel costs on our business or results of operation. We estimate that the recent spike in fuel prices may continue to have a material adverse effect on our results of operations and profitability in 2009 and beyond. We are currently negotiating with the Government for further tariff increase, but cannot assure that the Government will agree to such increase at the level desired by us or at all. If the fuel prices remain at the current level or continue to increase and the Government, out of concern for inflation or for other reasons, maintains the current level of electricity tariff or does not increase it to a level to sufficiently offset the impact of rising fuel prices, the fuel price increases will

 

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significantly narrow our profit margins or even cause us to suffer net losses and our business, financial condition, results of operations and cash flows would seriously suffer.

Demand and Supply of Electricity

Our results of operations, sales in particular, are dependent upon demand for electricity in Korea and the rates we charge for the electricity we sell.

The rapid growth in Korean economy since the early 1960s has resulted in substantial growth in demand for electricity. While the worldwide economic recession of the early 1980s slowed economic growth in Korea, in the latter half of the 1980s, the Korean economy resumed rapid growth and resulted in a substantial increase in demand for electricity. The slow economic growth in Korea in the early 1990s resulted in a slight decline in the growth of demand for electricity. Following the Asian financial crisis in 1998, electricity demand contracted in Korea for several years but resumed stable growth in the early 2000s with an annual growth rate generally between 5% and 8% between 2001 and 2008. Demand for electricity in Korea grew at a compounded average rate of 5.6% per annum for the five years ended December 31, 2008. According to The Bank of Korea, real gross domestic product, or GDP, compounded growth rates was approximately 4.2 % for the same period. The GDP growth rate was 2.2% for 2008 as compared to 5.1% in 2007. However, following the onset of the global liquidity crisis, the Korean economy experienced a contraction in real gross domestic product by 3.4% and 4.3% in the fourth quarter of 2008 and the first quarter of 2009 compared to corresponding quarters year on year, respectively. Partly as a result thereof, particularly the resulting slowdown in industrial activities, demand for electricity decreased by 2.3% from the first quarter of 2008 to the first quarter of 2009, and in light of the negative or slow growth in GDP currently anticipated for 2009 we cannot guarantee that electricity sales will increase in 2009.

The table below sets forth, for the periods indicated, the annual rate of growth in Korea’s gross domestic product and the annual rate of growth in electricity demand (measured in total annual electricity consumption).

 

     2004     2005     2006     2007     2008  

Growth in GDP (at 2000 constant prices)

   4.6 %   4.0 %   5.2 %   5.1 %   2.2 %

Growth in electricity consumption

   6.3 %   6.5 %   4.9 %   5.7 %   4.5 %

Demand for electricity may be categorized either by the nature of its usage or by the type of customers as used for the purpose of charging electricity tariff. See Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates.” The following describes the demand for electricity by the nature of its usage:

 

   

The industrial usage currently represents the largest segment of electricity consumption in Korea. While the industrial usage (including the agricultural usage) has increased steadily as a result of economic growth in Korea, it has gradually declined as a percentage of total consumption from 62.6% in 1997 to 55.1 % in 2008 In addition, demand from the industrial usage (including the agricultural usage) increased by 4.5 % to 212,344 gigawatt hours in 2008 as compared to 2007.

 

   

The commercial usage accounted for 22.5 % of electricity consumed in 2008 in Korea. The commercial usage has increased in recent years, both in absolute terms and as a percentage of total demand. The commercial usage has shown the highest rate of growth in demand since 1980 and increased by 5.6 % to 86,827 gigawatt hours in 2008 as compared to 2007.

 

   

The residential usage increased by 2.8 % to 77,269 gigawatt hours in 2008 as compared to 2007.

For additional discussions on demand by the type of customers, see Item 4. “Information on the Company Business Overview—Sales and Customers—Demand by the Type of Usage.”

In July 2004, the Government adopted the Community Energy System to enable regional districts to source electricity from independent power producers to supply electricity without having to undergo the cost-based pool

 

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system used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. A supplier of electricity under the Community Energy System must be authorized by the Korea Electricity Commission and be approved by the Minister of Knowledge Economy in accordance with the Electricity Business Act. The purpose of this system is to decentralize electricity supply and thereby reduce transmission costs and improve the efficiency of energy use. As of April 30, 2009, six districts are using this system and 14 other districts are preparing to launch it. The generation capacity installed or under construction of the electricity suppliers in the 20 districts amounted to approximately 1.0% of the generation capacity of our generation subsidiaries as of April 30, 2009. If this system is widely adopted, this system will erode our market position in the generation and distribution of electricity in Korea, which has been virtually monopolistic to-date. Unless we become more operationally efficient so as to keep the loss of our market share to the minimum, this system may have a material adverse effect on our business, growth, revenues and profitability.

The table below sets forth for the year ended December 31, 2007 and 2008 and as of April 30, 2009, the number of districts with government permits to participate in the Community Energy Supply, the number of apartments in such districts and generating capacity to be installed.

 

For the years ended and as of

   Number of Districts
with Permit to
Participate
   Number of
Apartments
   Generating
Capacity
          (in thousands)    (Megawatts)

December 31, 2007

   26    242    1,177

December 31, 2008

   31    320    1,472

April 30, 2009(1)

   20    186    841

 

Note:

 

(1) Reflects 11 districts with a permit to participate in the Community Energy System, which have subsequently announced that they are abandoning plans to adopt such system. In addition, four more districts are reportedly considering abandoning such plans. The number of apartments and generating capacity represented by such districts are approximately 134,000 units and 631,000 megawatts, respectively.

Electricity Rates

The Electricity Business Law and the Price Stabilization Act prescribe the procedures for the approval and establishment of rates charged for the electricity we sell. In order to revise the rates we charge or change the electricity rate structure, we submit our proposals to the Ministry of Knowledge Economy for review, which then makes the final decision following consultation with the Electricity Rates Expert Committee of the Ministry of Knowledge Economy and the Ministry of Strategy and Finance. Under the recently amended Electricity Business Law, the Korean Electricity Commission must review these proposals prior to the final decision by the Ministry of Knowledge Economy. On January 1, 2008, the Ministry of Knowledge Economy adjusted our rate schedule by increasing the average industrial rates and average night power usage rates by 1.0% and 18.0%, respectively, while reducing the average commercial rates by 3.0%. As a result of such adjustments, which had the effect of balancing out the increase with the decrease, our overall average rate did not materially change. In addition, in light of the rapid rise in fuel prices following the general rise in commodity prices (including oil) worldwide in the second half of 2007 and the first half of 2008 which seriously undermined our profitability, effective November 13, 2008, the Ministry of Knowledge Economy increased the industrial, commercial, educational and street lighting rates by 8.1%, 3.0%, 4.5% and 4.5%, while making no changes to the residential and agricultural rates, which is expected to result in an increase by 4.5% in our overall average rate. There is no assurance, however, that such rate increase will be sufficient to fully offset the adverse impact from the rise in fuel costs on our business or results of operations. See “Business Overview—Sales and Customers—Electricity Rates.”

Fuel Costs

Our results of operations are also significantly affected by the cost of producing electricity, which is subject to a variety of factors, including, in particular, the cost of fuel.

 

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Cost of fuel in any given year is a function of the volume of fuels consumed and the unit fuel cost for the various types of fuel used for generation of electricity (i) by our generation subsidiaries or (ii) by independent power producers from whom we purchase electric power. A significant change in the unit fuel costs materially impacts the costs of electricity generated by our generation subsidiaries (which costs form part of our power generation, transmission and transmission costs expenses) as well as, to our knowledge, the costs of electricity generated by the independent power producers that sell their electricity to us (which costs form part of our purchased power expenses). We believe that unit fuel costs materially impact the total fuel costs for both generated power and purchased power, but are unable to provide a comparative analysis since the unit fuel cost information for purchased power is proprietary information of the independent power producers, who use a significantly different composition of the types of fuels for power generation.

Fuel costs accounted for 32.6%, 35.7% and 49.8% of our operating revenues and 37.2%, 39.5% and 45.8% of our operating expenses in 2006, 2007 and 2008, respectively. Substantially all of the fuel (except for anthracite coal) used by our generation subsidiaries is imported from outside of Korea at prices determined in part by prevailing market prices in currencies other than Won. In addition, our generation subsidiaries purchase a significant portion of their fuel requirements under contracts with limited quantity and duration. Pursuant to the terms of our long-term supply contracts, prices are adjusted in light of market conditions. See Item 4. “Information on the Company—Business Overview—Fuel.”

Uranium accounted for 41.0%, 37.6%, and 38.3% of our fuel requirements in 2006, 2007 and 2008, respectively. Coal accounted for 38.7%, 40.9% and 43.9% of our fuel requirements in 2006, 2007 and 2008, respectively. Oil (including diesel for internal combustion) accounted for 4.1%, 4.3% and 2.2% of our fuel requirements in 2006, 2007 and 2008, respectively. LNG accounted for 15.3%, 16.4% and 14.6% of our fuel requirements in 2006, 2007 and 2008, respectively. In each case, the fuel requirements are measured by the amount of electricity generated by us and do not include electricity purchased from third parties. In order to ensure stable supplies of fuel materials, our generation subsidiaries enter into long-term and medium-term contracts with various suppliers and supplement such supplies with fuel materials purchased on spot markets.

In the past few years, the price of bituminous coal underwent a wide fluctuation, with a substantial rise until the first half of 2008, after which it has gradually decreased. However, there can be no assurance that the price will remain stable or not increase rapidly. See Item 4. “Information on the Company—Business Overview—Fuel.” In 2008, approximately 82.6% of the combined bituminous coal requirements of our generation subsidiaries were purchased under long-term contracts and 17.4% purchased on the spot market. The average “free on board” Newcastle coal price index in 2008 was US$128.4 per ton. In March 2009, the average “free on board” Newcastle coal price index was down to US$64.4 per ton. If the bituminous coal price rises again to the level of 2008 or higher, our generation subsidiaries may not be able to secure their respective bituminous coal supplies at prices commercially acceptable to them. In addition, any significant interruption or delay in the supply of fuel, bituminous coal in particular, from any of their suppliers could cause our generation subsidiaries to purchase fuel on the spot market at prices higher than contracted, resulting in an increase in fuel cost. Furthermore, there have been recent increases in crude oil prices that may lead to an increase in the price of commodity oil that we use, thereby resulting in higher fuel cost.

Because the Government heavily regulates the rates we charge for the electricity we sell (see Item 4. “Information on the Company—Business Overview—Sales and Customers—Electricity Rates”), our ability to pass on such cost increases to our customers is limited. The spike of fuel prices in 2008 has led to our recording net loss for the first time in our operating history in 2008 and we estimate that it will continue to have a similar adverse effect in 2009. If the fuel prices remain at the current level or continue to increase and the Government, out of concern for inflation or for other reasons, maintains the current level of electricity tariff or does not increase it to a level to sufficiently offset the impact of rising fuel prices, the price increases will significantly narrow our profit margins or even cause us to suffer net losses and our business, financial condition, results of operations and cash flows would seriously suffer.

 

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Nuclear power has a stable low-cost structure and forms a significant portion of the base load of electricity supplied in Korea. Due to significantly lower fuel costs as compared with those of conventional power plants, our nuclear power plants generally operate at full capacity with only routine shutdowns for check-up and overhauls lasting 30 to 40 days. In case of shortage in electricity generation resulting from stoppages of the nuclear power plants, we seek make up for such shortage with power generated by our coal-fired power plants.

Movements of the Won against the U.S. Dollar and Other Foreign Currencies

Korean Won has fluctuated significantly against major currencies in recent years. For fluctuations in exchange rates, see Item 3. “Key Information—Selected Financial Data—Currency Translations and Exchange Rates.” In particular, as liquidity and credit concerns and volatility in the global financial markets increased significantly since the second quarter of 2008, the value of Won relative to U.S. dollar has depreciated at an accelerated rate. The Noon Buying Rate per one U.S. dollar depreciated from (Won)936.6 to on January 2, 2008 to (Won)1,570.1 on March 2, 2009. The Noon Buying Rate per one U.S. dollar was (Won)1,246.0 on June 12, 2009. The depreciation of Won against U.S. dollar and other foreign currencies in the past had resulted in a material increase in the cost of servicing our foreign currency debt and the cost of fuel materials and equipment purchased from overseas. As of December 31, 2008, approximately 29.3% before swap transaction of our long-term debt (including the current portion thereof) was denominated in foreign currencies, in U.S. dollar, Yen and Euro. The prices for substantially all of the fuel materials and a significant portion of the equipment we purchase are stated in currencies other than Won, generally in U.S. dollars. Since substantially all of our revenues are denominated in Won, we must generally obtain foreign currencies through foreign-currency denominated financings or from foreign currency exchange markets to make such purchases or service such debt. As a result, any significant depreciation of Won against U.S. dollar or other foreign currencies will have a material adverse effect on our profitability and results of operations. See Item 3. “Key Information—Risk Factors—Risks Relating to KEPCO—The movement of Won against the U.S. dollar and other currencies may have a material adverse effect on us.”

Recent Accounting Changes

Preparation and Presentation of Financial Statements

We adopted SKAS No. 21—“Preparation and Presentation of Financial Statements,” SKAS No. 23—“Earning per Share” and SKAS No. 25—“Consolidation Financial Statements”, effective from January 1, 2007. Adoption of these newly effective SKAS in 2007 did not result in any change to reported net income or shareholders’ equity in 2006. Pursuant to adoption of SKAS No. 21, valuation gain on available-for-sale, unrealized loss and gain on investment securities using the equity method, cumulative effect of foreign currency translation and valuation loss on derivatives, formerly classified as capital adjustments, are reclassified as accumulated other comprehensive income. In addition, pursuant to adoption of SKAS No. 25, income before minority interest is reclassified as net income. Furthermore, controlling interest in net income and minority interest in net income are separately presented in the consolidated statements of income.

Income Taxes

In 2007, we adopted amended SKAS No. 16—“Income Taxes” which are amended such that additional payment of income taxes and income tax refunds, formerly classified as other income (expenses), are reclassified as income taxes. Moreover, consolidated subsidiaries’ deferred income tax assets and liabilities, formerly recorded at net amount, are separately recorded in the consolidated balance sheets.

 

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Critical Accounting Policies

The following discussion and analysis is based on our consolidated financial statements. The fundamental objective of financial reporting is to provide useful information that allows a reader to comprehend our business activities. To aid in that understanding, our management has identified “critical accounting policies.”

We make a number of estimates and judgments in preparing our consolidated financial statements. These estimates may differ from actual results and have a significant impact on our recorded assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We consider an estimate to be a critical accounting estimate if it requires a high level of subjectivity or judgment, and a significant change in the estimate would have a material impact on our financial condition or results of operations. Further discussion of these critical accounting estimates and policies is included in the notes to our consolidated financial statements.

Accounting for Regulation

Under U.S. GAAP, SFAS No. 71—“Accounting for the Effects of Certain Types of Regulation” differs in certain respects from the application of GAAP by non-regulated businesses. We are required to recognize regulatory liabilities or regulatory assets on the consolidated financial statements by a corresponding charge or credit to operations to match revenues and expenses under the regulations for the establishment of electric rates. If, as a result of deregulation, we no longer meet the criteria for application of SFAS No. 71, the elimination of the regulatory assets and liabilities is charged or credited to current operations.

Regulatory assets and liabilities are established based on the current regulation and rate-making process. Accordingly, these assets and liabilities may be significantly changed due to the potential future deregulation or changes in the rate-making process. If future recovery of costs ceases to be probable, all or part of the regulatory assets and liabilities would have to be written off against current period earnings. As of December 31, 2008, the consolidated balance sheet included regulatory assets of (Won)610 billion and regulatory liabilities of (Won)1,184 billion. Our management evaluates the anticipated recovery of regulatory assets, liabilities, and revenue subject to refund and provides for allowances and/or reserves as appropriate. As of December 31, 2008, we did not have any allowances or reserves related to regulatory assets.

Derivative Instruments

We record rights and obligations arising from derivative instruments as assets and liabilities, which are stated at fair value. The gains and losses that result from the change in the fair value of derivative instruments are reported in current earnings. However, for derivative instruments designated as hedging, the exposure of variable cash flows, the effective portions of the gains or losses on the hedging instruments are recorded as accumulated other comprehensive income (loss) and credited or charged to operations at the time the hedged transactions affect earnings, and the ineffective portions of the gains or losses are credited or charged immediately to operations.

Decommissioning Costs

We record the fair value of estimated decommissioning costs as a liability in the period in which we incur a legal obligation associated with retirement of long-lived assets that result from acquisition, construction, development and/or normal use of the assets. We also record a corresponding asset that is depreciated over the life of the asset. Accretion expense consists of period-to-period changes in the liability for decommissioning costs resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Depreciation and accretion expenses are included in cost of electric power in the accompanying consolidated statements of income.

 

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The decommissioning cost estimates are based on engineering studies and the expected decommissioning dates of the nuclear power plants. Actual decommissioning costs are expected to vary from these estimates because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment. Based on the above, we believe that the accounting estimate related to decommissioning costs is a critical accounting policy.

Under Korean GAAP, until December 31, 2003, we recorded a liability for the estimated decommissioning costs of nuclear facilities based on engineering studies and the expected decommissioning dates of the nuclear power plant. Additions to the liability were in amounts such that the current costs would be fully accrued for at estimated dates of decommissioning on a straight-line basis.

During 2004, we adopted SKAS No. 17, “Provision and Contingent Liability & Asset.” Under this standard, we record the fair value of the liabilities for decommissioning costs as a liability in the period in which we incur a legal obligation associated with retirement of long-lived assets that result from acquisition, construction, development, and/or normal use of the assets. We would also record a corresponding asset that is depreciated over the life of the asset. Accretion expense consists of period-to-period changes in the liability for decommissioning costs resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Depreciation and accretion expenses are included in cost of electric power in the accompanying consolidated statements of income.

As of December 31, 2006, 2007 and 2008, we recorded a liability of (Won)7,543 billion, (Won)8,206 billion, and (Won)5,471 billion, respectively, as the cost of dismantling and decontaminating existing nuclear power plants. During 2003, we updated our engineering study on the estimated decommissioning costs of our nuclear facilities and applied the amount prospectively. As a result of this change in estimate, the provisioning for decommissioning costs increased by (Won)73 billion in 2003 under Korean GAAP. In addition, during 2004, we updated the 2003 study and estimates for its liability for decommissioning costs based on new engineering studies provided by other third parties. Major revisions made in this study related to increases in dismantling cost per power plant, cask maintenance costs for spent fuel and maintenance cost after closedown of interim storage and operating costs for radioactive wastes. In addition, the 2004 study revised the timing of cash outflows. As required by SKAS No. 17, the change in accounting included the revised factors from the 2004 study, since these factors were our best estimates at the time we elected to adopt SKAS No. 17. With the adoption of SKAS No. 17, we re-measured the liability for decommissioning costs and reflected the cumulative effect of a change in accounting including the effect of the change in estimate up to prior year into the beginning balance of retained earnings. Upon the effectiveness of the Radioactive Waste Management Act (“RWMA”) on January 1, 2009, the date the responsibility of disposal of spent fuel and low and intermediate radioactive waste was transferred to the newly established Korea Radioactive Waste Management Corporation (“KRMC”), a government-controlled entity, and we are required to pay the disposal cost for spent fuel of (Won)3,576 billion to KRMC over 15 years after a grace period of five years, together with interest at 4.36% per annum. This amount will be reclassified as long term accounts payable-other.

Under U.S. GAAP, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. Under this Statement, the fair value of liabilities for an asset retirement obligations for all existing long-lived assets is to be recognized in the period in which they are incurred if a reasonable estimate of fair value can be made. The corresponding amount is capitalized as part of the carrying amount of the long-lived asset and expensed using a systematic and rational method over the asset’s useful life.

In addition, as a result of change in estimate based on an engineering study conducted during 2003, the liability for decommissioning costs and the related net asset increased by (Won)732 billion and (Won)851 billion, respectively, in 2003. As a result of this change in estimate, under U.S. GAAP, net income increased by (Won)119 billion in 2003. In addition, as described above, during 2004 we updated the 2003 study. Under U.S. GAAP, since we already adopted SFAS No. 143 in 2003, the impact from the 2004 study is considered as a change in estimate. As a result of this change in estimate, under U.S. GAAP, the liability for decommissioning costs and

 

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the related net asset decreased by (Won)633 billion and (Won)1,078 billion, respectively, and net income decreased by (Won)455 billion in 2004. As noted above, beginning on January 1, 2009, liability for decommissioning costs for spent fuel and low and intermediate radioactive waste was changed into normal payables to KRMC and the related liability of decommissioning costs was reclassified to payables to KRMC under U.S. GAAP. See Note 21 and 36(j) of the notes to our consolidated financial statements.

Deferred Tax Assets

In assessing the realizability of the deferred tax assets, our management considers whether it is probable that a portion or all of the deferred tax assets will not be realized. The ultimate realization of our deferred tax assets is dependent on whether we are able to generate future taxable income in specific tax jurisdictions during the periods in which temporary differences become deductible. Our management has scheduled the expected future reversals of the temporary differences and projected future taxable income in making this assessment. Based on these factors, our management believes that it is probable that we will realize the benefits of these temporary differences as of December 31, 2008. However, the amount of deferred tax assets may be different if we do not realize estimated future taxable income during the carry forward periods as originally expected.

We recognize deferred tax assets and liabilities based on the differences between the financial statement carrying amounts and the tax bases of assets and liabilities at each separate taxpaying entity. Under Korean GAAP, a deferred tax asset is recognized only when its realization is probable under and an appropriate write-down of a previously recognized deferred tax asset is deducted directly from the deferred tax asset. Under U.S. GAAP, a deferred tax asset is recognized for temporary difference that will result in deductible amounts in future years and for carry forwards and a valuation allowance is recognized, if based on the weight of available evidence, it is more likely than not than some portion or all of the deferred tax asset will not be realized.

We believe that the accounting estimate related to establishing tax valuation allowances is a “critical accounting estimate” because: (1) it requires management to make assessments about the timing of future events, including the probability of expected future taxable income and available tax planning opportunities, and (2) the difference between these assessments and the actual performance could have a material impact on the realization of tax benefits as reported in our results of operations. Management’s assumptions require significant judgment because actual performance has fluctuated in the past and may continue to do so.

Useful Lives of Property, Plant and Equipment

In accordance with Korean GAAP, property, and plant and equipment are stated at cost, except in the case of revaluation made in accordance with the KEPCO Act and the Assets Revaluation Law of Korea. Depreciation is computed by the declining-balance method (straight-line method for buildings, structures, loaded heavy water and capitalized asset retirement cost of nuclear power plants and waste electric transformer, unit-of-production method for loaded nuclear fuel (PWR) and capitalized asset retirement cost of loaded nuclear fuel) using rates based on the estimated useful lives. Net property, plant and equipment as of December 31, 2008, totaled (Won)69,795 billion (US$55,305 million) representing more than 79.1% of total assets. Given the significance of property, plant and equipment and the associated depreciation expense to our financial statements, the determination of an asset’s economic useful life is considered to be a critical accounting estimate.

 

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Economic useful life is the duration of time the asset is expected to be productively employed by us, which may be less than its physical life. Management’s assumptions on the following factors, among others, affect the determination of estimated economic useful life: wear and tear, obsolescence, technical standards, changes in market demand and technological changes. We apply the following useful lives for our property, plant and equipment:

 

     Estimated useful life

Buildings

   8 ~ 40

Structures

   8 ~ 30

Machinery

   5 ~ 16

Vehicles

   4 ~ 5

Loaded heavy water (include in nuclear fuel)

   30

Loaded nuclear fuel

   —  

Capitalized asset retirement cost of nuclear power plants

   30 ~ 40

Capitalized asset retirement cost of waste electric transformer

   8

Capitalized asset retirement costs of loaded nuclear fuel

   —  

Others

   4 ~ 9

Generally, useful life is estimated at the time the asset is acquired and is based on historical experience with similar assets and takes into account anticipated technological or other changes. If technological changes were to occur more rapidly than anticipated or in a different form than anticipated or the assets experienced unexpected levels of wear and tear, the useful lives assigned to these assets may need to be shortened, resulting in the recognition of increased depreciation expenses in future periods.

Impairment of Long-lived Assets

Long-lived assets generally consist of property, plant and equipment and intangible assets. We review the long-lived assets for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying amount of such assets may not be recoverable. The assessment of impairment is a critical accounting estimate, because significant management judgment is required to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset’s estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. If management’s assumptions about these assets change as a result of events or circumstances, and management believes the assets may have declined in value, we may record impairment charges, resulting in lower profits. Our management uses its best estimate in making these evaluations and considers various factors, including the future prices of energy, fuel costs and other operating costs. However, actual market prices and operating costs could vary from those used in the impairment evaluations, and the impact of such variations could be material.

Consolidated Results of Operations

2008 Compared to 2007

In 2008, our consolidated revenues from the sale of electric power, the principal component of our operating revenues, increased by 7.7% to (Won)30,709 billion from (Won)28,501 billion in 2007, reflecting primarily a 4.5% increase in the volume of electricity sold from 368,605 gigawatt hours in 2007 to 385,070 gigawatt hours in 2008, a 4.5% average tariff increase by the Government effective in November 2008 and the government subsidy in the amount of (Won)668 billion received in December 2008. The overall increase in the volume of electricity sold was primarily attributable to a 4.4% increase in the volume of electricity sold to the industrial sector, which represents the largest segment of electricity consumption in Korea, from 194,936 gigawatt hours in 2007 to 203,475 gigawatt hours in 2008, and, to a lesser extent, a 5.6% increase in the volume of electricity sold to the commercial sector from 82,208 gigawatt hours in 2007 to 86,827 gigawatt hours in 2008, and a 2.8% increase in the volume of electricity sold to the residential sector from 75,148 gigawatt hours in 2007 to 77,269 gigawatt

 

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hours in 2008. The increases in the volume of electricity sold to the industrial sector and the commercial sector were primarily due to the increased level of economic activities in Korea, as evidenced by the 2.5% growth in GDP from 2007 to 2008. The increase in the volume of electricity sold to the residential sector was primarily due to an increased use of heaters, air conditions and electrical appliances at home.

Our consolidated operating expenses increased by 30.6% to (Won)34,358 billion in 2008 from (Won)26,316 billion in 2007, primarily due to a 24.0% increase in power generation, transmission, and distribution expenses, which accounted for 78.9% of the total operating expenses in 2008, to (Won)27,102 billion in 2008 from (Won)21,860 billion in 2007. This increase was primarily due to an increase in fuel costs and, to a lesser extent, an increase in depreciation and amortization costs, which was partially offset by a decrease in maintenance costs. Fuel costs increased by 51.3% from (Won)10,391 billion in 2007 to (Won)15,722 billion in 2008. The fuel costs accounted for 47.5% and 58.0% of the power generation, transmission, and distribution expenses in 2007 and 2008, respectively. The increase in fuel costs was primarily due to the increase in the unit fuel costs as well as the devaluation of Won, particularly against the U.S. dollar, which had a particularly adverse impact on the cost of bituminous coal ,whose average unit purchased price per ton increased by 76.8% from (Won)55,519 in 2007 to (Won)98,248 billion in 2008, in line with the general increase in fuel prices worldwide and, to a lesser extent, the increased volume of fuel used due to increased power generation. For further information on the increase in fuel costs, see Item 4. “Information on the Company—Business Overview—Fuel”. Depreciation and amortization costs increased by 5.6% from (Won)5,031 billion in 2007 to (Won)5,315 billion in 2008 mainly due to an increase in newly constructed facilities. Maintenance costs decreased by 26.1% from (Won)2,154 billion in 2007 to (Won)1,593 billion in 2008, primarily a result of efforts to improve cost efficiency in maintenance services. Purchased power, which accounted for 12.9% of the total operating expenses in 2008, increased by 71.6% to (Won)4,434 billion in 2008 from (Won)2,584 billion in 2007, primarily due to an 19.7% increase in the volume of power purchased from 22,636 gigawatt hours in 2007 to 27,106 gigawatt hours in 2008, which resulted mainly from an increase in the aggregate generation capacity of independent power purchasers from 8,000 megawatts as of December 31, 2007 to 8,961 megawatts as of December 31, 2008, and a 42.9% increase in the unit cost of power purchased, which resulted from the general increase in fuel costs.

Our consolidated selling and administrative expenses increased by 8.0% to (Won)1,740 billion in 2008 from (Won)1,610 billion in 2007, primarily due to an increase in labor cost and an increase in sales commissions. Labor cost increased by 12.4% from (Won)580 billion in 2007 to (Won)651 billion in 2008 due to scheduled wage increases and an increase in incentive payments. Sales commissions increased by 6.0% from (Won)363 billion in 2007 to (Won)384 billion in 2008, largely due to an increase in the fees charged for metering services.

As a result of the foregoing, we recorded consolidated operating loss of (Won)2,798 billion in 2008 compared to consolidated operating income of (Won)2,822 billion in 2007. We recorded a consolidated operating loss margin of 8.9% in 2008 compared to a consolidated operating profit margin of 9.7% in 2007, largely due to the 51.3% increase in fuel costs which outpaced the 7.7% increase in our revenue from the sale of electricity.

Our consolidated net non-operating loss significantly increased to (Won)1,046 billion in 2008 from (Won)428 billion in 2007, primarily due to the effect of recording net loss on foreign currency transactions and translation in the amount of (Won)1,845 billion in 2008 compared to net loss on foreign currency transactions and translation in the amount of (Won)145 billion in 2007, which mainly resulted from Won depreciation against U.S. dollar in 2008. This was partially offset by a significant increase in net valuation gain on financial derivatives to (Won)1,342 billion in 2008 from (Won)24 billion in 2007, which resulted primarily from our entering into a significant number of swap contracts to hedge risks from foreign currency movements and interest rate movements related to our foreign currency-denominated debt.

As a result of the foregoing, we recorded consolidated loss before income taxes of (Won)3,844 billion in 2008 compared to consolidated income before income taxes of (Won)2,393 billion in 2007. Accordingly, we recorded consolidated income tax benefit of (Won)930 billion in 2008 compared to consolidated income tax expenses of (Won)926 billion in 2007.

 

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As a cumulative result of the above factors, we recorded consolidated net loss of (Won)2,914 billion in 2008 compared to consolidated net income of (Won)1,467 billion in 2007, and we recorded consolidated net loss margin of 9.2% in 2008 compared to consolidated net income margin of 5.0% in 2007.

2007 Compared to 2006

In 2007, our consolidated revenues from the sale of electric power, the principal component of our operating revenues, increased by 7.2% to (Won)28,501 billion from (Won)26,590 billion in 2006, reflecting primarily a 5.7% increase in the volume of electricity sold from 348,719 gigawatt hours in 2006 to 368,605 gigawatt hours in 2007 and a 2.1% average effective tariff increase by the Government effective in January 2007. The overall increase in the volume of electricity sold was primarily attributable to a 6.5% increase in the volume of electricity sold to the industrial sector, which represents the largest segment of electricity consumption in Korea and includes agricultural usage, from 193,390 gigawatt hours in 2006 to 206,160 gigawatt hours in 2007, and, to a lesser extent, a 5.7% increase in the volume of electricity sold to the commercial sector from 77,809 gigawatt hours in 2006 to 82,208 gigawatt hours in 2007, and a 3.3% increase in the volume of electricity sold to the residential sector from 72,730 gigawatt hours in 2006 to 75,148 gigawatt hours in 2007. The increases in the volume of electricity sold to the industrial sector and the commercial sector were primarily due to the increased level of economic activities in Korea, as evidenced by the 5.0% growth in GDP from 2006 to 2007. The increase in the volume of electricity sold to the residential sector was primarily due to an unusually hot summer which required a greater use of air conditioning and a continuing trend toward living in high-rise apartment buildings, which generally consumes greater electricity per person. The tariff increase, which became effective in January 2007, involved a 4.2% increase in the average effective rate for the industrial sector, with no further rate changes for the commercial or residential sectors.

Our consolidated operating expenses increased by 9.6% to (Won)26,316 billion in 2007 from (Won)24,014 billion in 2006, primarily due to a 9.4% increase in power generation, transmission, and distribution expenses, which accounted for 83.1% of the total operating expenses in 2007, to (Won)21,860 billion in 2007 from (Won)19,985 billion in 2006. This increase was primarily due to a 16.3% increase in fuel costs from (Won)8,938 billion in 2006 to (Won)10,391 billion in 2007, and to a lesser extent, a 5.8% increase in maintenance costs from (Won)2,036 billion in 2006 to (Won)2,154 billion in 2007. The fuel costs accounted for 44.7% and 47.5% of the power generation, transmission, and distribution expenses in 2006 and 2007, respectively. The increase in fuel costs was primarily due to the increase in the unit fuel costs, particularly bituminous coal whose average contracted price per ton increased by 13.5% from (Won)48,923 in 2006 to (Won)55,519 in 2007, in line with the general increase in fuel prices worldwide as well as the increased volume of fuel used due to increased power generation. For further information on the increase in fuel costs from 2006 to 2007, see Item 4. “Information on the Company—Business Overview—Fuel.” The increase in maintenance costs was primarily a result of an increase in the maintenance periods of our power facilities primarily due to the ageing of our generation plants. Purchased power, which accounted for 9.8% of the total operating expenses in 2007, increased by 24.6% to (Won)2,584 billion in 2007 from (Won)2,073 billion in 2006, primarily due to the increase of unit fuel costs as well as a 5.7% increase in demand for electricity.

Our consolidated selling and administrative expenses increased by 2.2% to (Won)1,610 billion in 2007 from (Won)1,576 billion in 2006, primarily due to an increase in labor cost due to increased hiring and the annual wage increase and an increase in depreciation and amortization expenses primarily arising from an increase in acquisition of intangible assets arising from the installation of an enterprise resource planning system.

As a result of the foregoing, our consolidated operating income for 2007 decreased by 16.9% to (Won)2,822 billion in 2007 from (Won)3,395 billion in 2006. Our operating margin decreased from 12.4% in 2006 to 9.7% in 2007, largely due to the 16.3% increase in fuel costs which outpaced the 7.2% increase in our revenue from the sale of electricity.

Our consolidated net non-operating loss significantly increased to (Won)428 billion in 2007 from (Won)26 billion in 2006, primarily due to the effect of recording net loss on foreign currency transactions and translation in the amount of (Won)145 billion in 2007 compared to net gain on foreign currency transactions and translation in the

 

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amount of (Won)417 billion in 2006, which mainly resulted from Won depreciation against U.S. dollar in 2007. This was partially offset by a 49.4% increase in net equity income of affiliates to (Won)120 billion in 2007 from (Won)80 billion in 2006, which was mainly due to the increases in net income of our affiliates, such as Korea Gas Corporation and LG Powercom Corporation, and the effect of recording a net valuation gain on financial derivatives in the amount of (Won)24 billion in 2007 as compared to a net valuation loss on financial derivatives in the amount of (Won)173 billion in 2006, which resulted primarily from our entering into a significant number of swap contracts to hedge risks involving foreign currency and interest rate of foreign currency debts.

Our consolidated income tax expenses decreased to (Won)926 billion in 2007 from (Won)1,123 billion in 2006, due primarily to a decrease in income before income taxes. However, our effective tax rate increased to 38.70% in 2007 from 33.34% in 2006, primarily due to a decrease in tax benefit as a result of a decrease in dividend income from our affiliates and an increase in equity income of our affiliates.

As a cumulative result of the above factors, our consolidated net income decreased by 34.7% to (Won)1,467 billion in 2007 from (Won)2,246 billion in 2006, and our consolidated net income margin decreased from 8.2% in 2006 to 5.0% in 2007.

Segment Results

We operate the following business segments: transmission and distribution, power generation and all other. The transmission and distribution segment, which is operated by KEPCO, the parent company, consists of operations related to the transmission, distribution and sale to end-users of electricity purchased from our generation subsidiaries as well as from independent power producers. The power generation segment, which is operated by KEPCO’s six generation subsidiaries, consists of operations related to the generation of electricity sold to KEPCO through the Korea Power Exchange. The transmission and distribution segment and the power generation segment together represent our electricity business. The remainder of our operation is categorized as “all other”. The all other segment consists primarily of operations related to the engineering and maintenance of generation plants, information services, sales of nuclear fuel, communication line leasing and others. In 2007 and 2008, the unaffiliated revenues of the power generation segment (representing the six generation subsidiaries) and all our other revenues in the aggregate amounted to only 1.83% and 1.85% of our consolidated revenues, respectively, and the results of operations for our business segments substantially mirror our consolidated results of operations.

LIQUIDITY AND CAPITAL RESOURCES

We expect that our capital requirements, capital resources and liquidity position may change in the course of implementing the Restructuring Plan. See Item 4. “Information on the CompanyBusiness OverviewRestructuring of the Electricity Industry in Korea” and Item 3. “Key InformationRisk FactorsRisks Relating to KEPCOThe Government’s plan for restructuring the electricity industry in Korea may have a material adverse effect on us.”

Capital Requirements

We have traditionally met our working capital and other capital requirements primarily from net cash provided by operating activities, sales of debt securities, borrowings from financial institutions and construction grants. Net cash provided by operating activities was (Won)7,802 billion in 2006, (Won)6,984 billion in 2007 and (Won)1,961 billion (US$1,554 million) in 2008. Total long-term debt as of December 31, 2008 (including the current portion and discount on debentures on and excluding premium on debentures) was (Won)27,902 billion (US$22,110 million), of which (Won)19,707 billion (US$15,616 million) was denominated in Won and an equivalent of (Won)8,195 billion (US$6,494 million) was denominated in foreign currencies, primarily U.S. dollars. Construction grants received were (Won)797 billion in 2006, (Won)1,032 billion in 2007 and (Won)1,142 billion (US$905 million) in 2008.

 

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The implementation of the Restructuring Plan and changes in the economic environment may result in a material change in our capital investment program. However, our working capital and other capital requirements (including those of our generation subsidiaries) may continue to increase. The capital investment program contemplates the construction of a large number of generation units and a significant expansion of our transmission and distribution systems. The construction of new generation units requires significant investments over extended periods before commencement of operations. In addition, the overseas investment that we have been pursuing may require substantial investment.

We anticipate that capital expenditures will be the most significant use of our funds for the next several years. Our total capital expenditures were (Won)7.5 trillion in 2006, (Won)8.5 trillion in 2007 and (Won)8.9 trillion in 2008 and under current plans, are estimated to be approximately (Won)12.4 trillion in 2009 and approximately (Won)13.7 trillion in 2010.

In addition to funding requirements relating to our capital investment program, payments of principal and interest on indebtedness will require considerable resources. The scheduled maturities of our outstanding debt as of December 31, 2008 for each year from 2009 to 2013 and thereafter are set forth in the table below:

 

Year ended

December 31

   Local
currency
borrowings
   Foreign
currency
borrowings
   Domestic
Debentures
   Foreign
debentures
   Exchangeable
bonds
   Total
     (in millions of Won)

2009

   2,201,430    52,390    2,190,000    1,498    —      4,445,318

2010

   1,809,947    79,026    2,550,000    1,030,888    —      5,469,861

2011

   1,110,720    83,370    2,990,000    1,396,204    1,040,796    6,621,090

2012

   286,734    83,370    2,330,010    378,370    —      3,078,484

2013

   125,110    88,260    1,960,000    1,824,304    —      3,997,674

Thereafter

   93,642    204,064    2,060,000    1,932,060    —      4,289,766
                             
   5,627,583    590,480    14,080,010    6,563,324    1,040,796    27,902,193
                             

We have incurred interest charges (including capitalized interest) of (Won)1,191 billion in 2006, (Won)977 billion in 2007 and (Won)1,311 billion (US$774 million) in 2008. We anticipate that interest charges will increase in future years because of, among other factors, anticipated increases in our long-term debt. See “—Capital Resources” below. The weighted average rate of interest on our debt was 5.17 % in 2006, 4.85% in 2007 and 5.47% in 2008.

In June 2005, the Government announced its policy to relocate the headquarters of government-invested enterprises, including us and certain of our subsidiaries including six generation subsidiaries, out of the Seoul metropolitan area to other provinces in Korea by the end of 2012. Pursuant to this policy, our headquarters are scheduled to be relocated to Naju in Jeolla Province, which is approximately 300 kilometers south of Seoul, by the end of 2012. In addition, the headquarters of certain of our subsidiaries are scheduled to be relocated to various other cities in Korea. On December 14, 2007, the Government approved our headquarter relocation plan, including the scale and the target year of the relocation. According to this plan, prepared in accordance with the special law and the related guidelines, the currently estimated total relocation cost is (Won)417.5 billion, including (Won)397.3 billion as costs of building the new headquarters building as well as (Won)20.2 billion of moving costs for our headquarters and employees. Based on the Special Act on Construction and Support of Innovation Cities Regarding the Relocation of Public Agencies Outside the Capital and related guidelines, we are required to sell the building and land for our current headquarters in Samsung-dong by the end of 2012.

We paid dividends on our common stock of (Won)738 billion in 2006, (Won)642 billion in 2007 and (Won)492 billion (US$390 million) in 2008. Currently, we have no plans to pay dividends in 2009 from our operations for 2008.

 

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Capital Resources

In order to meet our future working capital and other capital requirements, we intend to continue to rely primarily upon net cash provided by operating activities, sales of debt securities, borrowings from financial institutions and construction grants. As of December 31, 2008, our long-term debt, excluding the current portion thereof, as a percentage of shareholders’ equity was 56.5%. We incurred (Won)4,918 billion of long-term debt in 2006, (Won)5,198 billion in 2007 and (Won)9,890 billion (US$7,837 million) in 2008. As of December 31, 2008, the current portion of long-term debt was (Won)4,445 billion (US$3,522 million) as compared to (Won)4,670 billion as of December 31, 2007. As of December 31, 2008, we had (Won)1,358 billion (US$1,076 million) of short-term borrowings as compared to (Won)820 billion as of December 31, 2007. See Note 17 of the notes to our consolidated financial statements. In addition, in anticipation of potential liquidity shortage, we maintain several credit facilities with domestic financial institutions amounting to (Won)1,451 billion and US$ 110 million, the full amount of which was available as of December 31, 2008. In addition, in September 2008, we have established a global medium-term notes program up to an aggregate amount of US$1 billion, which may be drawn down wholly or in part, depending on the market conditions.

Subject to the implementation of our capital expenditure plan and the sale of our interests in our generation subsidiaries and other subsidiaries, our long-term debt may increase or decrease in future years. Until recently, a substantial portion of our long-term debt was raised through foreign currency borrowings. However, in order to reduce the impact of foreign exchange rate fluctuations on our results of operations, we have reduced the proportion of our debt which is denominated in foreign currencies and plan to adjust the proportion of foreign currency debt in order to optimize our foreign currency exposure in light of, among others, the fluctuations in the value of Won, the cost of funding by each currency and the maturity of fund available in each market. Our foreign currency-denominated long-term debt increased to (Won)8,195 billion (US$6,493 million) as of December 31, 2008 from (Won)5,667 billion as of December 31, 2007.

Our ability to incur long-term debt in the future is subject to a variety of factors, many of which are beyond our control, including, among others, the implementation of the Restructuring Plan and the amount of capital that other Korean entities may seek to raise in capital markets. Economic, political and other conditions in Korea may also affect investor demand for our securities and those of other Korean entities. In addition, our ability to incur debt will also be affected by the Government’s policies relating to foreign currency borrowings, the liquidity of the Korean capital markets and our operating results and financial condition. In case of adverse developments in Korea, however, the price at which such financing may be available may not be acceptable to us.

We may raise capital from time to time through the issuance of equity securities. However, there are certain restrictions on our ability to issue equity, including limitations on shareholdings by foreigners. In addition, without changes in the existing KEPCO Act which requires that the Government, directly or pursuant to the Korea Development Bank Act, through Korea Development Bank, own at least 51% of our capital stock, it may be difficult or impossible for us to undertake any equity financing other than sales of treasury stock without the participation of the Government. In case of adverse economic developments in Korea, however, the share price at which such financing may be available may not be acceptable to us. See Item 3. “Key Information—Risk Factors—Risks Relating to Korea and the Global Economy—Adverse developments in Korea may adversely affect us.”

Our total stockholders’ equity decreased from (Won)44,267 billion as of December 31, 2007 to (Won)41,275 billion (US$32,706 million) as of December 31, 2008.

Liquidity

Substantially all of our revenues are denominated in Won. However, as of December 31, 2008, 29.4% of our long-term debt (including the current portion thereof) was denominated in currencies other than Won. We have incurred such foreign currency debt in the past principally due to the limited availability and the high cost of

 

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Won-denominated financing in the Republic. Although we intend to continue to raise certain amounts of capital through long-term foreign currency debt, we have recently been reducing, and plan to continue to reduce, the portion of our debt which is denominated in foreign currencies.

We enter into currency swaps and other hedging arrangements with respect to our debt denominated in foreign currencies only to a limited extent due primarily to the limited size of the Korean market for such derivative arrangements. Such instruments include combined currency and interest rate swap agreements, interest rate swaps and foreign exchange agreements. We do not enter into derivative financial instruments in order to hedge market risk resulting from fluctuations in fuel costs. Our policy is to hold or issue derivative financial instruments for hedging purposes only. Our derivative financial instruments are entered into with major financial institutions, thereby minimizing the risk of credit loss. See Note 24 of the notes to our consolidated financial statements. Due to the considerable amount of our long-term debt denominated in foreign currencies, changes in foreign currency exchange rates significantly affect our liquidity because of the effect of such changes on the amount of funds required for us to make interest and principal payments on foreign currency-denominated debt. In order to hedge against foreign currency fluctuation risks, we generally enter into foreign currency swap agreements. 10.4% of our long-term debt, after accounting for swap transactions, was denominated in foreign currency as of December 31, 2008.

In addition to the impact of foreign exchange rates on us arising from foreign currency-denominated borrowings, fluctuations in foreign exchange rates may also affect our liquidity as we obtain substantially all of our fuel materials, other than anthracite coal, directly or indirectly from sources outside Korea and the prices for such fuel materials are based on prices stated in, and in many cases are paid for in, currencies other than Won.

Our liquidity is also substantially affected by our construction expenditures and fuel purchases. Construction in progress increased from (Won)9,824 billion as of December 31, 2007 to (Won)10,178 billion (US$8,065 million) as of December 31, 2008. Fuel costs represented 36.5% and 51.2% of revenues from sale of electric power in 2007 and 2008, respectively.

We had a working capital deficit (working capital being defined as current assets minus current liabilities) of (Won)197 billion (US$156 million) as of December 31, 2008, compared to a working capital deficit of (Won)3 billion as of December 31, 2007, mainly due to a decrease in cash and cash equivalents as well as an increase in the current trade payables. Due to the capital-intensive nature of our business, we have traditionally operated with a working capital deficit, and we may have substantial working capital deficit in the future. In order to meet capital requirements related to working capital deficit, we intend to continue to rely primarily upon net cash provided by operating activities, sales of debt securities, borrowings from financial institutions and construction grants. See “—Capital Resources”.

During 2007 and 2008, we declared and paid dividends of (Won)621 billion and (Won)467 billion related to income earned in 2006 and 2007, respectively. In 2009, no dividend has been or is expected to be paid as we recorded net loss in 2008.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements as of December 31, 2008.

 

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Contractual Obligations and Commercial Commitments

The following summarizes certain of our contractual obligations as of December 31, 2008 and the effect such obligations are expected to have on liquidity and cash flow in future periods.

 

     Payments Due by Period

Contractual Obligations(1)

   Total    Less than
1 year
   1–3 years    4–5 years    After
5 years
     (in billions of Won)

Long-term debt(2)

   (Won) 27,902    (Won) 4,445    (Won) 12,091    (Won) 7,076    (Won) 4,290

Interest payments on long-term debt(3)

     6,900      1,360      1,899      1,001      2,640

Short-term borrowings

     1,358      1,358      —        —        —  

Plant construction(4)

     55,257      7,798      17,843      20,583      9,033

Accrual for retirement and severance benefits(5)

     1,433      58      171      235      969
                                  

Total

   (Won) 92,850    (Won) 15,019    (Won) 32,004    (Won) 28,895    (Won) 16,932
                                  

 

Notes:

 

(1) We entered into capital lease agreements with Korea Development Leasing Corporation and others for certain computer systems. We believe the remaining annual payments under capital and operating lease agreements as of December 31, 2008 were immaterial.
(2) Includes the current portion and excludes amortization of note discount and issue costs.
(3) As of December 31, 2008, a portion of our long-term debt carried a variable rate of interest. We used the interest rate in effect as of December 31, 2008 for the variable rate of interest in calculating the interest payments on long-term debt for the periods indicated.
(4) Based on budgeted amounts of capital expenditure for the construction of generation through 2014. The budgeted amounts may differ from the actual amounts of expenditure.
(5) Represents, as of December 31, 2008, the amount of the severance and retirement benefits which we will be required under applicable Korean laws to pay to all of our employees when they reach their normal retirement age.

For a description of our commercial commitments and contingent liabilities, see Note 32 of the notes to our consolidated financial statements.

We entered into a power purchasing agreement with GS EPS Co., Ltd. and other independent power producers, under which and in accordance with the Electricity Business Act of Korea we are required to purchase a minimum amount of power from these companies. Power we purchased from these companies amounted to (Won)1,299 billion, (Won)1,487 billion and (Won)2,228 billion for the years ended December 31, 2006, 2007 and 2008, respectively.

We have entered into contracts with domestic and foreign suppliers (including Korea Gas Corporation, a related party) to purchase bituminous coal, anthracite coal and LNG. These contracts generally have terms of three months to one year and provide for periodic price adjustments to then-market prices. Under most of the coal purchase contracts, we are required to purchase an annual quantity of coal. See Note 32 of the notes to our consolidated financial statements for further details of these contracts. We have also entered into long-term transportation contracts with Hanjin Shipping Co., Ltd. and others.

We import all uranium ore concentrates from sources outside Korea (including the United States, United Kingdom, Kazakhstan, France, Russia, South Africa, Canada and Australia) through medium- to long-term contracts and pay for such concentrates with currencies other than Won, primarily U.S. dollars. Contract prices for processing of uranium are generally based on market prices. See Note 32 of the notes to our consolidated financial statements for further details of these contracts.

 

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Under the Long-term Transmission and substation plan approved by the Ministry of Knowledge Economy, which took effect on March 13, 2009, we are liable for the construction of all of our power transmission facilities and the maintenance and repair expenses for such facilities.

In July 2005, nine government-invested utilities companies, including us, entered into the Renewable Portfolio Agreement with the Government in order to expand the generation and distribution of renewable energy. This agreement contemplates two phases of capacity build-up for the generation and distribution of renewable energy. During Phase I, which lasted from 2006 to 2008, we and our generation subsidiaries made capital expenditures of (Won)520.1 billion to construct renewable energy generation capacity of 289 megawatts. During Phase II, which is expected to last from 2009 to 2011, we and our generation subsidiaries are scheduled to make capital expenditures of (Won)1,968.0 billion to construct renewable energy generation capacity of 811 megawatts.

The breakdown of capital expenditures for Phase I and Phase II under the Renewable Portfolio Agreement by type of expenditure is as follows:

 

     Phase I (2006 – 2008)    Phase II (2009 – 2011)
     (in billions of Won)

Facilities investment

   (Won) 380.0    (Won) 1,864.3

Research and development

     127.6      93.0

Promotion and other

     12.5      10.7
             

Total

   (Won) 520.1    (Won) 1,968.0
             

Payment guarantee and short-term credit facilities from financial institutions as of December 31, 2008 were as follows:

Payment guarantee

 

Description

   Financial Institutions    Credit Lines
          (In millions of Won or
thousands of US$, SAR)

Payment of import letter of credits

   Korea Exchange Bank and others    US$  1,000,481

Payment of customs duties

   Korea Exchange Bank and others    (Won) 12,660

Inclusive credits

   Kookmin Bank and others    (Won) 8,000

Borrowings

   Woori Bank and others    US$

(Won)

75,000

324,000

Performance guarantees

   Korea Exchange Bank and others    US$ 225,872

Payment of foreign currency

   Korea Exchange Bank    (Won) 50,000
   Shinhan Bank and others    US$ 43,633
   Export-Import Bank of Korea    SAR  25,000

Overdraft and Others

 

Description

  

Financial Institutions

   Credit Lines
          (In millions of Won or
thousands of US$, JPY)

Overdraft

   Korea Exchange Bank and others    (Won) 725,000

Commercial paper

   Korea Exchange Bank and others    (Won)

US$

645,000

110,000

Trade financing

   National Agricultural Cooperative Federation and others    (Won) 81,000

Repayment guarantees for foreign currency debentures

   Korea Development Bank    US$ 686,757