20-F 1 d111421d20f.htm FORM 20-F Form 20-F
Table of Contents

As filed with the Securities and Exchange Commission on April 30, 2021

 

 

 

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

 

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

For the fiscal year ended December 31, 2020

OR

 

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

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)

 

 

55 Jeollyeok-ro, Naju-si, Jeollanam-do, 58322, Korea

(Address of principal executive offices)

 

 

Yoonjue Lee, +82 61 345 4213, yoonjue.lee@kepco.co.kr, +82 61 345 4299

55 Jeollyeok-ro, Naju-si, Jeollanam-do, 58322, Korea

(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:

 

Trading Symbol(s):

 

Name of each exchange on which registered:

Common stock, par value Won 5,000 per share   KEP   New York Stock Exchange*

American depositary shares, each representing

one-half of share of common stock

 

KEP

  New York Stock Exchange  

 

*

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.

 

 

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:

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

634% 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 period

covered by the annual report:

641,964,077 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  ☑    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  ☑

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  ☑    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files):    Yes  ☑    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑                    Accelerated filer ☐                     Non-accelerated filer ☐                     Emerging Growth Company  ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☑

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  ☐

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  ☐

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  ☑

(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  ☐

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  

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  
  Item 3.A.    Selected Financial Data      2  
  Item 3.B.    Capitalization and Indebtedness      4  
  Item 3.C.    Reasons for the Offer and Use of Proceeds      4  
  Item 3.D.    Risk Factors      4  

ITEM 4.

  INFORMATION ON THE COMPANY      34  
  Item 4.A.    History and Development of the Company      34  
  Item 4.B.    Business Overview      35  
  Item 4.C.    Organizational Structure      89  
  Item 4.D.    Property, Plant and Equipment      95  

ITEM 4A.

  UNRESOLVED STAFF COMMENTS      95  

ITEM 5.

  OPERATING AND FINANCIAL REVIEW AND PROSPECTS      95  
  Item 5.A.    Operating Results      96  
  Item 5.B.    Liquidity and Capital Resources      112  
  Item 5.C.    Research and Development, Patents and Licenses, etc.      117  
  Item 5.D.    Trend Information      118  
  Item 5.E.    Off-Balance Sheet Arrangements      118  
  Item 5.F.    Tabular Disclosure of Contractual Obligations      118  
  Item 5.G.    Safe Harbor      128  

ITEM 6.

  DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES      128  
  Item 6.A.    Directors and Senior Management      128  
  Item 6.B.    Compensation      133  
  Item 6.C.    Board Practices      133  
  Item 6.D.    Employees      134  
  Item 6.E.    Share Ownership      135  

ITEM 7.

  MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS      135  
  Item 7.A.    Major Shareholders      135  
  Item 7.B.    Related Party Transactions      135  
  Item 7.C.    Interests of Experts and Counsel      136  

ITEM 8.

  FINANCIAL INFORMATION      136  
  Item 8.A.    Consolidated Statements and Other Financial Information      136  
  Item 8.B.    Significant Changes      139  

ITEM 9.

  THE OFFER AND LISTING      139  
  Item 9.A.    Offer and Listing Details      139  
  Item 9.B.    Plan of Distribution      141  
  Item 9.C.    Markets      141  
  Item 9.D.    Selling Shareholders      144  
  Item 9.E.    Dilution      144  
  Item 9.F.    Expenses of the Issue      144  

ITEM 10.

  ADDITIONAL INFORMATION      144  
  Item 10.A.    Share Capital      144  
  Item 10.B.    Memorandum and Articles of Incorporation      145  
  Item 10.C.    Material Contracts      152  
  Item 10.D.    Exchange Controls      152  
  Item 10.E.    Taxation      157  
  Item 10.F.    Dividends and Paying Agents      169  

 

i


Table of Contents
         Page  
  Item 10.G.    Statements by Experts      169  
  Item 10.H.    Documents on Display      169  
  Item 10.I.    Subsidiary Information      169  

ITEM 11.

  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      169  

ITEM 12.

  DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES      174  
  Item 12.A.    Debt Securities      174  
  Item 12.B.    Warrants and Rights      174  
  Item 12.C.    Other Securities      175  
  Item 12.D.    American Depositary Shares      175  

PART II

     177  

ITEM 13.

  DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES      177  

ITEM 14.

  MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS      177  

ITEM 15.

  CONTROLS AND PROCEDURES      177  

ITEM 16.

  [RESERVED]         178  

ITEM 16.A.

 

AUDIT COMMITTEE FINANCIAL EXPERT

     178  

ITEM 16.B.

 

CODE OF ETHICS

     178  

ITEM 16.C.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

     178  

ITEM 16.D.

 

EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE

     179  

ITEM 16.E.

 

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

     179  

ITEM 16.F.

 

CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

     179  

ITEM 16.G.

 

CORPORATE GOVERNANCE

     179  

ITEM 16.H.

 

MINE SAFETY DISCLOSURE

     187  

PART III

     188  

ITEM 17.

 

FINANCIAL STATEMENTS

     188  

ITEM 18.

 

FINANCIAL STATEMENTS

     188  

ITEM 19.

 

EXHIBITS

     188  

INDEX OF EXHIBITS

     190  

INDEX TO FINANCIAL STATEMENTS

     F-1  

 

ii


Table of Contents

CERTAIN DEFINED TERMS AND CONVENTIONS

All references to “Korea” or the “Republic” in this annual report on Form 20-F, or this annual report, are references to the Republic of Korea. All references to the “Government” in this annual report are references to the government of the Republic. All references to “we,” “us,” “our,” “ours,” the “Company” or “KEPCO” in this annual report are references to Korea Electric Power Corporation and, as the context may require, its subsidiaries, and the possessive thereof, as applicable. All references to “the Ministry of Trade, Industry and Energy” and “the Ministry of Economy 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 “IFRS” in this annual report are references to the International Financial Reporting Standards as issued by the International Accounting Standard Board. Unless otherwise stated, all of our financial information presented in this annual report has been prepared on a consolidated basis and in accordance with IFRS.

In addition, in this annual report, all references to:

 

   

“EWP” are to Korea East-West Power Co., Ltd.,

 

   

“KHNP” are to Korea Hydro & Nuclear Power Co., Ltd.,

 

   

“KOMIPO” are to Korea Midland Power Co., Ltd.,

 

   

“KOSEP” are to Korea South-East Power Co., Ltd.,

 

   

“KOSPO” are to Korea Southern Power Co., Ltd., and

 

   

“KOWEPO” are to Korea Western Power Co., Ltd.,

each of which is our wholly-owned generation subsidiary.

FORWARD-LOOKING STATEMENTS

This annual report includes “forward-looking statements” (as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934), including statements regarding our expectations and projections for future operating performance and business prospects. The words “believe,” “expect,” “anticipate,” “estimate,” “project” and similar words used in connection with any discussion of our future operation or financial performance identify forward-looking statements. In addition, all statements other than statements of historical facts included in this annual 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 annual report.

This annual report discloses, under the caption Item 3.D. “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.

 

1


Table of Contents

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

 

Item 3.A.

Selected Financial Data

The selected consolidated financial data set forth below as of and for the years ended December 31, 2016, 2017, 2018, 2019 and 2020 have been derived from our audited consolidated financial statements which have been prepared in accordance with IFRS.

You should read the following data with the more detailed information contained in Item 5. “Operating and Financial Review and Prospects” and our consolidated financial statements included in Item 18. “Financial Statements.” Historical results do not necessarily predict future results.

Consolidated Statement of Comprehensive Income (Loss) Data

 

     2016     2017     2018     2019     2020     2020  
     (rounded to billions of Won and millions of US$, except per share data)(1)  

Sales

   59,763     59,336     60,033     58,568     57,926     $ 53,334  

Cost of sales

     45,550       52,099       58,208       57,780       51,805       47,698  

Gross profit

     14,213       7,237       1,825       788       6,121       5,636  

Selling and administrative expenses

     2,639       2,763       2,628       2,670       2,678       2,466  

Other income (expenses), net

     652       689       739       756       619       570  

Other gains (losses), net

     70       157       (621     (582     35       32  

Operating profit (loss)

     12,296       5,320       (685     (1,708     4,097       3,772  

Finance income (expenses), net

     (1,646     (1,596     (1,674     (1,772     (1,386     (1,276

Profit (loss) before income tax

     10,513       3,614       (2,001     (3,266     2,992       2,755  

Income tax benefit (expense)

     (3,365     (2,173     826       1,002       (899     (828

Profit (loss) for the period

     7,148       1,441       (1,175     (2,264     2,093       1,927  

Other comprehensive income (loss)

     (2     (95     (107     135       (220     (203

Total comprehensive income (loss)

     7,146       1,346       (1,282     (2,128     1,873       1,724  

Profit (loss) attributable to:

            

Owners of the Company

     7,048       1,299       (1,315     (2,346     1,992       1,834  

Non-controlling interests

     100       142       140       82       101       93  

Total comprehensive income (loss) attributable to:

            

Owners of the Company

     7,042       1,230       (1,426     (2,239     1,803       1,660  

Non-controlling interests

     104       116       144       111       70       64  

Earnings (loss) per share

            

Basic(2)

     10,980       2,023       (2,048     (3,654     3,102       2.86  

Earnings (loss) per ADS

            

Basic(2)

     5,490       1,012       (1,024     (1,827     1,551       1.46  

Dividends per share

     1,980       790       —         —         1,216       1.12  

 

2


Table of Contents

Consolidated Statements of Financial Position Data

 

    As of December 31,  
    2016     2017     2018     2019     2020     2020  
    (rounded to billions of Won and millions of US$, except share data)(1)  

Net working capital (deficit)(3)

    ₩ (5,031)       ₩ (4,283)       ₩ (2,096)       ₩ (4,749)       ₩ (5,319)       $ (4,897)  

Property, plant and equipment, net

    145,743       150,882       152,743       164,702       168,709       155,335  

Total assets

    177,837       181,789       185,249       197,598       203,142       187,038  

Total shareholders’ equity

    73,051       72,965       71,093       68,890       70,667       65,065  

Equity attributable to owners of the Company

    71,724       71,682       69,744       67,496       69,297       63,804  

Non-controlling interests

    1,327       1,283       1,349       1,393       1,370       1,261  

Share capital

    3,210       3,210       3,210       3,210       3,210       2,956  

Number of common shares as adjusted to reflect any changes in capital stock

    641,964,077       641,964,077       641,964,077       641,964,077       641,964,077       641,964,077  

Long-term debt (excluding current portion)(4)

    44,700       45,624       53,073       59,019       59,050       54,369  

Other long term liabilities(5)

    35,347       39,776       39,242       45,457       47,544       43,775  

 

Notes:

 

(1)

The financial information denominated in Won as of and for the year ended December 31, 2020 has been translated into U.S. dollars at the exchange rate of Won 1,086.1 to US$1.00, which was the Noon Buying Rate as of December 31, 2020.

(2)

Basic earnings (loss) per share are calculated by dividing net income available to holders of our common shares by the weighted average number of common shares issued and outstanding for the relevant period. Basic earnings (loss) per ADS have been computed as if all of our issued and outstanding common shares are represented by ADSs during each of the years presented. Each ADS represents one-half of our common share. Dilutive earnings (loss) per share were the same as basic earnings (loss) per share for the years ended December 31, 2016 through 2020 since there were no potential dilutive instruments.

(3)

Net working capital is defined as current assets minus current liabilities. For the periods indicated, current liabilities exceeded current assets, which resulted in working capital deficit for such periods.

(4)

Long-term debt, net consists of long-term borrowings and debt securities (excluding the current portions but including original issue discounts and premiums) without taking into consideration of swap transactions.

(5)

Other long-term liabilities consist of total non-current liabilities of our consolidated financial statements included in this annual report minus long-term debt (excluding current portion) of this table.

Currency Translations and Exchange Rates

In this annual report, unless otherwise indicated, all references to “Won,” “KRW” or “₩” are to the currency of Korea, all references to “U.S. dollars,” “Dollars,” “USD”, “$” or “US$” are to the currency of the United States of America; all references to “Euro”, “€” or “EUR” are references to the currency of the European Union; all references to “Yen”, “¥” or “JPY” are references to the currency of Japan; all references to “A$” or “AUD” are to the currency of Australia; and all references to “RMB” are to the currency of the People’s Republic of China. Unless otherwise indicated, all translations from Won to U.S. dollars were made at Won 1,086.1 to US$1.00, which was the Noon Buying Rate of the Federal Reserve Board (the “Noon Buying Rate”) in effect as of December 31, 2020, which rates are available on the H.10 statistical release of the Federal Reserve Board. On April 16, 2021, the Noon Buying Rate was Won 1,114.9 to US$1.00. The exchange rate between the U.S. dollar and Korean Won may be highly volatile from time to time and no representation is made that the Won or U.S. dollar amounts referred to in this annual 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.

 

3


Table of Contents

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)  

2016

     1,203.7        1,160.5        1,242.6        1,090.0  

2017

     1,067.4        1,141.6        1,207.2        1,067.4  

2018

     1,112.9        1,099.3        1,141.7        1,054.6  

2019

     1,155.5        1,165.8        1,220.7        1,111.8  

2020

     1,086.1        1,180.6        1,267.3        1,081.9  

October

     1,134.0        1,143.8        1,166.1        1,127.8  

November

     1,105.8        1,116.1        1,137.4        1,105.3  

December

     1,086.1        1,093.8        1,107.3        1,081.9  

2021 (through April 16)

     1,114.9        1,115.9        1,140.6        1,081.6  

January

     1,118.4        1,098.2        1,118.4        1,081.6  

February

     1,123.4        1,111.8        1,123.7        1,099.6  

March

     1,126.7        1,130.3        1,140.6        1,118.6  

April (through April 16)

     1,114.9        1,121.2        1,131.6        1,114.9  

 

Source: Federal Reserve Board

Note:

 

(1)

The average rates for annual and interim periods were calculated by taking the simple average of the Noon Buying Rates on the last day of each month during the relevant period. The average rates for the monthly periods (or a portion thereof) were calculated by taking the simple average of the daily Noon Buying Rates during the relevant month (or a portion thereof).

 

Item 3.B.

Capitalization and Indebtedness

Not Applicable.

 

Item 3.C.

Reasons for the Offer and Use of Proceeds

Not Applicable.

 

Item 3.D.

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. Such risks fall primarily under the categories below:

Risks relating to KEPCO primarily include:

 

   

increases in fuel prices which may not be passed on to customers;

 

   

Governmental policies that may affect the industry or our operations;

 

   

capacity expansion plans based on projections of long-term supply and demand of electricity proving to be inadequate against actual supply and demand;

 

   

being subject to various environmental legislations, regulations and government initiatives;

 

   

incurrence of additional indebtedness;

 

   

the movement of Won against other currencies;

 

4


Table of Contents
   

risks associated with new business strategies and overseas expansion opportunities;

 

   

an increase in electricity generated by and/or sourced from independent power producers eroding our market position;

 

   

labor unrest and increases in labor cost;

 

   

risks associated with the operation of nuclear power generation facilities;

 

   

opposition from civic groups in respect of the construction and operation of our facilities;

 

   

risk management policies and procedures failing to be effective, including but not limited to failing to prevent losses in our debt and foreign currency positions;

 

   

limited amount and scope of insurance coverage;

 

   

inability to raise equity capital without the Government’s participation;

 

   

claims by current or previous employees for unpaid wages;

 

   

cyberattacks;

 

   

previous or current engagements in Iran and Russia; and

 

   

the effects of COVID-19.

Risks relating to Korea and Global Economy primarily include:

 

   

unfavorable financial and economic conditions in Korea;

 

   

tensions with North Korea;

 

   

being subject to Korean corporate governance and disclosure standards; and

 

   

risks associated with enforcing a foreign judgment against us.

Risks relating to Our American Depositary Shares (ADSs) primarily include:

 

   

restrictions on withdrawal and deposit of common shares under the depositary facility;

 

   

ownership of our shares being restricted under Korean law;

 

   

no preemptive rights in certain circumstances;

 

   

being affected by the volatility of the Korean securities market;

 

   

dividend payments being affected by fluctuations in the exchange rate; and

 

   

restriction on the depositary bank from converting and remitting dividends under emergency circumstances.

Risks Relating to KEPCO

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

In 2020, fuel costs constituted 28.6% of our cost of sales, and the ratio of fuel costs to our sales was 25.5%. Our generation subsidiaries purchase substantially all of the fuel that they use (except for anthracite coal) from 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 (which accounted for approximately 44.8% of our fuel requirements in 2020 in terms of electricity output) are imported principally from Australia, Indonesia, Russia and, to a lesser extent, South Africa and others, which accounted for approximately 40%, 28%, 14%, 2% and 16%, respectively, of the annual bituminous coal requirements of our generation subsidiaries in 2020.

 

5


Table of Contents

Approximately 84% of the bituminous coal requirements of our generation subsidiaries in 2020 were purchased under long-term contracts and the remaining 16% from the spot market. Pursuant to the terms of our long-term supply contracts, prices are adjusted periodically based on prevailing market conditions. In addition, our generation subsidiaries purchase a significant portion of their fuel requirements under contracts with limited duration. See Item 4.B. “Business Overview—Fuel.”

The prices of our main fuel types, namely, bituminous coal, oil and liquefied natural gas, or LNG, fluctuate, sometimes significantly, in tandem with their international market prices. For example, the average weekly spot price of “free on board” Newcastle coal 6000 GAR (Gross As Received) published by Bloomberg (Bloomberg Ticker: COASNE60) decreased from US$77.49 per ton in 2019 to US$60.60 per ton in 2020 and increased to US$98.38 per ton as of March 29, 2021. 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 decreased from US$63.22 per barrel in 2019 to US$42.21 per barrel in 2020 and increased again to US$62.03 per barrel as of March 29, 2021. Furthermore, because the prices of LNG are dependent on the price of crude oil, an increase in such fuel prices can result in an increase in the prices of LNG, which, in turn, affect the cost of purchasing electricity from independent power producers. We cannot assure you that fuel prices will remain stable or will not significantly increase in the remainder of 2021 or thereafter. In addition, effective from January 1, 2020, the International Maritime Organization regulation referred to as IMO 2020 mandated, among other things, a reduction in the global upper limit on the sulphur content of ships’ fuel oil from 3.5% to 0.5%. While we have seen mixed reactions in the market, there is a likelihood that the shift from the traditional high sulphur fuel oil (“HSFO”) to low sulphur fuel oil (“LSFO”) and ultra low sulphur fuel oil (“ULSFO”) may become more pronounced once the pandemic caused by COVID-19 is under control and port authorities resume their full inspection on the fuel content of the ships. Such shift in fuels may significantly increase the operating cost of the shipping lines and the increased costs are expected to be passed onto customers like us via higher freight rates. If fuel prices increase substantially in the future within a short span of time, our generation subsidiaries may be unable to secure adequate fuel 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 may cause our generation subsidiaries to purchase fuel on the spot market at prices higher than the prices available under existing supply contracts, which would result in an increase in fuel costs.

As of January 1, 2021, we implemented a new cost pass-through tariff system to reinforce the correlation between the costs we incur and the tariff we charge to our customers and to enhance transparency by separately billing fuel costs and climate/environment related costs. Previously, the electricity tariff consisted of two main components: (i) the base charge (the “Base Charge”) and (ii) the usage charge (the “Usage Charge”) based on the amount of electricity consumed by end-users. Under the new tariff system, there are new components to the tariff called the fuel cost adjusted charge (the “Fuel Cost Adjusted Charge”) and the climate/environment related charge (the “Climate/Environment Related Charge”). The Fuel Cost Adjusted Charge is adjusted every quarter and the formula for calculating the amount of the Fuel Cost Adjusted Charge is multiplying (i) the unit price of the Fuel Cost adjusted Charge (the “Unit Price of the Fuel Cost Adjusted Charge”), which is the difference between a base fuel cost (the “Base Fuel Cost”) and an actual fuel cost (the “Actual Fuel Cost”) and (ii) the amount of electricity consumed. The Base Fuel Cost is the past twelve-month average fuel price of bituminous coal, LNG and Bunker C oil as posted by the Korea Customs Service. For 2021, the twelve-month average fuel price is measured by taking the average of monthly fuel prices from twelve preceding months from one month before the new tariff system was implemented. To illustrate, the Base Fuel Cost for the first and second quarters of 2021 was the average of the fuel prices from December 2019 to November 2020. On the other hand, the Actual Fuel Cost is the past three-month average fuel price of the same fuels we use to measure the Base Fuel Cost. The past three-month average fuel price is measured by taking the average of monthly fuel prices from three preceding months from one month before the start of each period when the applicable Fuel Cost Adjusted Charge will be updated. To illustrate, for the first quarter of 2021, we used the fuel costs for September, October and November 2020 to calculate the three-month average fuel price.

 

6


Table of Contents

The quarterly-adjusted Fuel Cost Adjusted Charge has built-in caps in view of price stability and other public policy considerations. First, there is a cap on the Unit Price of the Fuel Cost Adjusted Charge to be (i) no less than Won ±1 per kilowatt-hour and (ii) no greater than Won ±3 per kilowatt-hour as compared to the immediately preceding quarter. In other words, any change less than Won ±1 per kilowatt-hour will not be reflected to the Fuel Cost Adjusted Charge and any change greater than Won ±3 per kilowatt-hour will not be reflected to the extent of the portion that exceeds Won ±3 per kilowatt-hour. For example, in the first quarter of 2021, the Unit Price of the Fuel Cost Adjusted Charge was Won –10.5 per kilowatt-hour, meaning the Actual Fuel Cost was lower than the Base Fuel Cost, but after being subjected to the quarterly cap of Won ±3 per kilowatt-hour, the final rate for the Unit Price of the Fuel Cost Adjusted Charge came out to be Won –3 per kilowatt-hour. Second, the Unit Price of the Fuel Cost Adjusted Charge that exceeds Won ±5 per kilowatt-hour will not be reflected in the Fuel Cost Adjusted Charge. In other words, the maximum adjustment that can be incorporated to the Unit Price of the Fuel Cost Adjusted Charge is equal to Won ±5 per kilowatt-hour from the Base Fuel Cost that is in effect for a given period. The Base Fuel Cost can only be adjusted upon the revision of the Base Charge and the Usage Charge as described at further below in this risk factor.

However, our ability to pass on fuel and other cost increases to our customers may be limited due to the regulation of the Government on the rates we charge for the electricity we sell to our customers. In addition to the built-in caps described in the preceding paragraph, the new tariff system gives the discretion to the Government not to wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances. For example, in the second quarter of 2021, although the Unit Price of the Fuel Cost Adjusted Charge was Won –0.2 per kilowatt-hour, the Government decided to keep it at the same Won –3 per kilowatt-hour as the previous quarter. The Government cited (i) the need to alleviate the hardship caused by the prolonged economic effects of COVID-19 pandemic, (ii) an abnormal nature of the rapid increase in the price of LNG due to the global cold wave in the winter of late 2020 and early 2021, which has been factored into the Actual Fuel Cost, and (iii) the relative gains we received in the first quarter of 2021 because the Fuel Cost Adjusted Charge for the first quarter was capped at the lower bound of Won –3 per kilowatt-hour instead of decreasing it further.

Also, because the Fuel Cost Adjusted Charge takes into account the fuel prices posted by Korea Customs Service, there may still be a mismatch in value between the actual prices the domestic generation companies pay for their fuels in the open market and the adjustment that can be made through the Fuel Cost Adjusted Charge. The domestic generation companies include not only our generation subsidiaries but also independent power producers that are unaffiliated to us and we do not have access to fuel costs incurred by the independent power producers. As such, we use fuel prices posted by Korea Customs Service, which are easily accessible to our customers, for calculating the Fuel Cost Adjusted Charge.

Due to the likelihood of the Actual Fuel Cost being substantially over the caps in the new tariff system and the Government’s discretion not to wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances, there may be certain portions of the fuel costs that cannot be charged to our customers, even though those portions should have been included in the Fuel Cost Adjusted Charge. In such cases, we may accumulate such portions and reflect them in what is called the total comprehensive cost (the “Total Comprehensive Cost”), which is a variable we use to calculate the Base Charge and the Usage Charge of the tariff. The Total Comprehensive Cost, submitted yearly to the Government by us, is calculated based on our budget for relevant costs. Under the Total Comprehensive Cost approach, the Base Charge and the Usage Charge are established at levels that would enable us to recover our operating costs attributable to our basic electricity generation, transmission and distribution operations as well as receive a fair investment return on capital used in those operations. The operating costs are defined as the sum of our operating expenses, which principally consists of cost of sales and selling and administrative expenses, and our adjusted income taxes. The Base Charge and the Usage Charge that are derived from the Total Comprehensive Cost need to be approved by the Government to be revised. In addition, the Base Fuel Cost can only be adjusted upon the revision of the Base Charge and the Usage Charge. Therefore, if the Base Charge and the Usage Charge are not timely adjusted by the Government, there can be a delay for the change in fuel costs to be fully reflected in the tariff.

 

7


Table of Contents

Despite the new tariff system, if fuel prices increase rapidly and substantially and the current level of electricity tariff is not increased to a level sufficient to offset the impact of high fuel prices or not adjusted responsive to fuel price movements due to the factors we described in this risk factor, our profit margins will be adversely affected and/or we can even have operating and/or net losses, and our business, financial condition, results of operations and cash flows may be adversely affected.

The Government may adopt policy measures to substantially restructure the Korean electric power industry or our operational structure, which may have a material adverse effect on our business, operations and profitability.

From time to time, the Government considers various policy initiatives to foster efficiency in the Korean electric power industry, and at times have adopted policy measures that have substantially modified our business and operations. For example, in January 1999, with the aim of introducing greater competition in the Korean electric power industry and thereby improving its efficiency, the Government announced a restructuring plan for the Korean electric power industry, or the Restructuring Plan. For a detailed description of the Restructuring Plan, see Item 4.B. “Business Overview—Restructuring of the Electric Power Industry in Korea.” As part of this initiative, in April 2001 the Government established the Korea Power Exchange to enable the sale and purchase of electricity through a competitive bidding process, established the Korea Electricity Commission to ensure fair competition in the Korean electric power industry, and, in order to promote competition in electricity generation, split off our electricity generation business to form one nuclear generation company and five non-nuclear generation companies, in each case, to be wholly owned by us. In 2002, the Government introduced a plan to privatize one of our five non-nuclear generation subsidiaries, but this plan was suspended indefinitely in 2004 due to prevailing market conditions and other policy considerations.

In August 2010, the Ministry of Trade, Industry and Energy announced the Proposal for the Improvement in the Structure of the Electric Power Industry, which was designed to promote responsible management by and improve operational efficiency of government-affiliated electricity companies by fostering competition among them. Pursuant to this proposal, while our six generation subsidiaries continued to be our wholly-owned subsidiaries, in January 2011 the six generation subsidiaries were officially designated as “market-oriented public enterprises” (same as us) under the Act on the Management of Public Institutions, whereupon the President of Korea appoints the president and the standing director who is to become a member of the audit committee of each such subsidiary; the selection of non-standing directors of each such subsidiary is subject to approval by the minister of the Ministry of Economy and Finance; the president of each such subsidiary is required to enter into a management contract directly with the minister of the Ministry of Trade, Industry and Energy; and the Committee for Management of Public Institutions (which is comprised largely of Government officials and those recommended by Government officials) conducts performance evaluation of such subsidiaries. Previously, our president appointed the president and the statutory auditor of each such subsidiary; the selection of non-standing directors of each such subsidiary was subject to approval by our president; the president of each such subsidiary entered into a management contract with our president; and our evaluation committee conducted performance evaluation of such subsidiaries. As a result of these changes, our six generation subsidiaries took on additional operational responsibilities and management autonomy with respect to construction and management of generation units and procurement of fuel, while we as the parent company continued to oversee and coordinate, among others, finances, corporate governance, overseas businesses, including nuclear export technology and overseas resource development, that jointly affect us and our generation subsidiaries. See also Item 16G. “Corporate Governance—The Act on the Management of Public Institutions—Applications of the Act on Our Generation Subsidiaries.”

In June 2016, the Government announced the Proposal for Adjustment of Functions of Public Institutions (Energy Sector) for the purpose of streamlining the operations of government-affiliated energy companies by discouraging them from engaging in overlapping or similar businesses with each other, reducing non-core assets and activities and improving management and operational efficiency. The initiatives contemplated in this

 

8


Table of Contents

proposal that would affect us and our generation subsidiaries include the following: (i) the generation companies should take on greater responsibilities in overseas resource exploration and production projects as these involve procurement of fuels necessary for electricity generation while fostering cooperation among each other through closer coordination, (ii) KHNP should take a greater role in export of nuclear technology, and (iii) the current system of retail sale of electricity to end-users should be liberalized to encourage more competition. In accordance therewith, we transferred a substantial portion of our assets and liabilities in our overseas resource business to our generation subsidiaries as of December 31, 2016. In addition, pursuant to this Proposal, we considered a sale in the public market of a minority of our shares in our five non-nuclear generation subsidiaries, KEPCO KDN and KHNP. However, the planned sales have been put on hold, primarily due to prevailing market conditions. In any event, we plan to maintain a controlling stake in each of these subsidiaries.

Other than as set forth above, we are not aware of any specific plans by the Government to resume the implementation of the Restructuring Plan or otherwise change the current structure of the electric power industry or the operations of us or our generation subsidiaries materially in the near future. However, for reasons relating to changes in policy considerations, socio-political, 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 electric power industry or the operations of us or our generation subsidiaries materially. Any such measures may have a negative effect on our business, results of operations and financial condition. In addition, the Government, which beneficially owns a majority of our shares and exercises significant control over our business and operations, may from time to time pursue policy initiatives that could directly or indirectly impact our business and operations, and such initiatives may vary from the interest and objectives of our other shareholders.

The Government may adopt policy measures that affect the tariff rates in order to ease the burden on residential consumers, which may burden us financially.

Previously, there have been several adjustments to the existing tariff rates for residential consumers in order to ease the burden of electricity tariff on them. But these adjustments may be independent from fuel price movements and our business, results of operations, financial condition and profitability may suffer as a result. For example, effective on January 1, 2017, the progressive rate structure applicable to the residential sector, which applies a gradient of increasing tariff rates for heavier electricity usage, was changed from a six-tiered structure with the highest rate being no more than 11.7 times the lowest rate (which gradient system has been in place since 2005) into a three-tiered structure with the highest rate being no more than three times the lowest rate, in order to reflect the changes in the pattern of electricity consumption and reduce the electricity charges payable by consumers. Additionally, a new tariff structure was implemented to encourage energy saving by offering rate discounts to residential consumers that voluntarily reduce electricity consumption while charging special high rates to residential consumers with heavy electricity consumption during peak usage periods in the summer and the winter. Further, during July and August 2018, the residential electricity charges were reduced by temporarily relaxing the application of the then tariff structure and offering higher rate discounts to economically or otherwise disadvantaged customers to ease the burden on households that have significantly increased their use of air conditioners during a heatwave. Subsequently, a joint task force team, consisting of industry experts, scholars and government officials, was formed, which announced a proposal for amending the tariff structure aimed to lower electricity rates for households during the summer. As a result, in July 2019, the residential electricity tariff rate system was amended to expand the usage ceiling for the first two tiers of rates (from 200 kilowatts to 300 kilowatts for the first tier and from 400 kilowatts to 450 kilowatts for the second tier) applied during July and August each year. With the implementation of the new tariff system as of January 1, 2021, the residents were given a new benefit to opt for a new schedule of residential tariff, which is an option we have already been providing to our industrial and commercial customers. The new schedule is called a seasonal and hourly tariff and it allows residents to be charged under a monthly Base Charge plus increments depending on time, day and season. Each household may also choose to stay under the current tariff schedule which in contrast is a progressive schedule with seasonal adjustments. Our plan is to provide this option to households in

 

9


Table of Contents

Jeju Province in Korea first as many of these households are equipped with advanced metering infrastructure (“AMI”) and review rolling it out to the rest of the country depending on the penetration rate of the AMI in each region. Even though the rate discounts offered to residential consumers who voluntarily reduced electricity consumption and those offered to traditional wet markets were abolished in December 2019, the rate discount for electric vehicles will be gradually terminated in phases by June 2022, and the rate discounts for households that use less than 200 kilowatt-hours will phase out to 50% in July 2021 and be terminated in July 2022, there can be no assurance that other potential future adjustments in electricity tariff rates and rate discounts will not have an adverse impact on our business, results of operations, financial condition and profitability. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates” for more information on electricity tariff for residential consumers.

Our capacity expansion plans, which are principally based on projections on long-term supply and demand of electricity in Korea, may prove to be inadequate.

We and our generation subsidiaries make plans for expanding or upgrading our generation capacity and transmission infrastructure based on the Basic Plan Relating to the Long-Term Supply and Demand of Electricity, or the Basic Plan, which is generally revised and announced every two years by the Government. In December 2020, the Government announced the Ninth Basic Plan to revise the Eighth Basic Plan. The Ninth Basic Plan is effective for the period from 2020 to 2034. The Ninth Basic Plan focuses on, among other things, accelerating transition to eco-friendly power sources. The specific measures include: (i) thirty decrepit coal-fired power plants and eleven nuclear power plants will be retired, and, as a result, coal and nuclear generation capacities will be reduced to 29 gigawatts and 19.4 gigawatts respectively by 2034, (ii) twenty-four out of thirty decrepit coal-fired power plants will be retired, the total generation capacity for which is 12.7 gigawatts, and shall be converted into using LNG instead, and (iii) domestic renewable energy generation capacity will be expanded by 77.8 gigawatts by 2034 in accordance with the Green New Deal initiative of the Korean Government.

In June 2019, the Ministry of Trade, Industry and Energy adopted the Third Basic National Energy Plan following consultations with representatives from civic groups, the energy industry and academia. The Third Basic National Energy Plan, which is a comprehensive plan that covers the entire spectrum of energy industries in Korea, covers the period from 2019 to 2040. The Third Basic National Energy Plan is consistent with the First and the Second Basic National Energy Plans in terms of the general policy direction and aims to promote sustainable growth and improvement of people’s quality of life by converting to renewable energy. Specifically, it establishes the following five key tasks: (i) strengthening management of energy demand from various sectors, such as commerce and transportation, and promoting a rational electricity tariff system to improve the national energy consumption efficiency by 38% and reduce the energy demand by 18.6% by 2040; (ii) converting to clean and safe energy through gradual reduction of nuclear power generation and decisive reduction of coal power generation by prohibiting construction of new coal-fired power plants and increasing the proportion of renewable energy sources to approximately 35% by 2040; (iii) expanding the power distribution in areas near those with demands for renewable energy and fuel cells and strengthening the roles and responsibilities of local governments; (iv) fostering the growth of the future energy industries (including renewable energy, hydrogen fuel and other efficient sources of energy linked to technology), promoting the value-add for traditional energy industries and maintaining a core energy ecosystem for nuclear power plants; and (v) improving the energy, gas and heat market systems to facilitate the national energy conversion and building platforms based on big data to foster creation of new energy industries.

We cannot assure that the Ninth Basic Plan, the Third Basic National Energy Plan, or their respective successor plans will successfully achieve their intended goals, the foremost of which is to ensure, through carefully calibrated capacity expansion and other means, balanced overall electricity supply and demand in Korea to end users while promoting efficiency and environmental friendliness in the consumption and production of electricity. If there is significant variance between the projected electricity supply and demand considered in

 

10


Table of Contents

planning our capacity expansions and the actual electricity supply and demand, or if these plans otherwise fail to meet their intended goals or have other unintended consequences, this may result in inefficient use of our working capital, and undue financing costs on the part of us and our generation subsidiaries, among others, which may have a material adverse effect on our results of operations, financial condition and cash flows.

From time to time, we may experience temporary power shortages or circumstances bordering on power shortages due to factors beyond our control, such as extreme weather conditions. Such circumstances may lead to increased end-user complaints and greater public scrutiny, which may in turn require us to modify our capacity expansion plans, and if we were to substantially modify our capacity plans, this might result in additional capital expenditures and, as a result, have a material adverse effect on our results of operations, financial condition and cash flows.

Although the Government makes significant efforts to encourage conservation of electricity, including through public education campaigns, there is no assurance that such efforts will have the desired effect of substantially reducing the demand for electricity or improving efficient use thereof.

We are subject to various environmental legislations, regulations and related government initiatives, including in relation to climate change, which could cause significant compliance costs and operational liabilities.

We are subject to national, local and overseas environmental laws and regulations, including increasing pressure to reduce emission of carbon dioxide from our electricity generation. Our operations could expose us to the risk of substantial liability relating to environmental, health and safety issues, such as those resulting from the discharge of pollutants and carbon dioxide into the environment and the handling, storage and disposal of hazardous materials. We may be responsible for the investigation and remediation of environmental conditions at current or former operational sites. We may also be subject to related liabilities (including liabilities for environmental damage, third party property damage or personal injury) resulting from lawsuits brought by governments or private litigants. In the course of our operations, hazardous wastes may be generated, disposed of or treated at third party-owned or -operated sites. If those sites become contaminated, we could also be held responsible for the cost of investigation and remediation of such sites for any related liabilities, as well as for civil or criminal fines or penalties.

We intend to fully comply with our environmental obligations. However, our environmental measures, including the use of, or replacement with, environmentally friendly but more expensive parts and equipment and budgeting capital expenditures for the installation or modification of such facilities, may result in increased operating costs and liquidity requirement. The actual cost of installation, replacement, modification and/or operation of such equipment and related liquidity requirement may depend on a variety of factors that are beyond our control. There is no assurance that we will continue to be in material compliance with legal or regulatory requirements or satisfy social norms and expectations in the future in relation to the environment, including in respect of climate change.

In recent years, partly driven by growing public awareness and sensitivity toward climate change and other environmental issues as well as in an effort to capture the economic and social potential associated with renewable energy and “new energy”-related industries (such as smart grids, energy storage systems and electrical vehicles, among others), the Government has introduced and implemented a number of new measures designed to reduce greenhouse gas emission, minimize environmental damage and spur related business opportunities. Some key examples of such Government initiatives pertinent to our and our generation subsidiaries’ operations are as follows:

 

   

Greenhouse Gas Emission Trading System, Related Emission Reduction Targets and the Greenhouse Gas Reduction Roadmap.

 

  ¡   

In accordance with the Act on Allocation and Trading of Greenhouse Gas Emission Allowances, enacted in March 2013, the Government implemented a greenhouse gas emission trading system under which the Government will allocate the amount of permitted greenhouse gas emission to

 

11


Table of Contents
 

companies by industry and a company whose business emits more carbon than the permitted amount is required to purchase the right to emit more carbon through the Korea Exchange. The categories of allowances traded include the Korean Allowance Unit (KAU), which is the emissions allowance allocated to applicable companies by the Government; Korean Credit Unit (KCU), which is a tradable unit converted from external carbon offset certifications including the Korean Offset Credit; and Korean Offset Credit (KOC), which is the verified carbon offset credit obtained by companies for reducing carbon emissions through absorption or otherwise. The greenhouse gas emission trading system is expected to be implemented in three stages. During the first phase (2015 to 2017), the Government set up and conducted a test run of the trading system to ensure its smooth operation, allocating the greenhouse gas emission allowances free of charge. In July 2018, the Government released the allocation plan for the second phase (2018 to 2020), during which 97% of the greenhouse gas emission allowances were allocated free of charge, with 3% allocated through an auction. During the third phase (2021 to 2025), the Government expanded the scale of the system with aggressive greenhouse gas emission reduction targets and allocating 10% of the greenhouse gas emission allowances through an auction.

 

  ¡   

In December 2016, the Government announced the Climate Change Response Initiatives and the 2030 National Greenhouse Gas Reduction Roadmap, which set forth the greenhouse gas emission trading system as one of the primary means to reach the emission and greenhouse gas reduction targets of the policies. According to the Nationally Determined Contributions (NDC) announced by the Government in December 2020, the total greenhouse gas emission target level by 2030 is a 24.4% reduction as compared to the level in 2017, and the reduction target for the electricity conversion sector as a whole which we are the part of is a total of 60 million tons as compared to the level in 2017. In addition, in December of 2020, the government announced the Long-term low greenhouse gas Emission Development Strategies (LEDS) and presented a long-term vision and national strategy for achieving carbon neutrality in 2050. We cannot assure you that the reduction target will not be raised in the future. Adhering to such emission and greenhouse gas reduction requirement may result in significant additional compliance costs. For example, the daily market price of the KAUs traded through the Korea Exchange was Won 8,640 per ton in early 2015, and the price has increased continuously thereafter, reaching its peak price at Won 42,500 per ton on April 2, 2020. Since then, the price has been lowered due to the influence of COVID-19, and, as of the end of 2020, the price has been formed in the range of Won 20,000 per ton. We cannot predict how the price of the KAUs will fluctuate over time, and such volatility may adversely affect our results of operation, financial condition and cash flows.

 

   

Regulation of Coal-Fired Generation Units. As a measure to address the high level of particulate matter pollution, in October 2018, the Government introduced a pilot regulation to lower the output of 35 coal-fired generation units to approximately 80% of their capacity that emit more than a certain amount of particulate matter. The regulation was formally implemented in January 2019, targeting 40 coal-fired power plants with high emissions of particulate matter. From March to June 2019, the scope expanded to cover 60 units in total. In addition, coal-fired generation units originally scheduled for preventive maintenance during the second half of 2019 were required to undertake such maintenance earlier in the spring of 2019. In November 2019, the Government pursued a reduction of coal-fired generation units in order to implement the Special Measures to Respond to the High Concentration Period (December to March) of Particulate Matter. During December 2019 to March 2020, 8 to 15 coal-fired generation units that require preventive maintenance or are otherwise older units were first shut down, with a maximum of 49 coal-fired generation units subject to a cap of 80% on the output within the remaining reserve capacity range. We plan to continue to participate in the effort to reduce the particulate matter emissions from coal-fired generation units, not only during the winter but also during the spring. For example, from December 2020 to February 2021, 9 to 17 coal-fired generation units were shut down, with a maximum of 46 coal-fired generation units subject to a cap of 80% on the output within the remaining reserve capacity range. In March 2021, we suspended the operations of 19 to 28 coal power generation plants and imposed a cap of 80% on the output of up

 

12


Table of Contents
 

to 37 coal-fired generation units. Additionally, the Government adjusted the schedule to close down two decrepit coal-fired generation units (Boryeong #1 and #2), which were shut down in December 2020. Also, other coal-fired generation units, Samcheonpo #1 and #2, are planned to be shut down in May 2021 and Honam #1 and #2 units in December 2021. According to the Ninth Basic Plan announced in December 2020, the total coal-fired power plant capacity in 2030 will decrease to 32.6 gigawatts from 35.8 gigawatts in 2020, and its percentage of total power generation capacity will decrease to 18.9% from 28.1% in 2020. In addition, the Government will introduce a system that will limit the annual power generation of coal-fired power plants in line with its greenhouse gas reduction target. While such measures may be subject to change, we expect to incur significant costs of complying with such measures, including in connection with more stringent particulate matter pollution regulations, retrofitting and overall replacement of environmental facilities.

 

   

Coal and LNG Consumption Taxes. In January 2014, largely based on policy considerations of tax equity among different fuel types as well as environmental concerns, the Ministry of Economy and Finance announced that, effective July 1, 2014, consumption tax will apply to bituminous coal, which previously was not subject to consumption tax unlike other fuel types such as LNG or bunker oil. Pursuant to the amended Individual Consumption Tax Act effective as of April 1, 2019, which involved an increase of the unit tax rate for coal by Won 10 per kilogram across the board, the base tax rate (which is subject to certain adjustments) is Won 46 per kilogram for bituminous coal; however, due to concerns on the potential adverse effect on industrial activities, the applicable tax rate is applied differently based on the net heat generation amount. The currently applicable tax rate for bituminous coal is Won 43 per kilogram for net heat generation of less than 5,000 kilocalories, Won 46 per kilogram for net heat generation of 5,000 to 5,500 kilocalories and Won 49 per kilogram for net heat generation of 5,500 kilocalories or more. In contrast, the consumption tax and surcharge on importation of LNG decreased by Won 48 and Won 20.4 per kilogram, respectively, which came into effect in April 2019. The currently applicable consumption tax rate and surcharge on importation of LNG are Won 12 and Won 3.8 per kilogram, respectively. We expect an increase in our overall fuel costs, as bituminous coal currently represents the largest fuel type for our electricity generation, while the decrease in consumption tax and surcharge on importation of LNG will result in a decrease of our power purchase cost.

 

   

Renewable Portfolio Standard. Under this program, each of our generation subsidiaries is required to generate a specified percentage of total electricity to be generated by such generation subsidiary in a given year in the form of renewable energy or, in case of a shortfall, purchase a corresponding amount of a Renewable Energy Certificate (a form of renewable energy credit) from other generation companies whose renewable energy generation surpass such percentage. The target percentage was 4.0% in 2017, 5.0% in 2018, 6.0% in 2019, 7.0% in 2020, 9.0% in 2021 and will incrementally increase to 10.0% by 2022. Fines are to be levied on any subsidiary that fails to do so in the prescribed timeline. In 2019, all six of our generation subsidiaries met the target through renewable energy generation and/or the purchase of a Renewable Energy Certificate. Compliance by our generation subsidiaries of the 2020 target is currently under evaluation, and if any generation subsidiary is found to have failed to meet the target for 2020 or for subsequent years, such generation subsidiary may become subject to fines. From October 2021, an amendment to the Act on the Promotion of the Development, Use, and Diffusion of New and Renewable Energy will become effective to raise the upper limited of the target percentage even higher to 25% from the previous threshold of 10%. We expect the target percentage will remain the same for 2021 but future changes to the target percentage may result in additional expenses for our generation subsidiaries.

 

   

Renewable Energy 3020 Plan. In December 2017, the Ministry of Trade, Industry and Energy announced the Renewable Energy 3020 Plan, an initiative to increase the generation and use of renewable energy on a nationwide basis. The Government plans to increase the required percentage of total electricity to be generated from renewable energy sources from 7% in 2016 to 10.5% and 20% by 2022 and 2030, respectively. Moreover, the Government plans to increase the domestic renewable

 

13


Table of Contents
 

energy generation capacity to 63.8 gigawatts by 2030 through the expansion of solar and wind power generation capacities to 36.5 gigawatts and 17.7 gigawatts, respectively. According to the Ninth Basic Plan and the Fifth Basic Plan on Renewable Energy announced in December 2020, the Government has set national targets of 82.2 gigawatts in renewable energy generation and 25.8% of total electricity to be generated from renewable energy sources, including self-generation facilities, in 2034.

 

   

New Energy Industry Fund. In January 2016, the Ministry of Trade, Industry and Energy announced an initiative to promote the new energy industry by creating the New Energy Industry Fund, which is made up of funds sponsored by government-affiliated energy companies. We contributed Won 500 billion to the funds in 2016. The purpose of these funds is to invest in substantially all frontiers of the new energy industry, including renewable energy, energy storage systems, electric vehicles, small-sized self-sustaining electricity generation grids known as “micro-grids”, among others, as well as invest in start-up companies, ventures, small- to medium-sized enterprise and project businesses that engage in these businesses but have not previously attracted sufficient capital from the private sector.

 

   

Environmental and safety considerations in electricity supply and demand planning. In March 2017, the Electric Utility Act was amended to the effect that starting in June 2017, future national planning for electricity supply and demand in Korea should consider the environmental and safety impacts of such planning. Accordingly, the costs related to environmental and safety impacts, such as the desulphurization costs, have been reflected in our variable cost of generating electricity since August 2019. In December 2019, the Regulation on the Operation of the Electricity Market was revised, under which specific provisions of the Cost Evaluation Committee (defined below) to reflect the cost of greenhouse gas emission allowances were to be finalized in two years. The provisions were established in February 2021 and will be implemented from January 2022.

 

   

2050 Carbon-Neutrality Declaration. In response to the Paris Agreement and the United Nations Framework Convention on Climate Change (UNFCCC)’s goal to comprehensively replace fossil fuels and achieve global zero net emissions by 2050, the Korean national assembly has passed a non-binding resolution on September 24, 2020 to establish a special committee on climate change and urging the Government to meet its 2030 carbon reduction goal and bolster its efforts to achieve carbon neutrality by 2050. On November 27, 2020, the Government officially announced the Government’s commitment to implement policies in all areas of the industry to achieve Korea’s carbon neutrality by 2050. On December 10, 2020, the Government followed up with broad 2050 carbon neutrality development strategies. Although no specific regulations or policies affecting our business have been announced or implemented yet, we may experience an increased regulatory scrutiny over carbon dioxide emission from our electricity generation activities and related projects overseas.

 

   

Renewable Energy 100. In line with the spread of RE100, a global campaign by companies around the world to cover 100% of their electricity use with renewable energy by 2050, the Government in 2021 introduced its own version of RE100 that allows companies and other consumers to choose energy sources from which their electricity is generated. In order for a domestic company to participate in RE100, it may enter into a power purchase agreement either with a renewable energy generator through us as an intermediary (third party PPA) or with a renewable energy generator directly such that the generator will supply electricity to the company without going through the existing electricity market (corporate PPA). It is difficult to predict what effects the third party PPA will have on us as the new system has not been finalized yet, but the relevant legislation for the corporate PPA was enacted in the National Assembly in March 2021. If there is an expansion in the use of corporate PPA, it may adversely affect our market share in electricity sales.

Complying with these Government initiatives and operating programs in furtherance thereof has involved and will likely continue to involve significant costs and resources on our part, which may adversely affect our results of operation, financial condition and cash flows. Our cost of complying with the Renewable Portfolio Standard increased as the target percentage for compliance increased in 2020. We expect our future compliance costs may increase as the requirements under Government initiatives and operating programs continue to become

 

14


Table of Contents

more rigorous. We may not be able to pass on the increased cost to customers at a sufficient level or on a timely basis. Further, we and our generation subsidiaries could also become subject to substantial fines and other forms of penalties for non-compliance.

According to the new tariff system which came into effect on January 1, 2021, the Government introduced an additional component to the tariff called the climate/environment related charge (the “Climate/Environment Related Charge”). Previously, our climate and environment costs were embedded in the Usage Charge component of the tariff and our consumers could not discern the exact magnitude of such costs. By separating it out as an independent component, we intend to provide more information and transparency to our customers while having the flexibility to adjust it in alignment with the underlying costs. The Climate/Environment Related Charge for the coming year is calculated by multiplying (i) our total estimated costs of complying with the Renewable Portfolio Standard program, the Greenhouse Gas Emission Trading System and the coal-fired generation reduction program for the current year, and then dividing it by the electricity sales projected for the coming year, and (ii) the amount of electricity consumed. The value for (i) for 2021 is Won 5.3 per kilowatt-hour. The Climate/Environment Related Charge is planned to be adjusted every year by reflecting the change in climate and environment-related costs but the Government may change the date of adjustment under reasonable circumstances. There is no guarantee the Climate/Environment Related Charge will be regularly updated, even though our climate and environment-related costs will likely increase each year. If there are discrepancies between our costs and the Climate/Environment Related Charge, we may accumulate such discrepancies and reflect them in our Total Comprehensive Cost. However, the electricity rate based on the Total Comprehensive Cost needs to be approved by the Government to be revised. There is no assurance that, particularly given the wide-ranging policy priorities of the Government, it will in fact raise the electricity rate to a level sufficient to fully cover additional costs associated with implementing and operating programs as described in this risk factor and do so on a timely basis or at all. If the Government does not do so or provide us and our generation subsidiaries with other forms of assistance to offset the costs involved, our results of operation, financial condition and cash flows may be materially and adversely affected.

See Item 4.B. “Business Overview—Environmental Programs.”

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

We anticipate that a substantial amount of additional indebtedness will be required in the coming years in order to refinance existing debt, make capital expenditures for construction of generation plants and other facilities and/or make acquisitions, invest in renewable energy and the “new energy industry” projects and fund our overseas businesses. In 2018, 2019 and 2020, our capital expenditures in relation to the foregoing amounted to Won 13,695 billion, Won 15,795 billion and Won 15,485 billion, respectively, and our budgeted capital expenditures for 2021, 2022 and 2023 amount to Won 14,397 billion, Won 16,310 billion and Won 15,316 billion, respectively.

While we currently do not expect to face any material difficulties in procuring short-term borrowings to meet our liquidity and short-term capital requirements, there is no assurance that we will be able to do so. We expect that a portion of our long-term debt will need to be paid or refinanced through foreign currency-denominated borrowings and capital raising in international capital markets. Such financing may not be available on terms commercially acceptable to us or at all, especially if the global financial markets experience significant turbulence or a substantial reduction in liquidity or due to other factors beyond our control. If we are unable to obtain financing on commercially acceptable terms on a timely basis, or at all, we may be unable to meet our funding requirements for capital expenditures or debt repayment obligations, which could have a material adverse impact on our business, results of operations and financial condition.

We and our generation subsidiaries have undertaken various programs to reduce debt and improve the overall financial health. For further information, see Item 4.B. “Business Overview—Debt Reduction Program

 

15


Table of Contents

and Related Activities.” Despite our best efforts, however, for reasons beyond our control, including macroeconomic environments, government regulations and market forces (such as international market prices for our fuels), we cannot assure whether we or our generation subsidiaries will be able to successfully reduce debt burdens or otherwise improve our financial health to a level that would be optimal for our capital structure. If we or our generation subsidiaries fail to do so or the measures taken by us or our generation subsidiaries to reduce debt levels or improve financial health have unintended adverse consequences, such developments may have an adverse effect on our business, results of operations and financial condition.

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 from time to time. Even slight depreciation of Won against U.S. dollar and other foreign currencies may result in a material increase in the cost of fuel and equipment purchased by us from overseas since the prices for substantially all of the fuel materials and a significant portion of the equipment we purchase are denominated in currencies other than Won, generally in U.S. dollar.

Changes in foreign exchange rates may also impact the cost of servicing our foreign currency-denominated debt. As of December 31, 2020, 17.1% of our long-term debt (including the current portion but excluding original issue discounts and premium) without taking into consideration of swap transactions, was denominated in foreign currencies, principally U.S. dollar. In addition, even if we make payments in Won for certain fuel materials and equipment, some of these fuel materials may originate from other countries and their prices may be affected accordingly by the exchange rates between the Won and foreign currencies, especially the U.S. dollar. Since the substantial majority 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 the U.S. dollar or other major foreign currencies will have a material adverse effect on our profitability and results of operations.

We may not be successful in implementing new business strategies.

As part of our overall business strategy, we plan to (i) expand clean energy and stabilize electricity supply and demand, (ii) enhance sales profitability and competitiveness, (iii) explore convergence-based new businesses and markets, (iv) secure future strategic technologies and establish infrastructure for digital transformation, and (v) strengthen management efficiency and embody social value.

Due to their inherent uncertainties, such new and expanded strategic initiatives expose us to a number of risks and challenges, including the following:

 

   

new and expanded business activities may require unanticipated capital expenditures and involve additional compliance requirements;

 

   

new and expanded business activities may result in less growth or profit than we currently anticipate, and there can be no assurance that such business activities will become profitable at the level we desire or at all;

 

   

certain of our new and expanded businesses, particularly in the areas of renewable energy, require substantial government subsidies to become profitable, and such subsidies may be substantially reduced or entirely discontinued;

 

   

we may fail to identify and enter into new business opportunities in a timely fashion, putting us at a disadvantage vis-à-vis competitors, particularly in overseas markets; and

 

   

we may need to hire or retrain personnel to supervise and conduct the relevant business activities.

As part of our business strategy, we may also seek, evaluate or engage in potential acquisitions, joint ventures, strategic alliances, restructurings, combinations, rationalizations, divestments or other similar

 

16


Table of Contents

opportunities. The prospects of these initiatives are uncertain, and there can be no assurance that we will be able to successfully implement or grow new ventures, and these ventures may prove more difficult or costly than what we originally anticipated. In addition, we regularly review the profitability and growth potential of our existing and new businesses. As a result of such review, we may decide to exit from or to reduce the resources that we allocate to new or existing ventures in the future. There is a risk that these ventures may not achieve profitability or operational efficiencies to the extent originally anticipated, and we may fail to recover investments or expenditures that we have already made. Any of the foregoing may have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.

We plan to pursue overseas expansion opportunities that may subject us to different or greater risks than those associated with our domestic operations.

While our operations have, to-date, been primarily based in Korea, we and our generation subsidiaries may expand, on a selective and opportunistic basis, overseas operations in the future. In particular, we and our generation subsidiaries may further expand the construction and operation of renewable energy power plants, transmission and distribution and (primarily through our generation subsidiaries) mining and development of fuel sources.

Overseas operations often involve risks that are different from those we face in our domestic operations, including the following:

 

   

challenges of complying with multiple foreign laws and regulatory requirements, including tax laws and laws regulating our operations and investments;

 

   

volatility of overseas economic conditions, including fluctuations in foreign currency exchange rates;

 

   

difficulties in enforcing creditors’ rights in foreign jurisdictions;

 

   

risk of expropriation and exercise of sovereign immunity where the counterparty is a foreign government;

 

   

difficulties in establishing, staffing and managing foreign operations;

 

   

differing labor regulations;

 

   

political and economic instability, natural calamities, war and terrorism;

 

   

lack of familiarity with local markets and competitive conditions;

 

   

changes in applicable laws and regulations in Korea that affect foreign operations;

 

   

obstacles to the repatriation of earnings and cash; and

 

   

environmental regulations and public complaints regarding overseas coal-fired power plants.

Any failure by us to recognize or respond to these differences may adversely affect the success of our operations in those markets, which in turn could materially and adversely affect our business and results of operations.

Furthermore, while we seek to enter into overseas business opportunities in a prudent manner, some of our new international business ventures carry inherent risks that are different from our traditional business of electricity power generation, transmission and distribution. While the overseas businesses in the aggregate currently do not comprise a material portion of our overall business, the actual revenues and profitability from, and investments and expenditures into, such ventures may be substantially different from what we plan or anticipate and may have a material adverse impact on our overall business, results of operations, financial condition and cash flows.

An increase in electricity generated by and/or sourced from independent power producers may erode our market position and hurt our business, growth prospects, revenues and profitability.

As of December 31, 2020, we and our generation subsidiaries owned approximately 64.9% of the total electricity generation capacity in Korea (excluding plants generating electricity for private or emergency use).

 

17


Table of Contents

New entrants to the electricity business will erode our market share and create significant competition, which could have a material adverse impact on our financial condition and results of operations.

In particular, we compete with independent power producers with respect to electricity generation. The independent power producers accounted for 28.6% of total power generation in 2020 and 35.1% of total generation capacity as of December 31, 2020. As of December 31, 2020, there were 20 independent power producers in Korea, excluding renewable energy producers. Private enterprises became permitted to own and operate coal-fired power plants in Korea only after the Ministry of Trade, Industry and Energy approved plans for independent power producers to construct coal-fired power plants under the Sixth Basic Plan announced in February 2013. Under the Ninth Basic Plan announced in December 2020, six coal-fired power plants are planned to be constructed by independent power producers by 2024. While it remains to be seen whether construction of these generation units will be completed as scheduled, if these units were to be completed as scheduled and/or independent power producers are permitted to build additional generation capacity (whether coal-fired or not), our market share in Korea may decrease, which may have a material adverse effect on our results of operations and financial condition.

In addition, under the Community Energy System adopted by the Government in 2004, a minimal amount of electricity is supplied directly to consumers on a localized basis by independent power producers outside the cost-based pool system. Such system is used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. The purpose of this system is to geographically decentralize electricity supply and thereby reduce transmission losses 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 March 31, 2021, the aggregate generation capacity of suppliers participating in the Community Energy System amounted to less than 1% of that of our generation subsidiaries in the aggregate. We currently do not expect the Community Energy System to be widely adopted, especially in light of the significant level of capital expenditure required for such direct supply. However, if the Community Energy System is widely adopted, it may erode our currently dominant market position in the generation and distribution of electricity in Korea and may have a material adverse effect on our business, results of operations and financial condition.

While we are currently the dominant market player in the electricity distribution in Korea, we cannot assure you that our market dominance will not face potential erosion in the future. For example, in June 2016, the Government announced the Proposal for Adjustment of Functions of Public Institutions (Energy Sector), which contemplated a gradual opening of the electricity trading market to the private sector. Although the proposal was withdrawn after a year of deliberation, a number of economists and civic groups are continuing to demand for the liberalization of the electricity trading market. It is difficult to predict whether and in what direction the liberalization of the electricity trading market will happen in the future, and such event may result in substantial reduction of our market share in electricity distribution in Korea, which would have a material adverse effect on our business, results of operation and cash flows.

See also Item 4.B. “Business Overview—Competition.”

Labor unrest or increases in labor cost may adversely affect our operations.

We and each of our generation subsidiaries have separate labor unions. As of December 31, 2020, approximately 72.4% of our and our generation subsidiaries’ employees in the aggregate were members of these labor unions. Since a six-week labor strike in 2002 by union members of our generation subsidiaries in response to a proposed privatization of one of our generation subsidiaries, there has been no material labor dispute. However, we cannot assure you that there will not be a major labor strike or other material disruptions of operations by the labor unions of us and our generation subsidiaries if the Government resumes privatization or other restructuring initiatives or for other reasons, which may adversely affect our business and results of operations.

 

18


Table of Contents

Furthermore, the Government, as part of a response to low fertility amidst an aging population in Korea and to make the lives of workers more stable, has pledged to reduce the number of non-permanent workers and increase the employment of permanent workers, in part by transitioning from non-permanent to permanent positions in the public sector. We have completed transitioning temporary workers to permanent workers at the end of 2019. Our generation subsidiaries have partially completed transitioning of non-permanent workers to permanent positions by hiring them for an indefinite period or establishing subsidiaries and hiring them through such subsidiaries. Our thermal generation subsidiaries plan to form a labor-management consultative body to transition the in-house subcontracted workers for the fuel and environmental facilities to permanent positions. Although the Government guidelines suggest that we transition the non-permanent workers to permanent positions within our existing budget for the related business, we cannot assure you that this will not result in increased costs for us or our generation subsidiaries and have an adverse impact on us or our generation subsidiaries’ financial condition and results of operations.

Additionally, domestic and international policy changes may affect our relationship with our employees, such as the Government’s ratification of four and consent to ratification of three of the eight essential conventions of International Labor Organization and potential reformation of the public employee wage structure. We cannot assure you that such policy changes will not negatively affect our relationship with our employees, which may in turn adversely affect our business and results of operations.

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 KHNP, we currently operate 24 nuclear-fuel generation units. 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 and relatively inexpensive cost structure (which is least costly among the fuel types used by our generation subsidiaries) and is the second largest source of Korea’s electricity supply, accounting for 29.0% of electricity generated in Korea in 2020. Due to significantly lower unit fuel costs compared to those for thermal power plants, our nuclear power plants are generally operated at full capacity with only routine shutdowns for fuel replacement and maintenance, with limited exceptions.

From time to time, our nuclear generation units may experience unexpected shutdowns or maintenance-related stoppage. For example, following an earthquake in the vicinity in September 2016, four nuclear generation units at the Wolsong site were shut down for approximately three months as part of a preventive and safety assurance program although these units were not directly affected by the earthquake. Any prolonged or substantial 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 condition and results of operations.

In addition, heightened concerns regarding the safety of operating nuclear generation units could impede with our ability to operating them for an extended period of time or at all. For example, the nuclear power plant at Wolsong #1 unit began operations in 1982 and ended its operations in 2012 pursuant to its 30-year operating license. In February 2015, the Nuclear Safety and Security Commission (“NSSC”) evaluated the safety of operating Wolsong #1 unit and approved its extended operation until November 2022. However, a civic group filed a lawsuit to annul such decision, and in February 2017, the Seoul Administrative Court ruled against the NSSC. The NSSC appealed this decision, and the civic group filed an injunction to suspend the operation of the Wolsong #1 unit. The civic group’s injunction was denied in July 2017. KHNP, which operated the unit pursuant to the NSSC’s initial decision, has joined this lawsuit.

 

19


Table of Contents

There are ten other nuclear generation units whose life under their initial operating license will expire in the next ten years, or by 2030, and we may find it more difficult to have the life of other nuclear units extended as well. The failure to extend the life of these units would result in a loss of revenues from such units and the increase in our overall fuel costs (as nuclear fuel is the cheapest compared to coal, LNG or oil), which could adversely affect our results of operation and financial condition. Furthermore, in September 2016, Greenpeace and 559 Korean nationals brought a lawsuit against the NSSC to revoke the permit the NSSC granted to KHNP in relation to the construction of Shin-Kori #5 and #6 nuclear generation units. The Seoul Administrative Court dismissed the plaintiffs’ case on February 14, 2019. The Seoul High Court dismissed the appeal in January 2021. The case was further appealed and is now pending in the Supreme Court of Korea. Additionally, in May 2019, a group of 729 Korean nationals brought a lawsuit against the NSSC to suspend the operation of Shin-Kori #4. In July 2019, we have applied to participate in the lawsuit as a stakeholder. In February 2021, the Seoul Administrative Court dismissed the plaintiffs’ claim. The plaintiffs subsequently appealed in March 2021. We cannot assure you that there will not be new challenges to prohibit the construction of these new nuclear units in the future, whereby we may experience a loss of revenues and an increase in fuel costs (as nuclear fuel is the cheapest compared to coal, LNG or oil) as a result of such prohibition, which could adversely affect our results of operation and financial condition.

In order to prevent damages to the nuclear facilities such as a result of the tsunami and earthquake in March 2011 in Japan, KHNP prepared a comprehensive safety improvement plan including, but are not limited to, installing additional automatic shut-down systems for earthquakes, extending coastal barriers for seismic waves, procuring mobile power generators and storage batteries, installing passive hydrogen removers at nuclear facilities and improving the radiology emergency medical system. All follow-up measures will be finalized in December 2024 due to changes in the plan. KHNP also developed 10 additional supplementary safety measures by analysis of overseas plants and its current operations and implemented nine of such measures in 2017, with the one remaining measure to be implemented by 2023. However, there is no assurance that a similar or worse natural disaster may require the adoption and implementation of additional safety measures, which may be costly and have a material adverse impact on our financial condition and results of operations.

Subsequently, the Government unveiled its roadmap to shift in energy sources in October 2017 and announced the Eighth Basic Plan to implement such roadmap in December 2017. The Eighth Basic Plan focuses on, among other things, decreasing the reliance on nuclear and coal-based supply sources. Accordingly, six new nuclear generation units in a planning stage (Shin-Hanul #3 and #4, Chunji #1 and #2 and Daejin #1 and #2) would not be constructed, while new nuclear plants under construction, including Shin-Kori #5, #6, Shin-Hanul #1 and #2, shall begin operation by 2025 upon completion of the construction. However, the construction of Shin-Kori #5 and #6 was recently postponed for one year and nine months to March 2024 and March 2025, respectively, to prevent undue speed in construction in light of the recent enactment of Serious Accidents Punishment Act. The Ninth Basic Plan announced in December 2020 also focuses on the same agenda as the Eighth Basic Plan. Future extensions of life of decrepit nuclear generation units would not be granted and the proportion of renewable energy sources would be increased. We cannot assure you that these policies will not have an adverse impact on our or our generation subsidiaries’ financial condition and results of operations.

On June 15, 2018, the board of directors of KHNP decided to (i) retire Wolsong #1 unit earlier than planned due to comprehensive evaluation of the economic viability and regional sentiment of its continuing operation and (ii) discontinue the construction of Chunji #1 and #2 as well as Daejin #1 and #2 units. On December 24, 2019, the NSSC approved the permanent shutdown of Wolsong #1 unit. The Board of Audit and Inspection of Korea carried out an investigation into whether the shutdown of Wolsong #1 unit was economically feasible and reported that the benefits of continued operations were set unreasonably low compared to the benefits of being immediately shut down, which may have led to the approval of the permanent shutdown of Wolsong #1 unit. KHNP is currently preparing guidelines for economic feasibility assessment according to the results for the investigation by the Board of Audit and Inspection of Korea reported on October 20, 2020. However, the result of the investigation has not affected the decision to shut Wolsong #1 unit down. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Wolsong #1 unit

 

20


Table of Contents

accrued to Won 572,216 million and reversal of impairment loss was Won 16,693 million. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Chunji #1 and #2 as well as Daejin #1 and #2 units amounted to Won 38,886 million. Although the board of directors did not make any decisions regarding Shin-Hanul #3 and #4 units, which are new nuclear plants under construction, we cannot assure you that the construction of these units will not be discontinued. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Shin-Hanul #3 and #4 units accrued to Won 134,736 million. The Government currently has preliminary plans to refund us for reasonable expenditures incurred in relation to the phase-out of nuclear power plants in accordance with the Government’s energy transition policy. As of December 31, 2020, the impairment loss for each unit is still the same amount.

The construction and operation of our generation, transmission and distribution facilities involve difficulties, such as opposition from civic groups, which may have an adverse effect on us.

From time to time, we encounter social and political opposition against construction and operation of our generation facilities (particularly nuclear units) and, to a lesser extent, our transmission and distribution facilities. For example, we recently faced intense opposition from local residents and civic groups to the construction of transmission lines in the Milyang area, which we resolved through various compensatory and other support programs. Such opposition delayed the schedule for completion of this project. Although we and the Government have undertaken various community programs to address concerns of residents in areas near our facilities, civic and community opposition could result in delayed construction or relocation of our planned facilities, which could have a material adverse impact on our business and results of operations.

Our risk management policies and procedures may not be fully effective at all times.

In the course of our operations, we must manage a number of risks, such as regulatory risks, market risks and operational risks. Although we devote significant resources to developing and improving our risk management policies and procedures and expect to continue to do so in the future, our risk management practices may not be fully effective at all times in eliminating or mitigating risk exposures in all market environments or against all types of risk, including risks that are unidentified or unanticipated, such as natural disasters or employee misconduct. For example, in May 2013, the NSSC discovered that certain parts used in several of our then-operating nuclear generation units had been supplied based on falsified certificates. This discovery led to full internal investigation and investigation by the Prosecutor’s Office, which in turn led to prosecutions and convictions of several current and former employees of KHNP on related and separate bribery charges, as well as termination of the then-president of KHNP as part of a broad disciplinary action. The incident also led to suspended operation of the related nuclear generation units for several months pending safety inspection. A similar incident involving falsified certificates and bribery occurred also in November 2012. We and KHNP have fully cooperated with the authorities in terms of investigations as well as remedial and preventive measures, including enhanced internal compliance policies and procedures. In November 2019, prosecutors indicted six of KHNP’s employees for, among others, failing to immediately shut down Hanbit #1 reactor when its thermal output exceeded the threshold specified by the nuclear safety technical operations manual and filing false reports to the NSSC. KHNP is also indicted for secondary liability from its employees’ alleged wrongdoings. The case stemmed from the NSSC’s investigations into the manual shutdown of Hanbit #1 reactor during a diagnostic test in May 2019. In February 2021, the Gwangju District Court acquitted the employees of their charges of violating the safety technical operations manual and driving a vehicle without a license during the incident. However, three employees were fined for filing false reports to NSSC and KHNP was also fined in accordance with the disciplinary regulations. The prosecutors appealed the District Court’s decision and the case will proceed to an appellate court. We cannot assure you that the outcomes of the ongoing case will not have any material adverse effect on us, our reputation and our operating results. To prevent similar incidents from occurring again, KHNP is working to improve its risk monitoring and management system. For additional information, see Item 4.B. “Business Overview—Nuclear Safety.”

In April 2019, a forest fire broke out in Goseong in Gangwon Province, about 210 kilometers from Seoul, causing damages to nearby towns, covering approximately 1,260 hectares. The National Forensic Service has

 

21


Table of Contents

investigated the cause of the fire and has determined that the fire seems to have started by an electrical arc from our utility pole’s wire, which broke as a result of a strong wind. Based on this finding, the Police Department of Goseong conducted follow-up investigations and issued a recommendation to prosecute seven employees of KEPCO in connection with the fire. The prosecutors have taken over the case and a trial is underway, the results of which may have a material adverse effect on us, our reputation and our operating results. In the meantime, we have settled with and completed compensation payment of Won 57.5 billion to victims as of March 2021. We expect settlements with the remaining victims would cost us approximately Won 11.8 billion. In addition, we are compensating the fire victims by providing a number of services, such as free supply of electricity, and implementing measures to prevent future fires that may result from an electrical arc, including a special maintenance program during the dry season between March and May. Also, we implemented operational measures such as tailored operation of protective devices and suspension of operation during periods of low loads and plan to change power facility designs to reflect regional and seasonal characteristics, all of which are intended to help prevent similar incidents from happening in the future. Despite our efforts, however, such incidents may occur again, and we cannot assure you that they will not have any material adverse effect on us, our reputation and our operating results.

Further, our operational activities like the generation of electricity involve inherent operating risks that may result in accidents involving serious injury or loss of life, environmental damage or property damage. In December 2018, an employee of KOWEPO’s subcontractor died in an accident at a Taean thermal power unit, leading to a public scrutiny and review by the Ministry of Employment and Labor. As a result, KOWEPO was required to halt the operations of three Taean thermal power units (Taean #9 and #10 units as well as Taean Integrated Gasification Combined Cycle (IGCC)) between December 2018 and May 2019. Even though we plan to prioritize on-site safety management by engaging in communications with different stakeholders and investing more in safe environment, there is no guarantee that there will not be future accidents due to our inherent operating risks.

We believe we and our subsidiaries are in compliance in all material respects with internal compliance policies and procedures and all other additional safety measures initiated internally or required by regulatory and governmental agencies. However, we cannot assure you that, despite all precautionary and preventative measures undertaken by us, these measures will prove to be fully effective at all times against all the risks we face or that an incident that could cause harm to our reputation and operation will not happen in the future, including due to factors beyond our control.

Our risk management procedures may not prevent losses in debt and foreign currency positions.

We manage interest rate exposure for our debt instruments by limiting our variable rate debt exposure as a percentage of our total debt and closely monitoring the movements in market interest rates. We also actively manage currency exchange rate exposure for our foreign currency-denominated liabilities by measuring the potential loss therefrom using risk analysis software and entering into derivative contracts to hedge such exposure when the possible loss reaches a certain risk limit. To the extent we have unhedged positions or our hedging and other risk management procedures do not work as planned, our results of operations and financial condition may be adversely affected.

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. KHNP carries insurance for its generation units and nuclear fuel transportation, and we believe that the level of insurance is generally adequate and is in compliance with relevant laws and regulations. In addition, KHNP is the beneficiary of Government indemnity that covers damages which the insurance cannot cover. However, 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

 

22


Table of Contents

result from a serious accident or a natural disaster to the extent it is 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 these 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, 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 it is uninsured.

In addition, because neither we nor our non-nuclear generation subsidiaries carry any insurance against terrorist attacks, an act of terrorism would result in significant financial losses. See Item 4.B. “Business Overview—Insurance.”

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 directly or indirectly own at least 51% of our issued capital stock. As of December 31, 2020, the Government, directly and through Korea Development Bank (a statutory banking institution wholly owned by the Government), owned 51.1% 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.

We may be exposed to potential claims made by current or previous employees for unpaid wages for the past four years under the expanded scope of ordinary wages and become subject to additional labor costs arising from the broader interpretation of ordinary wages under such decision.

Under the Labor Standards Act, an employee is legally entitled to “ordinary wages.” Under the guidelines previously issued by the Ministry of Employment and Labor, ordinary wages include base salary and certain fixed monthly allowances for work performed overtime during night shifts and holidays. Prior to the Supreme Court decision described below, many companies in Korea had typically interpreted these guidelines as excluding from the scope of ordinary wages fixed bonuses that are paid other than on a monthly basis, namely on a bi-monthly, quarterly or semi-annual basis, although such interpretation had been a subject of controversy and had been overruled in a few court cases.

In December 2013, the Supreme Court of Korea ruled that regular bonuses fall under the category of ordinary wages on the condition that those bonuses are paid regularly and uniformly, and that any agreement which excludes such regular bonuses from ordinary wage is invalid. One of the key rulings provides that bonuses that are given to employees (i) on a regular and continuous basis and (ii) calculated according to the actual number of days worked (iii) that are not incentive-based must be included in the calculation of “ordinary wages.” The Supreme Court further ruled that in spite of invalidity of such agreements, employees shall not retroactively claim additional wages incurred due to such court decision, in case that such claims bring to employees unexpected benefits which substantially exceeds the wage level agreed by employers and employees and cause an unpredicted increase in expenditures for their company, which would lead the company to material managerial difficulty or would be a threat to the existence of the company. In that case, the claim is not acceptable since it is unjust and is in breach of the principle of good faith.

As a result of such ruling by the Supreme Court of Korea, we and our subsidiaries became subject to a number of lawsuits filed by various industry-wide and company-specific labor unions based on claims that ordinary wage had been paid without including certain items that should have been included as ordinary wage. In July 2016, the court ruled against us, and in accordance with the court’s ruling, in August 2016 we paid Won 55.1 billion to the employees for three years of back pay plus interest. As of December 31, 2020,

 

23


Table of Contents

22 lawsuits were pending against our subsidiaries for an aggregate claim amount of Won 45 billion, for which our subsidiaries set aside an aggregate amount of Won 8.3 billion to cover any potential future payments of additional ordinary wage in relation to the related lawsuits. We cannot presently assure you that the court will not rule against our subsidiaries in these lawsuits, or that the foregoing reserve amount will be sufficient to cover the amounts payable under the court rulings.

Additionally, since the issue of determining which labor costs should be additionally included as part of ordinary wages has not been fully resolved by the courts reviewing the lawsuits to which our subsidiaries are a party and other ordinary wage lawsuits filed against other companies, we cannot presently assure you that there will not be additional lawsuits in relation to ordinary wages and that we or our subsidiaries may not become liable for greater amount of damages as a result of these lawsuits. Furthermore, court decisions or labor legislations expanding the definition of ordinary wages may prospectively increase the labor costs of us and our subsidiaries. As a result, there can be no assurance that the above-described lawsuits and circumstances will not have a material adverse effect on our results of operations. See Item 8.A. “Consolidated Statements and Other Financial Information—Legal Proceedings.”

We are subject to cyber security risk.

Recently, our activities have been subject to an increasing risk of cyber-attacks and information leakages, the nature of which is continually evolving. For example, in December 2014, KHNP became subject to a cyber terror incident. Hackers hacked into the computer network of former KHNP employees and threatened to shut down certain of KHNP’s nuclear plants, even though such incident did not jeopardize our nuclear operation in any material respect and none of the stolen information was material to our nuclear operation or the national nuclear policy. Also, even though past cyber-attacks were mostly unspecified attacks, recent attacks are more targeted and intelligent attacks, such as a ransomware that encrypts a victim’s files, whereupon an attacker demands a ransom from the victim to restore access to the victim’s data upon payment. In particular, non-face-to-face business environment due to COVID-19 has led to more sophisticated phishing e-mail attacks that impersonate service providers and acquaintances. In light of the new developments, there is no assurance that a similar or more serious hacking or other forms of cyber terror will not happen with respect to us and our generation subsidiaries, which could have a material adverse impact on our business, financial condition and results of operations.

See Item 4.B. “Business Overview—Cyber Security.”

We previously engaged in limited activities relating to Iran and may become subject to sanctions under relevant laws and regulations of the United States and other jurisdictions as a result of such activities, which may adversely affect our business and reputation.

The U.S. Department of the Treasury’s Office of Foreign Assets Control, or OFAC, administers and enforces certain laws and regulations (which we refer to as the OFAC sanctions) that impose restrictions upon activities or transactions within U.S. jurisdiction with certain countries, governments, entities and individuals that are the subject of OFAC sanctions, including Iran. Even though non-U.S. persons generally are not directly bound by OFAC sanctions, in recent years OFAC has asserted that such non-U.S. persons can be held liable on various legal theories if they engage in transactions completed in part in the United States or by U.S. persons (such as, for example, wiring an international payment that clears through a bank branch in New York). The European Union also enforces certain laws and regulations that impose restrictions upon nationals and entities of, and business conducted in, member states with respect to activities or transactions with certain countries, governments, entities and individuals that are the subject of such laws and regulations, including Iran. The United Nations Security Council and other governmental entities also impose similar sanctions.

In addition to the OFAC sanctions described above, the United States also maintains indirect sanctions under authority of, among others, the Iran Sanctions Act, the Comprehensive Iran Sanctions,

 

24


Table of Contents

Accountability and Divestment Act of 2010, or CISADA, the National Defense Authorization Act for Fiscal Year 2012, or the NDAA, the Iran Threat Reduction and Syria Human Rights Act of 2012, or ITRA, various Executive Orders, the Iran Freedom and Counter-Proliferation Act of 2012, or IFCA, and the Countering America’s Adversaries Through Sanctions Act, or CAATSA. These indirect sanctions, which we refer to collectively as U.S. secondary sanctions, provide authority for the imposition of U.S. sanctions on foreign parties that provide services in support of certain Iran-related activities.

On July 14, 2015, the so-called “P5+1” powers (consisting of the United States, the United Kingdom, Germany, France, Russia, and China) and the European Union, or the EU, entered into an agreement with Iran known as the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA. The JCPOA was intended to significantly restrict Iran’s ability to develop and produce nuclear weapons. Upon implementation of the JCPOA on January 16, 2016 the United States, the EU, and the UN suspended certain nuclear-related sanctions against Iran following an announcement by the International Atomic Energy Agency that Iran had fulfilled its initial obligations under the JCPOA. Most U.S. secondary sanctions concerning Iran were suspended following January 16, 2016.

However, on May 8, 2018, the U.S. Government announced that it was ending its participation in the JCPOA and that it would take steps to re-impose secondary sanctions targeting Iran. Sanctions that had been lifted pursuant to the JCPOA were re-imposed after two wind down periods; one ending on August 6, 2018 and one ending on November 4, 2018. Since November 4, 2018, sanctions that have been lifted pursuant to the JCPOA have been re-imposed. Consequently, dealings with Iran may now subject foreign parties to U.S. secondary sanctions.

Violations of OFAC sanctions via transactions with a U.S. jurisdictional nexus can result in substantial civil or criminal penalties. A range of sanctions may be imposed on companies that engage in sanctionable activities within the scope of U.S. secondary sanctions, including, among other things, the blocking of any property subject to U.S. jurisdiction in which the sanctioned company has an interest, which could include a prohibition on transactions or dealings involving securities of the sanctioned company or the sanctioned company effectively losing access to the U.S. financial system.

We previously engaged in limited activities relating to Iran, but all of such activities have been terminated upon the withdrawal of the United States from the JCPOA.

Certain institutional investors, including state and municipal governments in the United States and universities, as well as financial institutions, have proposed or adopted initiatives regarding investments in companies that do business with countries that are the target of OFAC sanctions, including Iran. Accordingly, as a result of our historical activities related to Iran, certain investors may not wish to invest in our shares or ADSs or do business with us. As of February 2021, we were listed on the Iowa Public Employees’ Retirement System’s (IPERS) Iran Prohibited Companies List. Such divestment initiatives and the decision not to invest in, or to divest from our shares or ADSs may have a material negative impact our reputation and the value of our shares or ADSs.

Violations of sanctions can result in penalties or other consequences adverse to us. Certain of our counterparties may be subjected to sanctions. If we violate sanctions, we may ourselves be subjected to sanctions or penalties. Our business and results of operations may be adversely affected or we may suffer reputational damage. In addition, such sanctions may prevent us from consummating or continuing any of the projects we previously pursued in Iran, which could adversely affect our results of operations. Our Iranian branch initiated closing procedure in 2018 and completed all necessary steps except for the Companies Registration Office Tehran to post our closing on the official gazette. At any time, certain investors may divest their interests in our shares if we are found to have violated or are suspected of violating applicable sanctions law arising from our operation in a sanctioned country.

 

25


Table of Contents

We purchase goods and services from Russia and those activities may be adversely impacted in a material manner by economic sanctions concerning Russia imposed by the United States and other jurisdictions.

The United States and the European Union have imposed economic sanctions concerning Russia. OFAC sanctions concerning Russia, inter alia, block the property of certain designated individuals and entities, target certain sectors of the Russian economy and prohibit certain transactions with certain targeted persons in targeted sectors of the Russian economy, and restrict investment in and trade with the Crimea region of Ukraine. Additionally, non-U.S. persons that engage in certain prohibited transactions concerning Russia or with certain sanctioned Russian persons or entities may be subject to secondary sanctions. In August 2017, the United States Congress passed CAATSA, which introduced a host of new U.S. secondary sanctions concerning Russia including, inter alia, for certain dealings with the Russian energy sector, support for Russia’s energy export pipelines and engaging in a “significant transaction” with a person that is part of, or operates for or on behalf of, Russia’s defense or intelligence sectors. Additionally, a non-U.S. person that knowingly facilitates a “significant transaction” or transactions for or on behalf of any person subject to sanctions imposed by the U.S. with respect to the Russian Federation or any child, spouse, parent, or sibling of such a sanctioned person may also be subject to secondary sanctions.

In 2020, we purchased 13.6% of our bituminous coal requirements from Russia. Additionally, we also purchase conversion and enrichment services of uranium concentrates from a Russian supplier. In 2020, the total value of all goods and services purchased from Russia was approximately US$0.8 billion.

The extent to which the recent coronavirus (COVID-19) outbreak impacts our business, results of operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.

The rapid and diffuse spread of the recent coronavirus (COVID-19) and global health concerns relating to this outbreak have had severe negative impact on, among other things, financial markets, liquidity, economic conditions and trade and could continue to do so or could worsen for an unknown period of time, which could in turn have a material adverse impact on our business, results of operations and financial condition. Although a number of governments and organizations project GDP growth forecasts for 2021 to reflect the economic recovery after the COVID-19 vaccines are being rolled out both domestically and internationally, it is possible that the prolonged COVID-19 will cause a recession depending on the timeliness and effectiveness of actions taken or not taken to contain and mitigate the effects of COVID-19 both in Korea and internationally by governments, central banks, healthcare providers, health system participants, other businesses and individuals. The effects on the economy are still highly uncertain and cannot be predicted. Risks associated with a prolonged outbreak of COVID-19 include:

 

   

disruption in the normal operations of our industrial and commercial customers, which in turn may decrease demand for electricity for such uses;

 

   

the likelihood that the Government may not increase our tariff in a timely manner in an effort to ease the burden on the public, which will lead to a decrease in our revenue;

 

   

an increase in unemployment among, and/or decrease in disposable income of, Korean consumers, which may decrease demand for electricity for residential use and the products and services of our industrial and commercial customers, thereby also leading to a decrease in demand for electricity for such uses;

 

   

disruption in the supply of fuel and equipment from our suppliers;

 

   

disruptions or delays in the construction of new generation facilities or maintenance and refurbishment of existing generation facilities;

 

   

disruption in the normal operations of our business resulting from contraction of COVID-19 by our employees, which may necessitate our employees to be quarantined and/or our generation facilities or offices to be temporarily shut down;

 

26


Table of Contents
   

disruption resulting from the necessity for social distancing, including implementation of temporary adjustment of work arrangements requiring employees to work remotely, which may lead to a reduction in labor productivity;

 

   

depreciation of the Won against major foreign currencies, which in turn may increase the cost of imported raw materials and equipment;

 

   

unstable global and Korean financial markets, which may adversely affect our ability to meet our funding needs on a timely and cost-effective basis;

 

   

significant or extended incline in the prices of LNG, which may lead to the replacement of thermal generation with LNG-combined cycle generation; and

 

   

impairments in the fair value of our investments in companies that may be adversely affected by the pandemic.

In addition to the factors listed above, the Government may enact emergency measures such as electricity tariff adjustments to ease the burden on the economically disadvantaged customers, each of which could have an adverse impact on our financial condition, results of operations, and cash flows. Each of and any combination of the factors listed above and the emergency governmental measures could have an adverse impact on our financial conditions, results of operations and cash flows.

Risks Relating to Korea and the Global Economy

Unfavorable financial and economic conditions in Korea and globally may have a material adverse impact on us.

We are incorporated in Korea, where most of our assets are located and most of our income is generated. As a result, we are subject to political, economic, legal and regulatory risks specific to Korea, and our business, results of operations and financial condition are substantially dependent on the Korean consumers’ demand for electricity, which are in turn largely dependent on developments relating to the Korean economy.

The Korean economy is closely integrated with, and is significantly affected by, developments in the global economy and financial markets. In recent years, adverse conditions and volatility in the worldwide financial markets, fluctuations in oil and commodity prices and the general weakness of the global economy have contributed to the uncertainty of global economic prospects in general and have adversely affected, and may continue to adversely affect, the Korean economy, which in turn could adversely affect our business, financial condition and results of operations. As the Korean economy is highly dependent on the health and direction of the global economy, the prices of our securities may be adversely affected by investors’ reactions to developments in other countries. In addition, due to the ongoing volatility in the global financial markets, the value of the Won relative to the U.S. dollar has also fluctuated significantly in recent years, which in turn also may adversely affect our financial condition and results of operations.

Factors that determine economic and business cycles in the Korean or global economy are for the most part beyond our control and inherently uncertain. In light of the high level of interdependence of the global economy, any of the foregoing developments could have a material adverse effect on the Korean economy and financial markets, and in turn on our business and profitability.

More specifically, factors that could have an adverse impact on Korea’s economy in the future include, among others:

 

   

the global uncertainty and economic recession caused by the novel coronavirus (COVID-19) and its likelihood to further spread in the general population and stifle Korea’s economic activities and also those of the other countries that have economic ties with Korea;

 

27


Table of Contents
   

increases in inflation levels, volatility in foreign currency reserve levels, commodity prices (including oil prices), exchange rates (particularly against the U.S. dollar), interest rates, stock market prices and inflows and outflows of foreign capital, either directly, into the stock markets, through derivatives or otherwise, including as a result of increased uncertainty in the wake of the United Kingdom’s formal exit from the European Union on January 31, 2020, commonly known as “Brexit”;

 

   

difficulties in the financial sectors in Europe, China and elsewhere and increased sovereign default risks in certain countries and the resulting adverse effects on the global financial markets;

 

   

adverse developments in the economies of countries and regions to which Korea exports goods and services (such as the United States, Europe, China and Japan), or in emerging market economies in Asia or elsewhere that could result in a loss of confidence in the Korean economy, including potentially as a result of the Brexit;

 

   

potential escalation of the ongoing trade war between the U.S. and China as each country introduces tariffs on goods traded with the other;

 

   

social and labor unrest or declining consumer confidence or spending resulting from lay-offs, increasing unemployment and lower levels of income;

 

   

uncertainty and volatility and further increases in the market prices of Korean real estate;

 

   

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

 

   

political uncertainty, including as a result of increasing strife among or within political parties in Korea, and political gridlock within the government or in the legislature, which prevents or disrupts timely and effective policy making to the detriment of Korean economy, as well as the impeachment and indictment of the former president following a series of scandals and social unrest, which also involved the investigation of several leading Korean conglomerates and arrest of their leaders on charges of bribery and other possible misconduct;

 

   

deterioration in economic or diplomatic relations between Korea and its trading partners or allies, including deterioration resulting from territorial or trade disputes or disagreements in foreign policy, including as a result of any potential renegotiation of free trade agreements;

 

   

increases in social expenditures to support the aging population in Korea or decreases in economic productivity due to the declining population size in Korea;

 

   

any other development that has a material adverse effect in the global economy, such as an act of war, the spread of terrorism or a breakout of an epidemic such as SARS, avian flu, swine flu, Middle East Respiratory Syndrome, Ebola or Zika virus, or natural disasters, earthquakes and tsunamis and the related disruptions in the relevant economies with global repercussions;

 

   

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

 

   

an increase in the level of tensions or an outbreak of hostilities in the Korean peninsula or between North Korea and the United States.

Any future deterioration of the Korean economy could have an adverse effect on our business, financial condition and results of operations.

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 the two Koreas has fluctuated and may increase abruptly as a result of current and future events.

 

28


Table of Contents

In particular, there continues to be uncertainty regarding the long-term stability of North Korea’s political leadership since the succession of Kim Jong-un to power following the death of his father in December 2011, which has raised concerns with respect to the political and economic future of the region. In February 2017, Kim Jong-un’s half-brother, Kim Jong-nam, was reported to have been assassinated in an international airport in Malaysia.

In addition, there continues to be heightened security tension in the region stemming from North Korea’s hostile military and diplomatic actions, including in respect of its nuclear weapons and long-range missile programs. Some examples from recent years include the following:

 

   

In November 2017, North Korea conducted a test launch of another intercontinental ballistic missile, which, due to its improved size, power and range of distance, may potentially enable North Korea to target the United States mainland.

 

   

Recently, on September 3, 2017, North Korea conducted its sixth nuclear test, claiming it had tested a hydrogen bomb that could be mounted on an intercontinental ballistic missile. In response, on September 12, 2017, the United Nations Security Council unanimously adopted a resolution imposing additional sanctions on North Korea including new limits on gas, petrol and oil imports, a ban on textile exports and measures to limit North Korean laborers from working abroad.

 

   

On August 29, 2017, North Korea tested an intermediate-range ballistic missile which flew directly over northern Japan before landing in the Pacific Ocean. In response, the United Nations Security Council unanimously adopted a statement condemning such launch, reiterating demands that North Korea halt its ballistic missile and nuclear weapons programs.

 

   

On July 4, 2017, North Korea tested its first intercontinental ballistic missile. In response, the U.S. government and the Government both issued statements condemning North Korea and conducted a joint military exercise on July 5, 2017. On July 28, 2017, North Korea tested a second intercontinental ballistic missile which landed in the Sea of Japan, inside Japan’s Economic Exclusion Zone. In response, on August 5, 2017, the United Nations Security Council unanimously adopted a resolution that strengthened sanctions on North Korea. The resolution includes a total ban on all exports of coal, iron, iron ore, lead, lead ore and seafood, which is expected to reduce North Korea’s export revenue by a third each year.

 

   

In March 2017, North Korea launched four mid-range missiles, which landed off the east coast of the Korean peninsula.

 

   

On September 9, 2016, North Korea conducted its fifth nuclear test, which has been the largest in scale among North Korea’s nuclear tests thus far. According to North Korean announcements, the test was successful in detonating a nuclear missile. The test created a sizable earthquake in South Korea. In response, in February 2017 the U.N. Security Council adopted Resolution 2321 (2016) against North Korea, the purpose of which is to strengthen its sanctions regime against North Korea and to condemn North Korea’s September 9, 2016 nuclear test in the strongest terms.

 

   

On February 10, 2016, in retaliation of North Korea’s recent launch of a long-range rocket, South Korea announced that it would halt its operations of the Kaesong Industrial Complex to impede North Korea’s utilization of funds from the industrial complex to finance its nuclear and missile programs. In response, North Korea announced on February 11, 2016 that it would expel all South Korean employees from the industrial complex and freeze all South Korean assets there.

 

   

On February 7, 2016, North Korea launched a rocket, claimed by them to be carrying a satellite intended for scientific observation. The launch was widely suspected by the international community to be a cover for testing a long-range missile capable of carrying a nuclear warhead. On February 18, 2016, the President of the United States signed into law mandatory sanctions on North Korea to punish it for its recent nuclear and missile tests, human rights violations and cybercrimes. The bill, which marks the first measure by the United States to exclusively target North Korea, is intended to seize the

 

29


Table of Contents
 

assets of anyone engaging in business related to North Korea’s weapons program, and authorizes US$50 million over five years to transmit radio broadcasts into the country and support humanitarian assistance projects. On March 2, 2016, the United Nations Security Council voted unanimously to adopt a resolution to impose sanctions against North Korea, which include inspection of all cargo going to and from North Korea, a ban on all weapons trade and the expulsion of North Korean diplomats who engage in “illicit activities.” Also, on March 4, 2016, the European Union announced that it would expand its sanctions on North Korea, adding additional companies and individuals to its list of sanction targets. On April 1, 2016, North Korea fired a short-range surface-to-air missile in apparent protest of these sanctions adopted by the United States and the United Nations Security Council.

 

   

On January 6, 2016, North Korea announced that it had successfully conducted its first hydrogen bomb test, hours after international monitors detected a 5.1 magnitude earthquake near a known nuclear testing site in the country. The claims have not been verified independently. The alleged test followed a statement made in the previous month by Kim Jong-un, who claimed that North Korea had developed a hydrogen bomb.

 

   

In August 2015, two Korean soldiers were injured in a landmine explosion near the South Korean demilitarized zone. Claiming the landmines were set by North Koreans, the South Korean army re-initiated its propaganda program toward North Korea utilizing loudspeakers near the demilitarized zone. In retaliation, the North Korean army fired artillery rounds on the loudspeakers, resulting in the highest level of military readiness for both Koreas. High-ranking officials from North and South Korea subsequently met for discussions and entered into an agreement on August 25, 2015 intending to deflate military tensions.

 

   

From time to time, North Korea has fired short- to medium-range missiles from the coast of the Korean peninsula into the sea. In March 2015, North Korea fired seven surface-to-air missiles into waters off its east coast in apparent protest of annual joint military exercises being held by Korea and the United States.

 

   

North Korea renounced its obligations under the Nuclear Non-Proliferation Treaty in January 2003 and conducted three rounds of nuclear tests between October 2006 to February 2013, which increased tensions in the region and elicited strong objections worldwide. In response, the United Nations Security Council unanimously passed resolutions that condemned North Korea for the nuclear tests and expanded sanctions against North Korea.

North Korea’s economy also faces severe challenges, including severe inflation and food shortages, which may further aggravate social and political tensions within North Korea. In addition, reunification of Korea and North Korea could occur in the future, which would entail significant economic commitment and expenditure by Korea that may outweigh any resulting economic benefits of reunification. On April 27, 2018, May 26, 2018 and September 18, 2018, President Moon Jae-in met Kim Jong-un in a summit to discuss, among other matters, denuclearization of the Korean Peninsula. On June 12, 2018, President Donald Trump and Kim Jong-un in turn had an official summit in Singapore and on February 27, 2019, the parties held the second official summit in Hanoi, Vietnam. However, in March 2019, announcement was made that no agreement was reached in the second bilateral summit meeting between the United States and North Korea. On June 30 2019, for the first time, President Moon Jae-in, President Donald Trump and Kim Jong-un met in Panmunjom, a symbolic place of division in Korea, and the parties agreed to resume the United States and North Korea working-level negotiations, and on October 4, 2019, such working-level negotiations took place in Stockholm, Sweden. However, the negotiations did not result in any definitive agreement or any follow-up plans. On June 16, 2020, North Korea destroyed the joint liaison office in Kaesong, citing anti-regime propaganda allegedly disseminated using balloons across the border by Korean activists, and cut all other communication channels with Korea.

There can be no assurance that the level of tension on 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

 

30


Table of Contents

diplomatic negotiations over the North Korean nuclear program, occurrence of military hostilities, heightened concerns about the stability of North Korea’s political leadership or its actual collapse, a leadership crisis, a breakdown of high-level contacts or accelerated reunification could have a material adverse effect on our business, financial condition and results of operations, as well as the price of our common shares and our American depositary shares.

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. We and our generation subsidiaries are also subject to a number of special laws and regulations to Government-controlled entities, including the Act on the Management of Public Institutions. 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.

You may not be able to enforce a judgment of a foreign court against us.

We are a corporation with limited liability organized under the laws of Korea. Substantially all of our directors and officers and other persons named in this annual report reside in Korea, and all or a significant portion of the assets of our directors and officers and other persons named in this annual report and substantially all of our assets are located in Korea. As a result, it may not be possible for holders of the American depository shares to affect service of process within the United States, or to enforce against them or us in the United States judgments obtained in United States courts based on the civil liability provisions of the federal securities laws of the United States. There is doubt as to the enforceability in Korea, either in original actions or in actions for enforcement of judgments of United States courts, of civil liabilities predicated on the United States federal securities laws.

Risks Relating to Our American Depositary Shares (ADSs)

There are restrictions on withdrawal and deposit of common shares under the depositary facility.

Under the deposit agreement, holders of shares of our common stock may deposit those shares with the depositary bank’s custodian in Korea and obtain American depositary shares, and holders of American depositary shares may surrender American depositary shares to the depositary bank and receive shares of our common stock. However, under current Korean laws and regulations, the depositary bank is required to obtain our prior consent for the number of shares to be deposited in any given proposed deposit which exceeds the difference between (i) the aggregate number of shares deposited by us for the issuance of American depositary shares (including deposits in connection with the initial and all subsequent offerings of American depositary shares and stock dividends or other distributions related to these American depositary shares) and (ii) the number of shares on deposit with the depositary bank at the time of such proposed deposit. We have consented to the deposit of outstanding shares of common stock as long as the number of American depositary shares outstanding at any time does not exceed 80,153,810 shares. As a result, if you surrender American depositary shares and withdraw shares of common stock, you may not be able to deposit the shares again to obtain American depositary shares.

 

31


Table of Contents

Ownership of our shares is restricted under Korean law.

Under the Financial Investment Services and Capital Markets Act, with certain exceptions, a foreign investor may acquire shares of a Korean company without being subject to any single or aggregate foreign investment ceiling. As one such exception, certain designated public corporations, such as us, are subject to a 40% ceiling on acquisitions of shares by foreigners in the aggregate. The Financial Services Commission may impose other restrictions as it deems necessary for the protection of investors and the stabilization of the Korean securities and derivatives market.

In addition to the aggregate foreign investment ceiling set out under the Financial Investment Services and Capital Markets Act, our Articles of Incorporation set a 3% ceiling on acquisition by a single investor (whether domestic or foreign) of the shares of our common stock. Any person (with certain exceptions) who holds our issued and outstanding shares in excess of such 3% ceiling cannot exercise voting rights with respect to our shares exceeding such limit.

The ceiling on aggregate investment by foreign investors applicable to us may be exceeded in certain limited circumstances, including as a result of acquisition of:

 

   

shares by a depositary issuing depositary receipts representing such shares (whether newly issued shares or outstanding shares);

 

   

shares by exercise of warrant, conversion right under convertible bonds, exchange right under exchangeable bonds or withdrawal right under depositary receipts issued outside of Korea;

 

   

shares from the exercise of shareholders’ rights; or

 

   

shares by gift, inheritance or bequest.

A foreign investor who has acquired our shares in excess of any ceiling described above may not exercise his voting rights with respect to our shares exceeding such limit and the Financial Services Commission may take necessary corrective action against him.

Holders of our ADSs will not have preemptive rights in certain circumstances.

The Korean Commercial Act and our Articles of Incorporation require us, with some exceptions, to offer shareholders the right to subscribe for new shares in proportion to their existing ownership percentage whenever new shares are issued. If we offer any rights to subscribe for additional shares of our common stock or any rights of any other nature, the depositary bank, after consultation with us, may make the rights available to you or use reasonable efforts to dispose of the rights on your behalf and make the net proceeds available to you. The depositary bank, however, is not required to make available to you any rights to purchase any additional shares unless it deems that doing so is lawful and feasible and:

 

   

a registration statement filed by us under the U.S. Securities Act of 1933, as amended, is in effect with respect to those shares; or

 

   

the offering and sale of those shares is exempt from or is not subject to the registration requirements of the U.S. Securities Act.

We are under no obligation to file any registration statement with the U.S. Securities and Exchange Commission in relation to the registration rights. If a registration statement is required for you to exercise preemptive rights but is not filed by us, you will not be able to exercise your preemptive rights for additional shares and you will suffer dilution of your equity interest in us.

The market value of your investment in our ADSs may fluctuate due to the volatility of the Korean securities market.

Our common stock is listed on the KRX KOSPI Division of the Korea Exchange, which has a smaller market capitalization and is more volatile than the securities markets in the United States and many European

 

32


Table of Contents

countries. The market value of ADSs may fluctuate in response to the fluctuation of the trading price of shares of our common stock on the Stock Market Division of the Korea Exchange. The Stock Market Division of the Korea Exchange has experienced substantial fluctuations in the prices and volumes of sales of listed securities and the Stock Market Division of the Korea Exchange has prescribed a fixed range in which share prices are permitted to move on a daily basis. Like other securities markets, including those in developed markets, the Korean securities market has experienced problems including market manipulation, insider trading and settlement failures. The recurrence of these or similar problems could have a material adverse effect on the market price and liquidity of the securities of Korean companies, including our common stock and ADSs, in both the domestic and the international markets.

The Korean government has the ability to exert substantial influence over many aspects of the private sector business community, and in the past has exerted that influence from time to time. For example, the Korean government has promoted mergers to reduce what it considers excess capacity in a particular industry and has also encouraged private companies to publicly offer their securities. Similar actions in the future could have the effect of depressing or boosting the Korean securities market, whether or not intended to do so. Accordingly, actual or perceived actions or inactions by the Korean government may cause sudden movements in the market prices of the securities of Korean companies in the future, which may affect the market price and liquidity of our common stock and ADSs.

Your dividend payments and the amount you may realize in connection with a sale of your ADSs will be affected by fluctuations in the exchange rate between the U.S. dollar and the Won.

Investors who purchase the American depositary shares will be required to pay for them in U.S. dollars. Our outstanding shares are listed on the Korea Exchange and are quoted and traded in Won. Cash dividends, if any, in respect of the shares represented by the American depositary shares will be paid to the depositary bank in Won and then converted by the depositary bank into U.S. dollars, subject to certain conditions. Accordingly, fluctuations in the exchange rate between the Won and the U.S. dollar will affect, among other things, the amounts a registered holder or beneficial owner of the American depositary shares will receive from the depositary bank in respect of dividends, the U.S. dollar value of the proceeds which a holder or owner would receive upon sale in Korea of the shares obtained upon surrender of American depositary shares and the secondary market price of the American depositary shares.

If the Government deems that certain emergency circumstances are likely to occur, it may restrict the depositary bank from converting and remitting dividends in U.S. dollars.

Under the Foreign Exchange Transaction Act, if the Government deems that certain emergency circumstances are likely to occur, it may impose restrictions such as requiring foreign investors to obtain prior Government approval for the acquisition of Korean securities or for the repatriation of interest or dividends arising from Korean securities or sales proceeds from disposition of such securities. These emergency circumstances include any or all of the following:

 

   

sudden fluctuations in interest rates or exchange rates;

 

   

extreme difficulty in stabilizing the balance of payments; and

 

   

a substantial disturbance in the Korean financial and capital markets.

The depositary bank may not be able to secure such prior approval from the Government for the payment of dividends to foreign investors when the Government deems that there are emergency circumstances in the Korean financial markets.

 

33


Table of Contents
ITEM 4.

INFORMATION ON THE COMPANY

Item 4.A. History and Development of the Company

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 Act (the “KEPCO Act”) as the successor to Korea Electric Company. Our registered office is located at 55 Jeollyeok-ro, Naju-si, Jeollanam-do, 58322, Korea, and our telephone number is 82-61-345-4213. Our website address is www.kepco.co.kr.

Our agent in the United States is Korea Electric Power Corporation, North America Office, located at 7th Floor, Parker Plaza, 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 was 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% of our common stock. As of December 31, 2020, the Government maintained 51.1% ownership in aggregate of our common shares by direct holdings by the Government and indirect holdings through Korea Development Bank, a statutory banking institution wholly owned by the Government.

Under relevant laws of Korea, the Government is required to own, directly or indirectly, at least 51% of our capital. Direct or indirect ownership of more than 50% of our outstanding common voting stock enables the Government to control the approval of certain corporate matters relating to us that require a shareholders’ 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 Trade, Industry and Energy, based on the Government’s ownership of our common stock and a proxy received from Korea Development Bank, in consultation with the Ministry of Economy and Finance.

We operate under the general supervision of the Ministry of Trade, Industry and Energy. The Ministry of Trade, Industry and Energy, in consultation with the Ministry of Economy and Finance, is responsible for approving, subject to review by the Korea Electricity Commission, the electricity rates we charge our customers. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.” We furnish reports to officials of the Ministry of Trade, Industry and Energy, the Ministry of Economy and Finance and other Government agencies and regularly consult with such officials on matters relating to our business and affairs. See Item 4.B. “Business Overview—Regulation.” Our non-standing directors, who comprise a majority of our board of directors, must be appointed by the Ministry of Economy and Finance following the review and resolution of the Committee for Management of Public Institutions (which is established by law and chaired by the minister of the Ministry of Economy and Finance and whose members consist of Government officials and others appointed by the President of the Republic based on recommendation by the minister of the Ministry of Economy and Finance) from a pool of candidates recommended by the director nomination committee. Our president and standing directors who concurrently serve as members of our audit committee must be appointed by the President of the Republic upon the motion of the minister of the Ministry of Trade, Industry and Energy (in the case of our president) and the minister of the Ministry of Economy and Finance (in the case of our standing director who concurrently serves as a member of the audit committee) and following the nomination by our director nomination committee, the review and resolution of the Committee for Management of Public Institutions and an approval at the general meeting of shareholders. See Item 6.A. “Directors and Senior Management—Board of Directors” and Item 16G. “Corporate Governance—The Act on the Management of Public Institutions.”

 

34


Table of Contents

Item 4.B. 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 wholly-owned generation subsidiaries, we also generate the substantial majority of electricity produced in Korea. As of December 31, 2020, we and our generation subsidiaries owned approximately 64.9% of the total electricity generation capacity in Korea (excluding plants generating electricity primarily for private or emergency use). In 2020, we sold to our customers 509,270 gigawatt-hours of electricity. We purchase electricity principally from our generation subsidiaries and, to a lesser extent, from independent power producers. Of the 515,203 gigawatt-hours of electricity we purchased in 2020, 30.4% was generated by KHNP, our wholly-owned nuclear and hydroelectric power generation subsidiary, 42.2% was generated by our wholly-owned five non-nuclear generation subsidiaries and 27.4% was generated by independent power producers that trade electricity to us through the cost-based pool system of power trading (excluding independent power producers that supply electricity under power purchase agreements with us). Our five non-nuclear generation subsidiaries are KOSEP, KOMIPO, KOWEPO, KOSPO and EWP, each of which is wholly owned by us and is incorporated in Korea. We derive substantially all of our revenues and profit from Korea, and substantially all of our assets are located in Korea.

In 2020, we had sales of Won 57,926 billion and net profit of Won 2,093 billion, compared to sales of Won 58,568 billion and net loss of Won 2,264 billion in 2019.

Our revenues are closely tied to demand for electricity in Korea. Demand for electricity in Korea increased at a compounded average growth rate of 0.6% per annum from 2016 to 2020, compared to the real gross domestic product, or GDP, which increased at a compounded average growth rate of 1.7% during the same period, according to the Bank of Korea. During 2020, the GDP growth rate was -1.0%, while the demand for electricity in Korea during the same year decreased by 2.2%.

Strategy

As our overall strategy, we seek to become a leading global energy enterprise by actively responding to the market’s demand for a stable supply of clean, safe, affordable and convenient source of energy. To this end, we plan to develop key competencies needed for digital transformation of our operations and energy transition. We also aim to strengthen competitiveness in our core operations and to develop new businesses and markets by focusing on low-carbon and renewable energy projects. We evaluate and renew our mid- to long-term strategy every three years, and in 2019 established the “Vision 2030 Mid- to Long-Term Strategy.” Under this vision, we will aim for sustainable growth of our operations through the supply of clean energy as well as balanced new industry initiatives with growth potential.

 

   

Expand clean energy and stabilize electricity supply and demand. We plan to contribute to the Government’s Nationally Determined Contributions (NDCs) by reducing greenhouse gas emissions from our generation subsidiaries and leading large-scale projects to promote the use of renewable energy. In addition, we will focus on ensuring smooth and stable connection for the renewable energy as part of our energy networks. We will also seek to enhance the efficiency of our electricity networks through the use of advanced technology.

 

   

Enhance sales profitability and competitiveness. We will seek to become a market leader through the development of customized tariffs and new services. We will also maintain profitability through the cost-based tariff system and improve the demand-side efficiency to streamline energy use at the national level.

 

   

Explore convergence-based new businesses and markets. We plan to selectively focus on and pursue profitable new businesses through in-depth market analysis (considering the market environment and our capabilities) to build a business ecosystem. In connection with our overseas business, we plan to explore opportunities to develop low-carbon, renewable energy to expand our market and to diversify our portfolio and provide suitable solutions meeting the different needs of various countries.

 

35


Table of Contents
   

We will focus on R&D and commercialization of technologies essential to achieving our strategy. We will also create a platform for developing new businesses and enhance the efficiency of our operations based on digital technology.

 

   

In order to develop a management system suitable for sustainable growth, we will continue to develop sound corporate governance, financial structure and human resources. In addition, we will continue to implement the environment, health and safety management system and focus on fostering shared social values and growth with local communities.

Government Ownership and Our Interactions with the Government

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 voting stock enables the Government to control the approval of certain corporate matters which require a shareholders’ 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 Trade, Industry and Energy in consultation with the Ministry of Economy and Finance. We are currently not aware of any plans of the Government to cease to own, directly or indirectly, at least 51% of our outstanding common stock.

We play an important role in the implementation of the Government’s national energy policy, which is established in consultation with us, among other parties. As an entity formed to serve public policy goals of the Government, we seek to maintain a fair level of profitability and strengthen our capital base in order to support the growth of our business in the long term.

The Government, through its various policy initiatives for the Korean energy industry as well as direct and indirect supervision of us and our industry, plays an important role in our business and operations. Most importantly, the electricity tariff rates we charge to our customers are regulated by the Government taking into account, among others, our needs to recover the costs of operations, make capital investments and recoup a fair return on capital invested by us, as well as the Government’s overall policy considerations, such as inflation. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.”

In addition, pursuant to the Basic Plan determined by the Government, we and our generation subsidiaries have made, and plan to make, substantial expenditures for the construction of generation plants and other facilities to meet demand for electric power. See Item 5.B. “Liquidity and Capital Resources—Capital Requirements.”

Restructuring of the Electric Power Industry in Korea

On January 21, 1999, the Ministry of Trade, Industry and Energy published the Restructuring Plan. The overall objectives of the Restructuring Plan consisted of: (i) introducing competition and thereby increasing efficiency in the Korean electric power industry, (ii) ensuring a long-term, inexpensive and stable electricity supply, and (iii) promoting consumer convenience through the expansion of consumer choice.

The following provides further details relating to the Restructuring Plan.

Phase I

During Phase I, which served as a preparatory stage for Phase II and lasted from the announcement of the Restructuring Plan in January 1999 until April 2001, we undertook steps to split our generation business units off into one wholly-owned nuclear generation subsidiary (namely, KHNP) and five wholly-owned non-nuclear generation subsidiaries (namely, KOSEP, KOMIPO, KOWEPO, KOSPO and EWP), each with its own management structure, assets and liabilities. These steps were completed upon approval at our shareholders’ meeting in April 2001.

 

36


Table of Contents

The Government’s principal objectives in the split-off of the generation units into separate subsidiaries were to: (i) introduce competition and thereby increase efficiency in the electricity generation industry in Korea, and (ii) ensure a stable supply of electricity in Korea.

Following the implementation of Phase I, we have substantial monopoly with respect to the transmission and distribution of electricity in Korea.

While our ownership percentage of our generation subsidiaries will depend on further adjustments to the Restructuring Plan to be adopted by the Government, we plan to retain 100% ownership of our transmission and distribution business.

Phase II

At the outset of Phase II in April 2001, the Government introduced a cost-based competitive bidding pool system under which we purchase power from our generation subsidiaries and other independent power producers for transmission and distribution to customers. For a further description of this system, see “—Purchase of Electricity—Cost-based Pool System” below.

Pursuant to the Electric Utility Act amended in December 2000, the Government established the Korea Power Exchange in April 2001. The primary function of the Korea Power Exchange is 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 Korean electric power industry and ensure fair competition among industry participants. To facilitate this goal, 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 Trade, Industry and Energy.

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

Privatization of Generation Subsidiaries

In April 2002, the Ministry of Trade, Industry and Energy released the basic privatization plan for five of our generation subsidiaries other than KHNP. Pursuant to this plan, we commenced the process of selling our equity interest in 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.

In accordance with the Proposal for Adjustment of Functions of Public Institutions (Energy Sector) announced by the Government in June 2016, we considered a sale in the public market of a minority of our shares in our five non-nuclear generation subsidiaries, KEPCO KDN and KHNP gradually. However, the planned sales have been put on hold, primarily due to prevailing market conditions. In any event, we plan to maintain a controlling stake in each of these subsidiaries.

Suspension of the Plan to Form and Privatize Distribution Subsidiaries

In 2003, the Government established a Tripartite Commission consisting of representatives of the Government, leading businesses and labor unions in Korea to deliberate on ways to introduce competition in

 

37


Table of Contents

electricity distribution, such as by forming and privatizing new distribution subsidiaries. In 2004, the Tripartite Commission recommended not pursuing such privatization initiatives but instead creating independent business divisions within us to improve operational efficiency through internal competition. Following the adoption of such recommendation by the Government in 2004 and further studies by Korea Development Institute, in 2006 we created nine “strategic business units” (which, together with our other business units, were subsequently restructured into 14 such units in February 2012) that have a greater degree of autonomy with respect to management, financial accounting and performance evaluation while having a common focus on increasing profitability.

Initiatives to Improve the Structure of Electricity Generation

In August 2010, the Ministry of Trade, Industry and Energy announced the Proposal for Improvement in the Structure of the Electric Power Industry in order to resolve uncertainty related to restructuring plans for the electric power industry and maintain competitiveness of the electric power industry. Key initiatives of the proposal included the following: (i) maintain the current structure of having six generation subsidiaries and designate the six generation subsidiaries as market-oriented public enterprises under the Act on the Management of Public Institutions in order to foster competition among the generation subsidiaries and promote efficiency in their operations, (ii) clarify the scope of the business of us and the six generation subsidiaries (namely, that we shall manage the financial structure and governance of the six generation subsidiaries and nuclear power plant and overseas resources development projects, while the six generation subsidiaries will have greater autonomy with respect to construction and management of generation units and procurement of fuel), (iii) create a nuclear power export business unit to systematically enhance our capabilities to win projects involving the construction and operation of nuclear power plants overseas, (iv) further rationalize the electricity tariff by adopting a fuel-cost based tariff system in 2011 and a voltage-based tariff system in a subsequent year, and (v) create separate accounting systems for electricity generation, transmission, distribution and sales with the aim of introducing competition in electricity sales in the intermediate future. The fuel-cost based tariff system went into effect on July 1, 2011 but the Ministry of Trade, Industry and Energy issued a hold order on July 29, 2011 and subsequently informed us it needs to be reassessed in light of the circumstances.

In January 2011, the Ministry of Economy and Finance created a “joint cooperation unit” consisting of officers and employees selected from the five thermal power generation subsidiaries in order to reduce inefficiencies in areas such as fuel transportation, inventories, materials and equipment and construction, etc. and allow the thermal power generation subsidiaries to continue utilizing the benefits of economy of scale after split off of our generation business units into separate subsidiaries. The purpose of the joint cooperation unit was to give greater autonomy to the generation subsidiaries with regard to power plant construction and management and fuel procurements, and thereby enhance efficiency in operating power plants. The main functions of the joint cooperation unit are as follows: (i) maintain inventories of bituminous coal through volume exchanges and joint purchases, (ii) reduce shipping and demurrage expenses through joint operation and distribution of dedicated vessels, (iii) reduce costs by sharing information on generation material inventories and (iv) sharing human resources among the five thermal power generation subsidiaries for construction projects, among other things.

Furthermore, in January 2011 the six generation subsidiaries were officially designated as “market-oriented public enterprises,” whereupon the President of Korea appoints the president and the statutory auditor of each such subsidiary; the selection of non-standing directors of each such subsidiary is subject to approval by the minister of the Ministry of Economy and Finance; the president of each such subsidiary is required to enter into a management contract directly with the minister of the Ministry of Trade, Industry and Energy; and the Public Enterprise Management Evaluation Team which is established by the Committee for Management of Public Institutions conducts performance evaluation of such subsidiaries. Previously, our president appointed the president and the statutory auditor of each such subsidiary; the selection of non-standing directors of each such subsidiary was subject to approval by our president; the president of each such subsidiary entered into a management contract with our president; and our evaluation committee conducted performance evaluation of such subsidiaries. For further details of the impact of the designation of our generation subsidiaries as “market-

 

38


Table of Contents

oriented public enterprises,” see Item 16.G. “Corporate Governance—The Act on the Management of Public Institutions.”

Proposal for Adjustment of Functions of Public Institutions (Energy Sector)

In June 2016, the Government announced the Proposal for Adjustment of Functions of Public Institutions (Energy Sector) for the purpose of streamlining the operations of government-affiliated energy companies by discouraging them from engaging in overlapping or similar businesses with each other, reducing non-core assets and activities and improving management and operational efficiency. The initiatives contemplated in this proposal that would affect us and our generation subsidiaries include the following: (i) the generation companies should take on greater responsibilities in overseas resource exploration and production projects as these involve procurement of fuels necessary for electricity generation while fostering cooperation among each other through closer coordination, (ii) KHNP should take a greater role in export of nuclear technology, and (iii) the current system of retail sale of electricity to end-users should be liberalized to encourage more competition. In accordance therewith, we transferred a substantial portion of our assets and liabilities in our overseas resource business to our generation subsidiaries as of December 31, 2016. In addition, this Proposal contemplated selling a minority stake in our generation subsidiaries and KEPCO KDN, but the planned sales have been put on hold, as discussed above in “—Privatization of Generation Subsidiaries.”

Proposed Amendment for Direct Participation in Renewable Energy

An amendment to the Electric Utility Act is underway that will enable us to directly participate in the development of renewable power generation. Under the current Electric Utility Act, a single business entity cannot participate in two or more types of electric businesses. The proposed amendment allows a market-type public institution like ourselves to participate in renewable power generation business to a limited degree. The amendment bill was proposed in July 2020 and is now pending deliberation by the Korean national assembly. When the bill passes, we intend to pursue renewable power generation projects such as large-scale offshore wind power.

Purchase of Electricity

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 Electric Utility 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 split-off from us in April 2001, and independent power producers, which numbered 20 (excluding renewable energy producers) as of December 31, 2020. We distribute electricity purchased through the Korea Power Exchange to end users.

Our Relationship with the Korea Power Exchange

The key features of our relationships with the Korea Power Exchange include the following: (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 11 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 do not have control over the Korea Power Exchange or its policies since, among others, (i) the Korea Power Exchange, its personnel, policies, operations

 

39


Table of Contents

and finances are closely supervised and controlled by the Government, namely through the Ministry of Trade, Industry and Energy, and are subject to a host of laws and regulations, including, among others, the Electric Utility Act and the Act on the Management of Public Institutions, 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 Trade, Industry and Energy, 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 in 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.

Pricing Factors

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 the variable cost of generating electricity) and the capacity price (representing the fixed cost of generating electricity).

Under the merit order system, the electricity purchase allocation, the system marginal price (as described below) and the final allocation adjustment are automatically determined based on an objective formula. The variable cost (including the adjusted coefficient as described below) and the capacity price are determined in advance of trading by the Cost Evaluation Committee, which is comprised of representatives from the Ministry of Trade, Industry and Energy, the Korea Power Exchange, us, generation companies, scholars and researchers (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.

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. We currently refer such marginal price as the “system marginal price.”

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 which 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 a forecast made 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, seasonality and on-peak-hour versus off-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. These 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 in its bid, 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 highest price at which electricity can be supplied at a given hour based on the demand and supply for such hour.

 

40


Table of Contents

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 and reflected in the following month based on the fuel costs two months prior to such determination. The purpose of the merit order system is to encourage generation units to reduce its electricity generation costs by making its generation process more efficient, sourcing fuels from most cost-effective sources or adopting other cost savings programs.

The final allocation of electricity supply 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. This adjustment mechanism is designed to adjust for transmission losses in order to improve overall cost-efficiency in the transmission of electricity to end-users.

The 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

An adjusted coefficient applies in principle to all generation units operated by our generation subsidiaries and the coal-fired generation units operated by independent power producers. The adjusted coefficient applicable to the generation units operated by our generation subsidiaries is determined based on considerations of, among others, electricity tariff rates and the relative fair returns on investment in respect of us compared to our generation subsidiaries. The purpose of the adjusted coefficient here is to prevent electricity trading from resulting in undue imbalances as to the relative financial results among generation subsidiaries as well as between us (as the purchaser of electricity) and our generation subsidiaries (as sellers of electricity). Such imbalances may arise from excessive profit taking by base load generators (on account of their inherently cheaper fuel cost structure compared to non-base load generators) as well as from fluctuations in fuel prices (it being the case that during times of rapid and substantial rises in fuel costs which are not offset by corresponding rises in electricity tariff rates charged by us to end-users, on a non-consolidated basis our profitability will decline compared to that our generation subsidiaries since our generation subsidiaries are entitled to sell electricity to us at cost plus a guaranteed margin). In comparison, the adjusted coefficient applicable to the coal-fired generation units operated by independent power producers is determined to enable such independent power producers to recover the total costs of building and operating such units.

The adjusted coefficient is determined by the Cost Evaluation Committee in principle on an annual basis, although in exceptional cases driven by external or structural factors such as rapid and substantial changes in fuel costs, adjustments to electricity tariff rates or changes in the electricity pricing structure, the adjusted coefficient may be adjusted on a quarterly basis.

Previously, it was contemplated that the vesting contract system, as described below, would gradually replace the application of the adjusted coefficient. However, since the implementation of the vesting contract system has been suspended indefinitely, it is unlikely to impact the application of the adjusted coefficient in the foreseeable future.

Capacity Price

In addition to payment in respect of the variable cost of generating electricity, generation units receive payment in the form of capacity price, the purpose of which is to compensate them for the fixed costs of constructing generation facilities, provide incentives for construction of new generation units and maintain reliability of the nationwide electricity transmission network.

The capacity price is determined by the Cost Evaluation Committee as a function of the following factors: (i) reference capacity price, (ii) reserve capacity factor, (iii) time-of-the-day capacity coefficient and (iv) since

 

41


Table of Contents

October 2016, fuel switching factor. The time-of-the-day capacity coefficient are determined annually before the end of December for the subsequent twelve-month period. The reference capacity price, reserve capacity factor and the fuel switching factor are determined annually before the end of June for the subsequent twelve-month period.

The reference capacity price refers to the Won amount per kilowatt-hour payable annually for annualized available capacity indicated in the bids submitted the day before trading (provided that such capacity is actually available on the relevant day of trading), and is determined based on the construction costs and maintenance costs of a standard generation unit and related transmission access facilities, and a base rate for loading electricity. Prior to October 2016, the same reference capacity price applied uniformly to all generation units. Since October 2016, the reference capacity price applies differentially to each generation unit depending on the start year of its commercial operation. Accordingly, the reference capacity price currently ranges from Won 9.62 to 10.65 per kilowatt hour.

The reserve capacity factor relates to the requirement to maintain a standard capacity reserve margin in the range of 13% in order to prevent excessive capacity build-up as well as induce optimal capacity investment at the regional level. The capacity reserve margin is the ratio of peak demand to the total available capacity. Under this system, generation units in a region where available capacity is insufficient to meet demand for electricity as evidenced by failing to meet the standard capacity reserve margin receive increased capacity price. Conversely, generation units in a region where available capacity exceeds demand for electricity as evidenced by exceeding the standard capacity reserve margin receive reduced capacity price. Since October 2016, the reserve capacity factor also factors in the transmission loss per generation unit in order to favor transmission of electricity from a nearby generation unit.

The time-of-the-day capacity coefficient allows hourly and seasonal adjustments in order to incentivize our generation subsidiaries to operate their generation facilities at full capacity during periods of highest demand. For example, the capacity price paid differs depending on whether the relevant hour is an “on-peak” hour, a “mid-peak” hour or an “off-peak” hour (the capacity price being highest for the on-peak hours and lowest for the off-peak hours) and the capacity price paid is highest during the months of January, July and August when electricity usage is highest due to weather conditions.

The fuel switching factor, which was introduced in October 2016 to promote environmental sensitivities to climate change, seeks to encourage reduced greenhouse gas emission by penalizing generation units (mostly coal-fired units) for excessive greenhouse gas emission.

Other than subject to the aforementioned variations, the same capacity pricing mechanism applies to all generation units regardless of fuel types used.

Vesting Contract System

In May 2014, the Electric Utility Act was amended to introduce a “vesting contract” system in determining the price and quantity of electricity to be sold and purchased between the purchaser of electricity (namely, us) and the sellers of electricity (namely, our generation subsidiaries and independent power producers). Under the vesting contract system, electricity generators using base load fuels (such as nuclear, coal, hydro and by-product gas) at a particular generation unit were to be required to enter into a contract with the purchaser of electricity (namely, us), which specifies, among other things, the quantity of electricity to be generated and sold at a particular generation unit and the price at which such electricity is sold, subject to certain adjustments.

The vesting contract system was introduced principally to prevent excessive profit-taking by low-cost producers of electricity using base load fuels (such as nuclear, coal, hydro and by-product gas) by replacing the adjusted coefficient as the basis for determining the guaranteed return to generation companies, as well as to enhance the stability of electricity supply by requiring long-term contractual arrangements for the purchase and

 

42


Table of Contents

sale of electricity and promote cost savings, productivity enhancements and operational efficiency by providing incentives and penalties depending on the degree to which the generation companies could supply electricity at costs below the contracted electricity prices.

In order to minimize undue shock to the electricity trading market in Korea, the vesting contract system was to be implemented in phases starting with by-product gas-based electricity in 2015, which accounted for 1.8% of electricity purchased by us during such year. The rollout of the vesting contract system was further studied by a task force consisting of representatives from the Government, the Korea Power Exchange and generation companies.

Following such study, the Government announced in June 2016 that, due to changes in the electricity business environment (including an increase in generation capacity relative to peak usage, reduced fuel costs following a decline in oil prices and greater environmental concerns related to coal-fired electricity generation), it will indefinitely suspend any further rollout of the vesting contract system beyond by-product gas-based electricity, and revert to the adjusted coefficient-based electricity pricing adjustment mechanism. As of the end of 2020, there are no active contracts remaining under the vesting contract system.

Power Trading Results

The results of power trading, as effected through the Korea Power Exchange, for our generation subsidiaries and independent power producers in 2020 are as follows:

 

    

Items

  Volume
(Gigawatt
hours)
    Percentage
of Total
Volume
(%)
    Sales to
KEPCO(2) (in
billions of
Won)
    Percentage
of Total
Sales (%)
    Unit Price
(Won/kWh)
 

Generation Companies

   KHNP     156,726       30.4       9,554       23.0       60.96  
   KOSEP     48,677       9.5       4,047       9.7       83.14  
   KOMIPO     46,265       9.0       4,154       10.0       89.79  
   KOWEPO     37,684       7.3       3,502       8.4       92.94  
   KOSPO     41,434       8.0       3,946       9.5       95.23  
   EWP     43,027       8.4       3,982       9.6       92.56  
   Others(1)     141,390       27.4       12,382       29.8       87.57  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  

Total

    515,203       100.0       41,567       100.0       80.68  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Energy Sources

   Nuclear     152,328       29.6       9,093       21.9       59.69  
   Bituminous coal     185,179       35.9       15,209       36.5       82.13  
   Anthracite coal     1,875       0.4       153       0.4       81.48  
   Oil     2,184       0.4       422       1.0       193.12  
   LNG/Combined-cycle     140,866       27.4       13,918       33.5       98.81  
   Renewables     20,202       3.9       1,610       3.9       79.70  
   Hydro     3,156       0.6       258       0.6       81.72  
   Pumped storage     3,257       0.6       368       0.9       113.07  
   Others     6,156       1.2       536       1.3       87.03  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  

Total

    515,203       100.0       41,567       100.0       80.68  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Load

   Base load     339,383       65.9       24,455       58.8       72.06  
   Non-base load     175,820       34.1       17,112       41.2       97.33  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  

Total

    515,203       100.0       41,567       100.0       80.68  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

Notes:

 

(1)

Others represent independent power producers that trade electricity through the cost-based pool system of power trading (excluding independent power producers that supply electricity under power purchase agreements with us).

(2)

Based on the payment made by us through Korea Power Exchange

 

43


Table of Contents

Power Purchased from Independent Power Producers under Power Purchase Agreements

In 2020, we purchased an aggregate of 14,718 gigawatt hours of electricity generated by independent power producers under existing power purchase agreements. These independent power producers had an aggregate generation capacity of 11,689 megawatts as of December 31, 2020.

Power Generation

As of December 31, 2020, we and our generation subsidiaries had a total of 697 generation units, including nuclear, thermal, hydroelectric and internal combustion units, representing total installed generation capacity of 83,854 megawatts. Our thermal units produce electricity using steam turbine generators fired by coal and oil. Our internal combustion units use oil or diesel-fired gas turbines and our combined-cycle units are primarily LNG-fired. 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, 2020 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

     24        23,250        75.3  

Thermal:

        

Coal

     58        34,161        59.6  

Oil

     3        1,200        14.3  

LNG

     4        1,400        4.8  

Total thermal

     65        36,761        56.0  
  

 

 

    

 

 

    

 

 

 

Internal combustion

     214        176        26.2  

Combined-cycle(3)

     117        16,652        28.3  

Integrated gasification combined cycle(4)

     1        346        78.2  

Hydro

     60        5,352        9.6  

Wind

     14        144        16.0  

Solar

     170        215        12.5  

Fuel cell

     24        243        71.6  

Bio

     6        705        43.2  

Others(5)

     2        10        80.6  
  

 

 

    

 

 

    

 

 

 

Total

     697        83,854        53.5  
  

 

 

    

 

 

    

 

 

 

 

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 if the generation units were continuously operated at installed capacity, expressed as a percentage.

(3)

Involves generation through gas and oil.

(4)

Involves generation through coal and gasified coal.

(5)

Includes waste-to-energy.

The expected useful life of a unit, assuming no substantial renovation, is approximately as follows: nuclear, over 40 years; thermal, over 30 years; 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.

 

44


Table of Contents

We seek to achieve efficient use of fuels and diversification of generation 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 thermal generation 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. During those times when actual demand exceeds the usual level of electricity supply from nuclear power, 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, to meet the excess demand.

Bituminous coal has been the least expensive thermal fuel per kilowatt-hour of electricity produced, and therefore our use of bituminous coal for generation needs takes the largest portion 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 internal combustion units are the most efficient 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 unit cost.

Our generation subsidiaries have constructed and operated 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. These units generally take less time to complete construction than nuclear units.

The high average age of our oil-fired thermal units is attributable to our reliance on oil-fired thermal units as the primary means of electricity generation until mid-1970. Since then, we have diversified our fuel sources and constructed relatively few oil-fired thermal units compared to units of other fuel types.

 

45


Table of Contents

The table below sets forth, for the periods indicated, 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.

 

     2016      2017      2018      2019      2020      % of 2020
Gross
Generation(1)
 
     (in gigawatt hours, except percentages)  

Electricity generated by us and our generation subsidiaries:

                 

Nuclear

     161,995        148,426        133,505        145,910        160,184        29.0  

Coal

     207,912        227,186        222,818        211,785        178,808        32.4  

Oil

     13,055        5,242        5,845        1,842        1,504        0.3  

LNG

     369        220        —          —          587        0.1  

Internal combustion

     573        496        528        579        405        0.1  

Combined-cycle

     46,477        36,957        46,780        39,049        41,353        7.5  

Hydro

     4,835        5,263        5,187        4,477        4,502        0.8  

Wind

     186        209        195        192        202        0.0  

Solar, fuel cells and others

     908        2,485        3,469        5,236        6,885        1.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total generation by us and our generation subsidiaries

     436,310        426,484        418,327        409,070        394,430        71.4  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Electricity generated by IPPs:

                 

Thermal

     83,789        103,745        125,830        124,128        123,919        22.4  

Hydro, other renewable and others

     20,342        23,238        26,490        29,842        33,760        6.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total generation by IPPs

     104,131        126,983        152,320        153,970        157,679        28.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Gross generation

     540,441        553,467        570,647        563,040        552,108        100.0  

Auxiliary use(2)

     21,605        22,279        22,309        21,587        21,297        3.9  

Pumped-storage(3)

     4,716        5,477        5,106        4,588        3,271        0.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total net generation(4)

     514,120        525,711        543,232        536,865        527,540        95.5  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Transmission and distribution losses(5)

     18,475        18,790        19,359        19,000        18,610        3.54  

 

IPPs = Independent power producers

Notes:

 

(1)

Unless otherwise indicated, 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 is utilized to generate hydroelectric power during peak demand periods.

(4)

Total net generation represents gross generation minus auxiliary and pumped-storage use.

(5)

Transmission and distribution losses represents total transmission and distribution losses divided by total net generation.

The table below sets forth our total capacity at the time of peak usage, and peak and average loads during, the indicated periods.

 

     2016      2017      2018      2019      2020  
     (Megawatts)  

Total capacity

     100,180        116,657        117,205        121,147        127,819  

Peak load

     85,183        85,133        92,478        90,314        89,091  

Average load

     61,694        63,188        65,142        64,274        62,860  

 

46


Table of Contents

Korea Hydro & Nuclear Power Co., Ltd

We commenced nuclear power generation activities in 1978 when our first nuclear generation unit, Kori #1, began commercial operation. On April 2, 2001, all of our nuclear and hydroelectric power generation assets and liabilities were transferred to KHNP.

KHNP owns and operates 24 nuclear generation units at five power plant complexes in Korea, located in Kori (Busan), Saeul (Ulsan), Wolsong (Gyeongju), Hanbit (Yonggwang) and Hanul (Ulchin), 53 hydroelectric generation units including 16 pumped storage hydro generation units as well as 28 solar generation units and one wind generation unit as of December 31, 2020.

The table below sets forth the number of units and installed capacity as of December 31, 2020 and the average capacity factor by types of generation units in 2020.

 

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

Nuclear

     24        23,250        75.3  

Hydroelectric

     53        5,307.475        9.4  

Solar

     28        42.84        14.77  

Wind

     1        0.75        2.21  
  

 

 

    

 

 

    

Total

     106        28,601.065     
  

 

 

    

 

 

    

 

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 if the generation units were continuously operated at installed capacity, expressed as a percentage.

KHNP commenced commercial operation of Shin-Kori #3, with a 1,400 megawatt capacity, in December 2016, and Shin-Kori #4 began commercial operations on August 2019. KHNP is currently building four additional nuclear generation units, two at the Shin-Kori and two at Shin-Hanul sites, each with a 1,400 megawatt capacity. KHNP expects to complete these units between 2021 and 2025. In June 2018, the board of directors of KHNP decided to retire Wolsong #1 unit earlier than planned due to comprehensive evaluation of the economic viability and regional sentiment of its continuing operation. The initial phase of the decommissioning of Kori #1, which primarily involves safety inspections and the removal of spent fuels, has begun after its permanent shutdown in June 2017.

 

47


Table of Contents

Nuclear

The table below sets forth certain information with respect to the nuclear generation units of KHNP as of December 31, 2020.

 

Unit(5)

  Reactor Type(1)    

Reactor Design(2)

 

Turbine and
Generation(3)

  Commencement
of Operations
    Installed
Capacity
    Average
Capacity
Factor(4)
(%)
 
                        (Megawatts)        

Kori-2

    PWR     W   GEC     1983       650       36.7  

Kori-3

    PWR     W   GEC, Hitachi     1985       950       78.9  

Kori-4

    PWR     W   GEC, Hitachi     1986       950       81.7  

Shin-Kori-1

    PWR     D, KEPCO E&C, W   D, GE     2011       1,000       90.6  

Shin-Kori-2

    PWR     D, KEPCO E&C, W   D, GE     2012       1,000       92.4  

Shin-Kori-3

    PWR     D, KEPCO E&C, W   D, GE     2016       1,400       68.7  

Shin-Kori-4

    PWR     D, KEPCO E&C, W   D, GE     2019       1,400       78.5  

Wolsong-2

    PHWR     AECL, H, K   H, GE     1997       700       74.9  

Wolsong-3

    PHWR     AECL, H   H, GE     1998       700       63.7  

Wolsong-4

    PHWR     AECL, H   H, GE     1999       700       78.8  

Shin-Wolsong-1

    PWR     D, KEPCO E&C, W   D, GE     2012       1,000       100.0  

Shin-Wolsong-2

    PWR     D, KEPCO E&C, W   D, GE     2015       1,000       99.9  

Hanbit-1

    PWR     W   W, D     1986       950       99.5  

Hanbit-2

    PWR     W   W, D     1987       950       76.3  

Hanbit-3

    PWR     H, CE, K   H, GE     1995       1,000       9.1  

Hanbit-4

    PWR     H, CE, K   H, GE     1996       1,000       0.0  

Hanbit-5

    PWR     D, CE, W, KEPCO E&C   D, GE     2002       1,000       31.0  

Hanbit-6

    PWR     D, CE, W, KEPCO E&C   D, GE     2002       1,000       100.3  

Hanul-1

    PWR     F   A     1988       950       78.9  

Hanul-2

    PWR     F   A     1989       950       88.9  

Hanul-3

    PWR     H, CE, K   H, GE     1998       1,000       100.3  

Hanul-4

    PWR     H, CE, K   H, GE     1999       1,000       85.6  

Hanul-5

    PWR     D, KEPCO E&C, W   D, GE     2004       1,000       100.3  

Hanul-6

    PWR     D, KEPCO E&C, W   D, GE     2005       1,000       75.1  
         

 

 

   

 

 

 

Total nuclear

            23,250       75.3  
         

 

 

   

 

 

 

 

Notes:

 

(1)

“PWR” means pressurized light water reactor; “PHWR” means pressurized heavy water reactor.

(2)

“W” means Westinghouse Electric Corporation (U.S.A.); “AECL” means Atomic Energy of Canada Limited (Canada); “F” means Framatome (France); “H” means Hanjung; “CE” means Combustion Engineering (U.S.A.); “D” means Doosan Heavy Industries & Construction Co., Ltd.; “K” means Korea Atomic Energy Research Institute; “KEPCO E&C” means KEPCO Engineering & Construction.

(3)

“GEC” means General Electric Company (U.K.); “W” means Westinghouse Electric Corporation (U.S.A.); “A” means Alstom (France); “H” means Hanjung; “GE” means General Electric (U.S.A.); “D” means Doosan Heavy Industries & Construction Co., Ltd.; “Hitachi” means Hitachi Ltd. (Japan).

(4)

The average fuel cost per kilowatt in 2020 for the entire generation units, including nuclear fuel cost, power purchase cost and material cost, was Won 7.69 per kilowatt.

(5)

Kori-1 was permanently shut down on June 18, 2017. Shin-Kori-4 commenced operations on August 29, 2019. On December 24, 2019, the NSSC approved the permanent shutdown of Wolsong #1.

Under extended-cycle operations, nuclear units can be run continuously for periods longer than the conventional twelve-month period between scheduled shutdowns for refueling and maintenance. Since 1987, we have adopted the mode of extended-cycle operations for all of our pressurized light water reactor units and plan to use it for our newly constructed units. The duration of shutdown for fuel replacement, maintenance and the

 

48


Table of Contents

evaluation period for approval to start after maintenance was 2,062.4 days in the aggregate in 2020. In addition, KHNP’s nuclear units experienced an average of 0.13 unplanned shutdowns per unit in 2020. In the ordinary course of operations, KHNP’s nuclear units routinely experience damage and wear and tear, which are 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 operation in 1978.

Hydroelectric

The table below sets forth certain information relating to KHNP’s pumped-storage and hydroelectric business units, including the installed capacity as of December 31, 2020 and the average capacity factor in 2020.

 

Location of Unit

   Number of Units      Classification      Year
Built
     Installed Capacity      Average Capacity
Factor
 
                          (Megawatts)      (%)  

Hwacheon

     4        Dam waterway        1944        108.0        21.2  

Chuncheon

     2        Dam        1965        62.28        20.6  

Euiam

     2        Dam        1967        48.0        27.0  

Cheongpyung

     4        Dam        1943        140.1        19.7  

Paldang

     4        Dam        1973        120.0        30.8  

Chilbo (Seomjingang)

     3        Basin deviation        1945        35.4        26.0  

Boseonggang

     2        Basin deviation        1937        4.5        49.5  

Kwoesan

     2        Dam        1957        2.8        33.6  

Anheung(GangLim)

     3        Dam waterway        1978        0.4        22.7  

Kangreung

     2        Basin deviation        1991        82.0        0.0  

Topyeong

     1        Dam        2011        0.045        9.9  

Muju

     1        Dam        2003        0.4        22.0  

Sancheong

     2        Dam        2001        0.995        35.8  

Yangyang

     2        Dam        2005        1.4        24.3  

Yangyang

     1        Dam        2020        0.15        4.1  

Yecheon

     1        Dam        2011        0.9        21.0  

Yecheon (Mini)

     1        Dam        2018        0.025        71.5  

Cheongpeoung

     2        Pumped Storage        1980        400.0        8.4  

Samrangjin

     2        Pumped Storage        1985        600.0        1.1  

Muju

     2        Pumped Storage        1995        600.0        11.5  

Sancheong

     2        Pumped Storage        2001        700.0        12.0  

Yangyang

     4        Pumped Storage        2006        1,000.0        10.3  

Cheongsong

     2        Pumped Storage        2006        600.0        6.5  

Yecheon

     2        Pumped Storage        2011        800.0        4.7  
  

 

 

          

 

 

    

 

 

 

Total

     53              5,307.475        9.4  
  

 

 

          

 

 

    

 

 

 

 

49


Table of Contents

Solar/Wind

The table below sets forth certain information, including the installed capacity as of December 31, 2020 and the average capacity factor in 2020, of the solar and wind power units of KHNP.

 

Location of Unit

  

Classification

   Year Built      Installed Capacity      Average Capacity
Factor
 
                 (Megawatts)      (Percent)  

Yonggwang

   Solar      2008        20.07        15.15  

Yecheon

   Solar      2012        2.01        14.99  

Kori

   Wind      2008        0.75        2.21  

Kori

   Solar      2017        5.15        16.58  

Gapyeong

   Solar      2017        0.07        15.13  

Hydro Technical Training Center

   Solar      2017        0.09        14.57  

Cheongpyung

   Solar      2018        0.09        14.52  

Cheongsong

   Solar      2018        0.05        12.86  

Kwoesan

   Solar      2018        0.25        15.27  

Boseonggang

   Solar      2018        1.99        13.90  

Samrangjin

   Solar      2019        2.77        15.30  

Yeoncheon

   Solar      2020        0.99        14.42  

Jeju

   Solar      2020        4.91        13.19  

Gyeongju

   Solar      2020        4.40        14.84  
        

 

 

    

Total

           43.59     
        

 

 

    

Korea Water Resources Corporation, which is a Government-owned entity, assumes full control of multi-purpose dams, while KHNP maintains the dams used for power generation. Existing hydroelectric power units have exploited most of the water resources in Korea 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 demand periods.

Korea South-East Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2020 and the average capacity factor and average fuel cost per kilowatt in 2020 based upon the net amount of electricity generated, of KOSEP.

 

     Weighted
Average Age of

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

Bituminous:

           

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

     29.2        3,240        43.2        89.9  

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

     11.7        5,080        71.8        78.2  

Yeosu # 2

     6.8        669        62.2        123.9  

Combined cycle and internal Combustion:

           

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

     27.0        922        27.0        153.2  

Hydro, Solar and other renewable energy

     —          489        51.0        240.4  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     22.4        10,400        56.80        95.2  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

50


Table of Contents

Korea Midland Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2020 and the average capacity factor and average fuel cost per kilowatt in 2020 based upon the net amount of electricity generated, of KOMIPO.

 

    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, 7, 8

    25.91       4,050       62.04       52.84  

Shin Boryeong #1, 2

    3.46       2,038       74.13       44.44  

Oil-fired:

       

Jeju #2, 3

    20.46       150       45.54       200.66  

Combined-cycle and internal combustion:

       

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

    21.82       1,350       4.79       99.74  

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

    11.88       1,462.45       22.61       88.65  

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

    1.38       738.35       69.49       75.29  

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

    2.51       228.73       46.93       87.78  

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

    7.17       530.44       73.25       71.93  

Jeju Internal Combustion

Engine #1,2

    13.58       80       17.83       153.83  

Wind:

       

Yangyang #1, 2

    14.58       3       15.80       6.35  

Sejong Maebongsan Wind

    14.47       8.80       0.99       0.01  

Jeju Sangmyung Wind

    4.5       21       19.55       2.20  

Combined heat and power:

       

Wonju #1

    5.67       10       80.65       88.87  

Hydroelectric:

       

Boryeong

    11.86       7.50       20.67       0.34  

Shin Boryeong

    4.25       5       33.65       0.01  

Photovoltaic (“PV”) power and fuel cell generation:

       

Boryeong (PV) site

    3.76       3.11       14.71       3.83  

Shin Boryeong (PV) site

    4.58       2.90       13.71       0.01  

Seocheon (PV) site

    13.00       1.23       13.31       —    

Jeju (PV) site

    7.94       2.34       10.62       0.31  

Seoul (PV) site

    9.42       1.30       14.00       2.90  

Sejong (PV) site

    3.08       0.33       14.81       0.001  

Yeosu (PV) site

    8.83       2.22       14.79       —    

Incheon (PV) site

    3.18       1.58       3.49       0.001  

Shin Boryeong (fuel cell) site

    3.17       7.48       81.13       110.40  

Incheon (fuel cell) site

    0.92       15.84       86.66       99.52  

Seoul (fuel cell) site

    0.25       6       25.15       45.41  

Sejong (fuel cell) site

    0.92       5.28       85.37       84.62  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

    15.62       10,732.88       51.75       59.38  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

51


Table of Contents

Korea Western Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2020 and the average capacity factor and average fuel cost per kilowatt in 2020 based upon the net amount of electricity generated, of KOWEPO.

 

     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, 9, 10

     14.7        6,100        55.3        51.07  

LNG-fired:

           

Pyeongtaek #1, 2, 3, 4(1)

     39.1        1,400        4.8        121.47  

Combined cycle:

           

Pyeongtaek #2

     6.2        868.5        39.6        83.77  

Gunsan

     10.6        718.4        23        97.03  

West Incheon

     28.1        1,800        15.4        82.63  

Hydroelectric:

           

Taean

     13.3        2.2        16.5        —    

Solar:

           

Taean

     3.4        17.3        13.4        —    

Pyeongtaek

     3.5        3.9        13.1        —    

West Incheon

     3.5        1.2        13.6        —    

Gunsan

     5.2        1.0        12.3        —    

Samryangjin

     13.1        3.0        14.2        —    

Sejong City

     8.5        5.0        13.3        —    

Gyeonggi-do

     7.7        2.5        13.7        —    

Yeongam

     7.8        13.3        15.1        —    

Goheung

     1.7        1.0        10.6        —    

Fuel Cell:

           

West Incheon 1

     5.7        16.6        47.3        113.4  

West Incheon 2

     1.4        44.0        81.7        94.7  

Cheonan Cheongsu

     1.0        5.3        89.5        106.3  

Wind Power:

           

Hwasun

     5.0        16        19.2        —    

Integrated gasification combined cycle:

           

Taean

     4.4        346.3        78.2        39.08  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     18.5        11,365.5        40        58.17  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Notes:

 

(1)

Pyeongtaek #1, 2, 3 and 4 were converted into LNG-fired power plant in February 2020.

 

52


Table of Contents

Korea Southern Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2020 and the average capacity factor and average fuel cost per kilowatt in 2020 based upon the net amount of electricity generated, of KOSPO.

 

     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, 8

     19.3        4,000        58.4        50.2  

Samcheok #1

     3.8        2,044        50.0        57.1  

Oil-fired:

           

Nam Jeju #3, 4

     14.0        200        43.5        208.5  

Combined cycle:

           

Shin Incheon #1, 2, 3, 4

     24.2        1,800        19.4        83.3  

Busan #1, 2, 3, 4

     17.2        1,800        40.3        76.5  

Yeongwol #1

     10.2        848        6.8        86.6  

Hallim

     24.5        105        53.9        110.2  

Andong #1

     6.8        362        64.9        72.8  

Nam Jeju #1

     0.1        146        13.2        213.1  

Wind power:

           

Hankyung

     14.2        21        20.2        1.3  

Seongsan

     11.2        20        23.4        0.9  

Solar

     3.8        27        14.2        0.1  

Small Hydropower

     3.4        3        28.5        —    

Fuel Cell

     2.1        59        95.5        98.1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     12.5        11,435        43.7        63.3  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

53


Table of Contents

Korea East-West Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2020 and the average capacity factor and average fuel cost per kilowatt in 2020 based upon the net amount of electricity generated, of EWP.

 

     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, 9, 10

     13.0        6,040        58.5        50.8  

Honam #1, 2

     47.7        500        74.2        66.4  

Anthracite:

           

Donghae #1, 2

     21.8        400        59.6        79.7  

Oil-fired:

           

Ulsan #4, 5, 6

     40.4        1,200        14.3        167.13  

Combined cycle:

           

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

     17.0        2,072        34.0        79.5  

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

     26.8        900        14.5        112.6  

Mini hydro, Photovoltaic, Fuel Cell, Wind-Power, Biomass:

     —          126        40.1        66.1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     19.7        11,238        46.3        62.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Power Plant Remodeling and Recommissioning

Our generation subsidiaries supplement power generation capacity through remodeling or recommissioning of thermal units. Recommissioning includes installation of anti-pollution devices, modification of control systems and overall rehabilitation of existing equipment. The following table shows recent remodeling and recommissioning initiatives by our generation subsidiaries.

 

Power Plant

  

Capacity

  

Completed (Year)

  

Extension

  

Company

Taean #1 - 10

  

6,100 MW

(500 MW×8,

1,050 MW×2)

  

EP (1) upgrade (#5, 2009)

EP upgrade (#6, 2010)

EP upgrade (#2, 2016)

EP upgrade (#1, 2017)

EP upgrade (#3, 4, 2018)

SCR (2) upgrade (#2, 4, 7, 2016)

SCR upgrade (#1, 8, 2017)

SCR upgrade (#3, 5, 6, 2018)

FGD (5) upgrade (#1, 2017)

FGD upgrade (#2, 3, 4, 2018)

   Anti-pollution    KOWEPO

Pyeongtaek #1 - 4

  

1,400 MW

(350 MW×4)

   Steam turbine upgrade (#2, 3, 2014)    10-year performance-improvement    KOWEPO

Boryeong #3 - 6

  

2,000 MW

(500 MW×8)

  

Retrofit (#3, 2019)

Retrofit (#5, 6, 2021)

Retrofit (#4, 2023)

FGD, EP, SCR upgrade (#3, 2019)

FGD, EP, SCR upgrade (#5, 6, 2021)

FGD, EP, SCR upgrade (#4, 2023)

  

Lifetime extension & Performance-improvement

Performance-improvement

   KOMIPO

Boryeong #7, 8

  

1,000 MW

(500 MW×2)

  

FGD, EP upgrade (#7, 2025)

FGD, EP upgrade (#8, 2026)

   Performance-improvement    KOMIPO

 

54


Table of Contents

Power Plant

  

Capacity

  

Completed (Year)

  

Extension

  

Company

Yeosu #1, 2

  

668.6MW

(#1:340, #2:328.6MW)

  

Boiler Type Change

(CFBC (3):#1:2016, #2:2011)

   30 years    KOSEP

Samcheonpo #1, 2

  

1,120 MW

(560 MW ×2)

   Boiler, EP, Draft System Upgrade (#1, 2: 2012)   

10 years

Refurbishing-modernization

   KOSEP

Samcheonpo #5, 6

  

1,000 MW

(500 MW ×2)

  

EP upgrade(2016 ~ 2017),

FGD, SCR, WESP installation

(2019 ~ 2020)

   Anti-pollution    KOSEP

Yeongdong #2

  

200 MW

(200 MW ×1)

   Boiler, Hybrid SCR & EP, Draft System Retrofit (Biomass #1: 2020)    Renewable energy    KOSEP

Dangjin #1 - 4

  

2,000MW

(500MW×4)

   FGD, EP, SCR upgrade (2022)    Performance-improvement    EWP

Dangjin #5 - 8

  

2,000MW

(500MW×4)

   FGD, EP, SCR upgrade (2024)    Performance-improvement    EWP

Dangjin #9 - 10

  

2,040MW

(1,020MW×2)

   FGD, EP, SCR upgrade (2026)    Performance-improvement    EWP

Donghae #1, 2

  

400 MW

(200 MW×2)

   FGD (2022)    Anti-pollution & modification of control systems    EWP

Hadong #1 - 8

  

4,000 MW

(500 MW×8)

  

SCR Upgrade (#5. 2016)

SCR Upgrade (#2,3,5. 2017)

SCR Upgrade (#1,4,6,7. 2018)

SCR Upgrade (#8. 2019)

FGD Upgrade (#6, 2018)

FGD Upgrade (#2, 3, 2019)

FGD Upgrade (#4 2020)

FGD Upgrade (#5 2021)

   Anti-pollution    KOSPO

 

Notes:

 

(1)

“EP” means an electrostatic precipitation system.

(2)

“SCR” means a selective catalytic reduction system.

(3)

“CFBC” means a circulating fluidized bed combustion system.

(4)

“Biomass” means wood pallet powered plant.

(5)

“FGD” means flue-gas desulfurization designed to remove sulfur oxides.

Transmission and Distribution

We currently transmit and distribute substantially all of the electricity in Korea.

As of December 31, 2020, our transmission system consisted of 34,664 circuit kilometers of lines of 765 kilovolts and others including high-voltage direct current lines, and we had 877 substations with aggregate installed transformer capacity of 336,926 megavolt-amperes.

As of December 31, 2020, our distribution system consisted of 129,789 megavolt-amperes of transformer capacity and 9,787,967 units of support with a total line length of 514,779 circuit kilometers.

We make substantial investments in our transmission and distribution systems to minimize power interruptions and improve efficiency. Our current projects principally focus on increasing capabilities of the existing power networks and reducing our transmission and distribution loss, which was 3.54% of our gross generation in 2020. To cope with increasing damages to large-scale transmission and distribution facilities, we

 

55


Table of Contents

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 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 invest in automation of electricity transmission and development of new transmission technologies, among others.

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.

New Energy Industry Projects

Certain of our new energy industry projects are described below.

Advanced Metering Infrastructure

In July 2012, the Government implemented a master plan to build out a smart grid, which includes the Advanced Metering Infrastructure (“AMI”) roadmap, and revised the plan to focus on building electricity market ecosystem in August 2018. In accordance with such plan, we are in the process of installing “smart meters” and related communication networks and operating systems as part of the “smart grid” initiative in an effort to enhance efficiency in the power electricity industry and alleviate growing energy shortage concerns. Our goal is to complete such installation for all of the households in Korea. Smart meters refer to digital meters that record, on a real-time basis, electricity consumption within a household so that consumers will have a price-based incentive to enhance efficiency in their electricity usage. As of December 31, 2020, we have installed 10 million smart meter units, and plan to install additional 12 million units by 2024. The AMI project is expected to cost approximately Won 1.6 trillion in total.

Smart Grids

Smart grids refer to next-generation networks for electricity distribution that integrate information technology into existing power grids with the aim of enabling two-way real time exchange of information between electricity suppliers and consumers for optimal efficiency in electricity use. As part of our overall business strategy, we are currently developing and implementing smart grids based on advanced information technology, in order to promote more efficient allocation and use of electricity by consumers. We expect that such technology will improve efficiency and reduce electricity loss over the course of electricity transmission and distribution. We also expect that the smart grid initiative will significantly increase efficient energy consumption by providing real-time data to customers, which would in turn help to reduce greenhouse gas emission and decrease Korea’s reliance on foreign energy sources.

Leveraging our experience gained through high-tech intelligent power transmission and distribution network, or “smart grid” test beds in Jeju Province from 2009 to 2013, we plan to expand our smart grid project. We successfully implemented the KEPCO-Building Energy Management System(K-BEMS) at our Guri-Namyangju branch and the Smart Grid Deployment Project in 2014. In recognition of our achievement, we were awarded a special prize from the International Smart Grid Action Network in 2018. By the end of 2020, we implemented smart grid technology in 120 of our branches and 151 public sites (15 buildings, 8 campuses, 93 factories and 35 dispersed generation). Based on this experience, we plan to expand implementation of smart grid technology to residential and industrial buildings.

Energy Storage Systems

In October 2013, as part of an endeavor to create new markets for energy demand management applications using information and communication technology, we established a business plan to roll out energy storage

 

56


Table of Contents

systems for frequency regulation nationwide. These systems involve the establishment and operation of batteries and transformers with large-sized charge and discharge capabilities adjacent to substations to transmit electricity stably with regulated frequencies and optimize the efficiency of the substation operation. This system allows full conversion of reserve capacity for frequency regulation at existing low-cost generators into electricity storage and, if operated in sizable scale, offers opportunities for substantial cost savings in purchase of electricity.

In December 2014, we conducted a pilot project for this initiative by installing a 52 megawatts energy storage system at the Seo-Anseong substation and the Shin-Yongin substation. In July 2015, these substations began to commercially operate energy storage systems, and we expanded the energy storage capacity nationwide by an additional 184 megawatts in 2016, an additional 140 megawatts in 2017, with a total capacity of 376 megawatts as of December 31, 2020. Among them, we completed construction of the largest indoor energy storage systems for frequency regulation in Gimje substation with a 48 megawatts capacity.

Electric Vehicle Charging Infrastructure

In order to promote the use of environment-friendly electric vehicles, we began constructing infrastructures for electric vehicles in 2009. Since 2016, we have installed electric vehicle charging stations throughout public space and residential building complexes. In 2017, we created a platform for businesses in the electric vehicle charging industry by charging for the service and making the infrastructures available to the market. We plan to expand such infrastructures and to install 4,500 high speed electric vehicle charging stations by 2025.

In January 2016, the Ministry of Trade, Industry and Energy announced an initiative to promote the new energy industry by creating the New Energy Industry Fund. For further details, see “—Capital Investment Program.”

Fuel Sources and Requirements

Nuclear

Uranium, the principal fuel source for nuclear power, accounted for 31.9%, 35.7% and 40.6% of the fuel requirements for electricity generation by us and our generation subsidiaries in 2018, 2019 and 2020, respectively.

All uranium ore concentrates used by KHNP are imported from, and conversion and enrichment of such concentrates are provided by, sources outside Korea and are paid for with currencies other than Won, primarily U.S. dollars.

In order to ensure a stable supply, KHNP enters into long-term and medium-term contracts with various suppliers and supplements such supplies with purchases in spot markets. In 2020, KHNP purchased approximately 5,700 tons of its uranium concentrate requirement under both long-term and spot supply contracts with suppliers in Canada, France, the United Kingdom, Switzerland, Kazakhstan, Australia, Germany, Hong Kong, Japan and Uzbekistan. 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. The conversion and enrichment services of uranium concentrates are provided by suppliers in Canada, France, Hong Kong, Japan, China, Russia, the United Kingdom and Switzerland. A Korean supplier typically provides 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 medium- to long-term contracts and, in part, through spot market purchases.

Coal

Bituminous coal accounted for 52.6%, 51.1% and 44.8% of the fuel requirements for electricity generation by us and our generation subsidiaries in 2018, 2019 and 2020, respectively, and anthracite coal accounted for 0.6%, 0.6% and 0.5% of our fuel requirements for electricity generation in 2018, 2019 and 2020, respectively.

 

57


Table of Contents

In 2020, our generation subsidiaries purchased approximately 68 million tons of bituminous coal, of which approximately 40%, 28%, 14%, 2% and 16% were imported from Australia, Indonesia, Russia, South Africa and others, respectively. Approximately 84% of the bituminous coal requirements of our generation subsidiaries in 2020 were purchased under long-term contracts with the remaining 16% 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 periodically based on market conditions. The average cost of bituminous coal per ton purchased under such contracts amounted to Won 107,233, Won 101,624 and Won 69,748 in 2018, 2019 and 2020, respectively.

In 2020, our generation subsidiaries purchased approximately 1 million tons of anthracite coal. 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 Won 129,976, Won 136,526 and Won 137,116 in 2018, 2019 and 2020, respectively.

Oil

Oil accounted for 1.4%, 0.5% and 0.4% of the fuel requirements for electricity generation by us and our generation subsidiaries in 2018, 2019 and 2020, respectively.

In 2020, our generation subsidiaries purchased approximately 5 million barrels of fuel oil, substantial portion of which was purchased from domestic refiners through competitive open bidding. Purchase prices are based on the spot market price in Singapore. The average cost per barrel was Won 85,116, Won 100,827 and Won 91,566 in 2018, 2019 and 2020, respectively.

LNG

LNG accounted for 11.2%, 9.5% and 10.6% of the fuel requirements for electricity generation by us and our generation subsidiaries in 2018, 2019 and 2020, respectively. In 2020, for use in electricity generation we purchased approximately 5 million tons of LNG from Korea Gas Corporation, a Government-controlled entity in which we currently own a 22.02% equity interest (excluding treasury shares). In 2020, we purchased a substantial portion of our LNG requirements for use in power generation from Korea Gas Corporation. Under the terms of the LNG contract with Korea Gas Corporation, all of our five non-nuclear generation subsidiaries jointly and severally agreed to purchase a total of 5.3 million tons of LNG in 2020, subject to an automatic price adjustment annually based on a pre-determined formula if the actual purchased amount exceeds or falls short of the contracted amount. 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. The LNG supply contracts between our generation subsidiaries and Korea Gas Corporation generally have a term of 20 years and provide for minimum purchase requirements for our generation subsidiaries, the specific terms of which are subject to negotiation between Korea Gas Corporation and our generation subsidiaries and approval by the Government. The average cost per ton of LNG was Won 763,460, Won 727,083 and Won 556,564, in 2018, 2019 and 2020, respectively. In January 2020, Korea Gas Corporation announced that it will implement a new individual tariffs formula, whereby the domestic power plants can negotiate lower prices directly with Korea Gas Corporation. The new formula will apply to domestic power plants whose current contracts with Korea Gas Corporation will expire after January 2022 and also to new power plants commencing operations from January 2022.

Hydroelectric

Hydroelectric power generation accounted for 1.2%, 1.1% and 1.1%, of the fuel requirements for electricity generation by us and our generation subsidiaries in 2018, 2019 and 2020, respectively. 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 electricity demand.

 

58


Table of Contents

Sales and Customers

Our sales depend principally on the level of demand for electricity in Korea and the rates we charge for the electricity we sell to the end-users.

Demand for electricity in Korea grew at a compounded average rate of 0.6% per annum for the five years ended December 31, 2020. According to the Bank of Korea, the compounded growth rate for GDP was approximately 1.7% for the same period. The GDP growth rate was approximately 2.7%, 2.0% and -1.0% during 2018, 2019 and 2020, respectively.

The table below sets forth, for the periods indicated, the annual rate of growth in Korea’s GDP and the annual rate of growth in electricity demand (measured by total annual electricity consumption) on a year-on-year basis.

 

     2016     2017     2018     2019     2020  

Growth in GDP

     2.9     3.1     2.7     2.0     (1.0 )% 

Growth in electricity consumption

     2.8     2.2     3.6     (1.1 )%      (2.2 )% 

Electricity demand in Korea varies within each year for a variety of reasons other than the general growth in GDP demand. Electricity demand tends to be higher during daylight hours due to heightened commercial and industrial activities and electronic appliance use. Due to the use of air conditioning during the summer and heating during the winter, electricity demand is higher during these two seasons than the spring or the fall. 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.

Demand by the Type of Usage

The table below sets forth consumption of electric power, and growth of such consumption on a year-on-year basis, by the type of usage (in gigawatt hours) for the periods indicated.

 

    2016
(GWh)
    YoY
growth
(%)
    2017
(GWh)
    YoY
growth
(%)
    2018
(GWh)
    YoY
growth
(%)
    2019
(GWh)
    YoY
growth
(%)
    2020
(GWh)
    YoY
growth
(%)
    % of
Total
2020
 

Residential

    68,057       3.7       68,544       0.7       72,895       6.3       72,639       (0.4     76,303       5.0       15.0  

Commercial

    108,617       4.8       111,298       2.5       116,934       5.1       116,227       (0.6     113,639       (2.2     22.3  

Educational

    8,079       5.1       8,316       2.9       8,678       4.3       8,561       (1.4     7,515       (12.2     1.5  

Industrial

    278,828       1.9       285,969       2.6       292,999       2.5       289,240       (1.3     278,660       (3.7     54.7  

Agricultural

    16,580       5.6       17,251       4.0       18,504       7.3       18,882       2.0       19,029       0.8       3.7  

Street lighting

    3,462       3.6       3,557       2.7       3,582       0.7       3,571       (0.3     3,507       (1.8     0.7  

Overnight Power

    13,416       (4.7     12,811       (4.5     12,557       (2.0     11,379       (9.4     10,616       (6.7     2.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    497,039       2.8       507,746       2.2       526,149       3.6       520,499       (1.1     509,270       (2.2     100.0  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The industrial sector represents the largest segment of electricity consumption in Korea. Demand for electricity from the industrial sector was 278,660 gigawatt hours in 2020, representing a 3.7% decrease from 2019, largely due to a decrease in the industrial electricity usage from a recession in the manufacturing industry in light of the COVID-19 pandemic, even though the manufacturing industry has traditionally been a major consumer of electricity. Demand for electricity from the commercial sector depends largely on the level and scope of commercial activities in Korea. Demand for electricity from the commercial sector decreased to 113,639 gigawatt hours in 2020, representing a 2.2% decrease from 2019, largely due to a decrease in the commercial

 

59


Table of Contents

electricity usage from a slowdown in the service industry as a consequence of the social distancing in response to the COVID-19 pandemic and less air conditioning used in the stores as a result of a more temperate weather conditions. Demand for electricity from the residential sector is largely dependent on population growth and use of heaters, air conditioners and other electronic appliances. Demand for electricity from the residential sector increased to 76,303 gigawatt hours in 2020, representing a 5.0% increase compared to 2019, largely due to an increase in household electricity usage from an increased time spent at home and telecommuting in response to the COVID-19 pandemic.

Demand Management

Our ability to provide adequate supply of electricity is principally measured by the facility reserve margin and the supply reserve margin. The facility reserve margin 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 reserve margin 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 reserve margin and supply reserve margin for the periods indicated.

 

     2016     2017     2018     2019     2020  

Facility reserve margin

     17.6     37.0     26.7     34.1     43.5

Supply reserve margin

     8.5     12.9     7.7     6.7     9.9

While we seek to meet the growing demand for electricity in Korea primarily by continuing to expand our generation capacity, we have also implemented several measures to curtail electricity consumption, especially during peak periods. We apply time-of-use and seasonality tariff, which are structured so that higher tariffs are charged at the time and months of peak demand to select types of customers, and we also apply a progressive rate structure for the residential use of electricity. We have several demand management programs to control demand and induce power conservation during peak hours and peak seasons such as providing incentives for reducing power consumption during peak hours.

Electricity Rates

The Electric Utility Act and the Price Stabilization Act of 1975, each as amended from time to time, 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 Trade, Industry and Energy. The Ministry of Trade, Industry and Energy then reviews these proposals and, following consultation with the Ministry of Economy and Finance and review by the Korea Electricity Commission, makes the final decision.

Under the Electric Utility Act and the Price Stabilization Act, electricity rates are established at levels that would enable us to recover our operating costs attributable to our basic electricity generation, transmission and distribution operations as well as receive a fair investment return on capital used in those operations.

For the purposes of rate approval, operating costs are defined as the sum of our operating expenses (which principally consists of cost of sales and selling and administrative expenses) and our adjusted income taxes.

Fair investment return represents an amount equal to the rate base multiplied by the rate of return.

The rate base is currently equal to the sum of:

 

   

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

 

60


Table of Contents
   

the portion of working capital which is equal to the appropriate level of operating costs minus depreciation and other non-cash charges while taking into account the actual time of cost recovery; 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.

For the purpose of determining the fair rate of return, the rate base is divided into two components in proportion to our total shareholders’ 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, and the correlation of the stock price of our company with KOSPI. In 2019, the approved rate of return on the debt component of the rate base was 0.84% while the approved rate of return on the equity component of the rate base was 2.64%. As a result of such approved rates of returns, the fair rate of return in 2019 was determined to be 3.48%. The fair rates of return for 2020 have not yet been determined.

The Electric Utility Act and the Price Stabilization Act do not specify a basis for determining the reasonableness of our 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 tariff levels. These other factors include consumer welfare, our projected capital requirements, the effect of electricity tariff on inflation in Korea and the effect of tariff on demand for electricity.

From time to time, our actual rate of return on invested capital may differ significantly from the fair rate of return on invested capital assumed for the purposes of electricity tariff approvals, for reasons, among others, related to movements in fuel prices, exchange rates and demand for electricity that differ from what is assumed for determining our fair rate of return. For example, between 1987 and 1990, the actual rate of return was above the fair rate of return due to declining fuel costs and rising demand for electricity at a rate not anticipated for purposes of determining our fair rate of return. Similarly, depreciation of the Won against the U.S. dollar accounted for our actual rates of return being lower than the fair rate of return for the period from 1996 to 2000. For the period between 2006 and 2013, our actual rates of return were lower than the fair rate of return largely due to a general increase in fuel costs and additional facility investment costs incurred, the effects of which were not offset by timely increases in our tariff rates. Between 2014 and 2016, however, largely due to a decrease in fuel costs reflective of the drop in oil prices, our actual rate of return has surpassed the fair rate of return; however, substantially all of the resulting excess has been used to fund capital expenditure and repair and maintenance, and make investments in renewable energy and other environmental programs.

Partly in response to the variance between our actual rates of return and the fair rates of return, the Government from time to time increases the electricity tariff rates, but there typically is a significant time lag for the tariff increases as such increases requires a series of deliberation processes and administrative procedures and the Government also has to consider other policy considerations, such as the inflationary effect of overall tariff increases and the efficiency of energy use from sector-specific tariff increases.

Prior to November 2013, the Government from time to time effected tariff increases that typically covered all sectors, namely, residential, commercial and industrial, mainly in response to sustained increases in fuel prices. No cross-sector tariff increase has been implemented since November 2013 largely due to a general decline in fuel prices and relatively stable exchange rates. However, effective on January 1, 2017, the

 

61


Table of Contents

Government made several adjustments to the existing rate structure in order to ease the burden of electricity tariff on residential consumers. The progressive rate structure applicable to the residential sector, which applies a gradient of increasing tariff rates for heavier electricity usage, was changed from a six-tiered structure with the highest rate being no more than 11.7 times the lowest rate (which gradient system has been in place since 2005) into a three-tiered structure with the highest rate being no more than three times the lowest rate in order to reflect the changes in the pattern of electricity consumption and reduce the electricity charges payable by consumers. Additionally, a new tariff structure was implemented to encourage energy saving by offering rate discounts to residential consumers that voluntarily reduce electricity consumption while charging special high rates to residential consumers with heavy electricity consumption during peak usage periods in the summer and the winter. Further, during July and August 2018, the Government reduced residential electricity charges by temporarily relaxing the application of the then tariff structure and offering higher rate discounts to economically or otherwise disadvantaged customers to ease the burden on households that have significantly increased their use of air conditioners during a heatwave. Subsequently, a joint task force team, consisting of industry experts, scholars and government officials, was formed, which announced a proposal for amending the tariff structure aimed to decrease the financial burden for households during the summer. As a result, in July 2019, the Government amended the residential electricity tariff rate system to expand the usage ceiling for the first two tiers of rates (from 200 kilowatts to 300 kilowatts for the first tier and from 400 kilowatts to 450 kilowatts for the second tier) applied during July and August each year. Even though the rate discounts offered to residential consumers who voluntarily reduced electricity consumption and those offered to traditional wet markets were abolished in December 2019 and the rate discount for electric vehicles will be gradually terminated in phases by June 2022, there can be no assurance that other current or potential future adjustments in electricity tariff rates and rate discounts will not have an adverse impact on our business, results of operations, financial condition and profitability.

As of January 1, 2021, we implemented a new tariff system to reinforce the correlation between the costs we incur and the tariff we charge to our customers, among other changes. The new tariff system consists of three main changes.

First, we implemented a new cost pass-through tariff system to reinforce the correlation between the costs we incur and the tariff we charge to our customers and to enhance transparency by separately billing fuel costs and climate/environment related costs. Previously, the electricity tariff consisted of two main components: (i) the base charge (the “Base Charge”) and (ii) the usage charge (the “Usage Charge”) based on the amount of electricity consumed by end-users. Under the new tariff system, there are new components to the tariff called the fuel cost adjusted charge (the “Fuel Cost Adjusted Charge”) and the climate/environment related charge (the “Climate/Environment Related Charge”). The Fuel Cost Adjusted Charge is adjusted every quarter and the formula for calculating the amount of the Fuel Cost Adjusted Charge is multiplying (i) the unit price of the Fuel Cost adjusted Charge (the “Unit Price of the Fuel Cost Adjusted Charge”), which is the difference between a base fuel cost (the “Base Fuel Cost”) and an actual fuel cost (the “Actual Fuel Cost”) and (ii) the amount of electricity consumed. The Base Fuel Cost is the past twelve-month average fuel price of bituminous coal, LNG and Bunker C oil as posted by the Korea Customs Service. For 2021, the twelve-month average fuel price is measured by taking the average of monthly fuel prices from twelve preceding months from one month before the new tariff system was implemented. To illustrate, the Base Fuel Cost for the first and second quarters of 2021 was the average of the fuel prices from December 2019 to November 2020. On the other hand, the Actual Fuel Cost is the past three-month average fuel price of the same fuels we use to measure the Base Fuel Cost. The past three-month average fuel price is measured by taking the average of monthly fuel prices from three preceding months from one month before the start of each period when the applicable Fuel Cost Adjusted Charge will be updated. To illustrate, for the first quarter of 2021, we used the fuel costs for September, October and November 2020 to calculate the three-month average fuel price.

The quarterly-adjusted Fuel Cost Adjusted Charge has built-in caps in view of price stability and other public policy considerations. First, there is a cap on the Unit Price of the Fuel Cost Adjusted Charge to be (i) no less than Won ±1 per kilowatt-hour and (ii) no greater than Won ±3 per kilowatt-hour as compared to the

 

62


Table of Contents

immediately preceding quarter. In other words, any change less than Won ±1 per kilowatt-hour will not be reflected to the Fuel Cost Adjusted Charge and any change greater than Won ±3 per kilowatt-hour will not be reflected to the extent of the portion that exceeds Won ±3 per kilowatt-hour. For example, in the first quarter of 2021, the Unit Price of the Fuel Cost Adjusted Charge was Won –10.5 per kilowatt-hour, meaning the Actual Fuel Cost was lower than the Base Fuel Cost, but after being subjected to the quarterly cap of Won ±3 per kilowatt-hour, the final rate for the Unit Price of the Fuel Cost Adjusted Charge came out to be Won –3 per kilowatt-hour. Second, the Unit Price of the Fuel Cost Adjusted Charge that exceeds Won ±5 per kilowatt-hour will not be reflected in the Fuel Cost Adjusted Charge. In other words, the maximum adjustment that can be incorporated to the Unit Price of the Fuel Cost Adjusted Charge is equal to Won ±5 per kilowatt-hour from the Base Fuel Cost that is in effect for a given period. The Base Fuel Cost can only be adjusted upon the revision of the Base Charge and the Usage Charge as described at further below in this section.

However, our ability to pass on fuel and other cost increases to our customers may be limited due to the regulation of the Government on the rates we charge for the electricity we sell to our customers. In addition to the built-in caps described in the preceding paragraph, the new tariff system gives the discretion to the Government not to wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances. For example, in the second quarter of 2021, although the Unit Price of the Fuel Cost Adjusted Charge was Won –0.2 per kilowatt-hour, the Government decided to keep it at the same Won –3 per kilowatt-hour as the previous quarter. The Government cited (i) the need to alleviate the hardship caused by the prolonged economic effects of COVID-19 pandemic, (ii) an abnormal nature of the rapid increase in the price of LNG due to the global cold wave in the winter of late 2020 and early 2021, which has been factored into the Actual Fuel Cost, and (iii) the relative gains we received in the first quarter of 2021 because the Fuel Cost Adjusted Charge for the first quarter was capped at the lower bound of Won –3 per kilowatt-hour instead of decreasing it further.

Also, because the Fuel Cost Adjusted Charge takes into account the fuel prices posted by Korea Customs Service, there may still be a mismatch in value between the actual prices the domestic generation companies pay for their fuels in the open market and the adjustment that can be made through the Fuel Cost Adjusted Charge. The domestic generation companies include not only our generation subsidiaries but also independent power producers that are unaffiliated to us and we do not have access to fuel costs incurred by the independent power producers. As such, we use fuel prices posted by Korea Customs Service, which are easily accessible to our customers, for calculating the Fuel Cost Adjusted Charge.

Due to the likelihood of the Actual Fuel Cost being substantially over the caps in the new tariff system and the Government’s discretion not to wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances, there may be certain portions of the fuel costs that cannot be charged to our customers, even though those portions should have been included in the Fuel Cost Adjusted Charge. In such cases, we may accumulate such portions and reflect them in what is called the total comprehensive cost (the “Total Comprehensive Cost”), which is a variable we use to calculate the Base Charge and the Usage Charge of the tariff. The Total Comprehensive Cost, submitted yearly to the Government by us, is calculated based on our budget for relevant costs. Under the Total Comprehensive Cost approach, the Base Charge and the Usage Charge are established at levels that would enable us to recover our operating costs attributable to our basic electricity generation, transmission and distribution operations as well as receive a fair investment return on capital used in those operations. The operating costs are defined as the sum of our operating expenses, which principally consists of cost of sales and selling and administrative expenses, and our adjusted income taxes. The Base Charge and the Usage Charge that are derived from the Total Comprehensive Cost need to be approved by the Government to be revised. In addition, the Base Fuel Cost can only be adjusted upon the revision of the Base Charge and the Usage Charge. Therefore, if the Base Charge and the Usage Charge are not timely adjusted by the Government, there can be a delay for the change in fuel costs to be fully reflected in the tariff.

Also, the new tariff system introduces an additional component to the tariff called a climate/environment related charge (the “Climate/Environment Related Charge”). Previously, our climate and environment costs were

 

63


Table of Contents

embedded in the Usage Charge component of the tariff and our consumers could not discern the exact magnitude of such costs. By separating it out as an independent component, we intend to provide more information and transparency to our customers while having the flexibility to adjust it in alignment with the underlying costs. The Climate/Environment Related Charge for the coming year is calculated by multiplying (i) our total estimated costs of complying with the Renewable Portfolio Standard program, the Greenhouse Gas Emission Trading System and the coal-fired generation reduction program for the current year and then dividing it by the electricity sales projected for the coming year, and (ii) the amount of electricity consumed. The value for (i) for 2021 is Won 5.3 per kilowatt-hour. The Climate/Environment Related Charge is planned to be adjusted every year by reflecting the change in climate and environment-related costs but the Government may change the date of adjustment under reasonable circumstances. There is no guarantee the Climate/Environment Related Charge will be regularly updated, even though our climate and environment-related costs will likely increase each year. If there are discrepancies between our costs and the Climate/Environment Related Charge, we may accumulate such discrepancies and reflect them in our Total Comprehensive Cost. However, the electricity rate based on the Total Comprehensive Cost needs to be approved by the Government to be revised. There is no assurance that, particularly given the wide-ranging policy priorities of the Government, it will in fact raise the electricity rate to a level sufficient to fully cover additional costs associated with implementing and operating programs as described in this section and do so on a timely basis or at all. If the Government does not do so or provide us and our generation subsidiaries with other forms of assistance to offset the costs involved, our results of operation, financial condition and cash flows may be materially and adversely affected.

Second, the new tariff system intends to amend the residential electricity rate system starting in July 2021. Under the current system, households that use less than 200 kilowatt-hours of electricity receive a discount on their tariffs. We intend to redirect this benefit by phasing out the discount to 50% in July 2021 and terminating it in July 2022. The new tariff system also allows households to choose a new schedule of residential tariff, which is an option we have already been providing to our industrial and commercial customers. The new schedule is called a seasonal and hourly tariff and it allows residents to be charged under a monthly Base Charge plus increments depending on time, day and season. Each household may also choose to stay under the current tariff schedule which in contrast is a progressive schedule with seasonal adjustments. Our plan is to provide this option to households in Jeju Province in Korea first as many of these households are equipped with advanced metering infrastructure (“AMI”) and review rolling it out to the rest of the country depending on the penetration rate of the AMI in each region.

Third, the new tariff system will end certain special discounts we previously provided to our customers. The first of two such discounts is for customers who installed energy storage system (“ESS”). The benefits included tariff discounts of three times the Base Charge and 50% of the Usage Charge. Starting in January 2021, we rolled back the discount for ESS by decreasing it from three times the Base Charge to one times the Base Charge and discontinuing the 50% discount on the Usage Charge. The discount of one times the Base Charge is planned to also phase out in March 2026 as we originally intended. In addition, we intend to designate a three-hour time period during peak time and induce electricity discharge of the ESS during that period by giving more discount to the customers who made such discharge so they will increase supply during peak time. The second of the two discounts being rolled back is a 50% discount for customers who installed a renewable energy generator for their own industrial and general uses. We discontinued this discount in 2020 while only maintaining it for customers who are unable to sell their electricity in the market because of their small generation capacities (less than 10 kilowatts). The discount for such customers is planned to be discontinued by 2023.

Lastly, the new tariff system announced in December 2020 included a plan to minimize the public burden of tariff increase by reducing power supply cost of us and our generation subsidiaries through cost reduction measures. To this end, it was contemplated that an annual increase limit of 3% on certain electricity supply costs including labor costs and selling, general and administrative expenses would be set and an increase in excess of the 3% limit will not be reflected in the tariff. However, as of present, the precise scope of what constitutes electricity supply costs and the method of execution on the plan has not yet been determined. However, if the

 

64


Table of Contents

annual increase limit of 3% on electricity supply costs is implemented, it could have an adverse effect on our business, financial condition and results of operations.

The tariff rates we charge for electricity vary among the different classes of consumers, which principally consist of industrial, commercial, residential, educational and agricultural consumers. The tariff also varies depending upon the voltage used, the season, the time of usage, the rate option selected by the user and, in the residential sector, the amount of electricity used per household, as well as other factors. For example, we adjust for seasonal tariff variations by applying higher rates when demand tends to rise such as during the months of June, July and August (when the demand tends to rise due to increased use of air conditioning) and November, December, January and February (when demand tends to rise due to increased use of heating), which reflects the policy of the Korean government to cope with the rise in electricity demand during peak seasons by encouraging a more efficient use of electricity by customers. In addition, we provide discounts on tariff rates to certain users such as low income households.

 

   

Industrial. The monthly Base Charge varies from Won 5,550 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy Usage Charge varies from Won 47.8 per kilowatt-hour to Won 191.6 per kilowatt-hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

 

   

Commercial. The monthly Base Charge varies from Won 6,160 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy Usage Charge varies from Won 48.7 per kilowatt-hour to Won 191.6 per kilowatt-hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

 

   

Residential. The monthly Base Charge varies from Won 910 for electricity usage of less than 200 kilowatt hours to Won 7,300 for electricity usage in excess of 400 kilowatt hours. During the months of July and August each year, the usage ceiling for the first two tiers of rates is increased from 200 kilowatts to 300 kilowatts for the first tier and from 400 kilowatts to 450 kilowatts for the second tier. Residential tariff also includes an energy Usage Charge ranging from Won 88.3 to Won 275.6 per kilowatt-hour for electricity usage depending on the amount of usage and voltage. During the peak usage periods during summer and winter, namely the months of July and August and December to February, a higher energy Usage Charge of Won 704.5 per kilowatt-hour applies to residential consumers whose monthly electricity consumption exceeds 1,000 kilowatts hour. In accordance with the new tariff system, residents may also opt for our new seasonal and hourly tariff schedule as an alternative. Under the new schedule, the monthly Base Charge will be Won 4,310 plus increments depending on time, day and season. During summer and winter, namely January, February, June, July, August, November and December, the total charge will be between Won 4,417 and Won 4,498.8. During spring and fall, which include all months other than summer and winter, the total charge will be between Won 4,404.1 and Won 4,450.7.

 

   

Educational. The monthly Base Charge varies from Won 5,230 per kilowatt to Won 6,980 per kilowatt depending on the voltage used and the rate option. The energy Usage Charge varies from Won 38.8 per kilowatt-hour to Won 155.4 per kilowatt-hour depending on the voltage used, the season and the rate option.

 

   

Agricultural. The monthly Base Charge varies from Won 360 per kilowatt to Won 1,210 per kilowatt depending on the type of usage. The energy Usage Charge varies from Won 16.6 per kilowatt-hour to Won 36.9 per kilowatt-hour depending on the type of contract, the voltage used and the season.

 

   

Street-lighting. The monthly Base Charge is Won 6,290 per kilowatt and the energy Usage Charge is Won 80.9 per kilowatt-hour. For electricity capacity of less than 1 kilowatt or for places where the installation of the electricity meter is difficult, a fixed rate of Won 35.7 per watt applies, with the minimum monthly charge of Won 1,220.

 

65


Table of Contents

In 2001, as part of implementing the Restructuring Plan, the Ministry of Trade, Industry and Energy established the Electric Power Industry Basis Fund to enable the Government to take over certain public services previously performed by us. In 2020, 3.7% of the tariff we collected from our customers was transferred to this fund prior to recognizing our sales revenue.

Power Development Strategy

We and our generation subsidiaries make plans for expanding or upgrading our generation capacity based on the Basic Plan, which is generally revised and announced every two years by the Government. In December 2020, the Government announced the Ninth Basic Plan which is more environmentally focused than the Eighth Basic Plan and effective for the period from 2020 to 2034. The Ninth Basic Plan focuses on, among other things, accelerating transition to an eco-friendly power source. The Ninth Basic Plan focuses on, among other things, (i) decreasing the reliance on nuclear and coal-based supply sources, (ii) converting retired coal-fired power plants into LNG-fired ones for stable power supply and (iii) accelerating the use expansion of renewable energies in light of the Green New Deal initiative of the Korean Government. Furthermore, the Ninth Basic Plan includes the following specific measures: (i) thirty decrepit coal-fired power plants and eleven nuclear power plants will be retired, and, as a result, coal and nuclear generation capacities will be reduced to 29 gigawatts and 19.4 gigawatts respectively by 2034, (ii) twenty-four out of thirty decrepit coal-fired power plants will be retired, the total generation capacity for which is 12.7 gigawatts, and shall be converted into using LNG instead, and (iii) domestic renewable energy generation capacity will be expanded by 77.8 gigawatts by 2034 in accordance with the Green New Deal initiative of the Korean Government.

In June 2019, the Ministry of Trade, Industry and Energy adopted the Third Basic National Energy Plan following consultations with representatives from civic groups, the energy industry and academia. The Third Basic National Energy Plan, which is a comprehensive plan that covers the entire spectrum of energy industries in Korea, covers the period from 2019 to 2040. The Third Basic National Energy Plan is consistent with the First and the Second Basic National Energy Plans in terms of the general policy direction and aims to promote sustainable growth and improvement of people’s quality of life by converting to renewable energy. Specifically, it establishes the following five key tasks: (i) strengthening management of energy demand from various sectors, such as commerce and transportation, and promoting a rational electricity tariff system to improve the national energy consumption efficiency by 38% and reduce the energy demand by 18.6% by 2040; (ii) converting to clean and safe energy through gradual reduction of nuclear power generation and decisive reduction of coal power generation by prohibiting construction of new coal-fired power plants and increasing the proportion of renewable energy sources to approximately 35% by 2040; (iii) expanding the power distribution in areas near those with demands for renewable energy and fuel cells and strengthening the roles and responsibilities of local governments; (iv) fostering the growth of the future energy industries (including renewable energy, hydrogen fuel and other efficient sources of energy linked to technology), promoting the value-add for traditional energy industries and maintaining a core energy ecosystem for nuclear power plants; and (v) improving the energy, gas and heat market systems to facilitate the national energy conversion and building platforms based on big data to foster creation of new energy industries.

We cannot assure that the Ninth Basic Plan, the Third Basic National Energy Plan or the respective plans to be subsequently adopted will successfully achieve their intended goals, the foremost of which is to ensure, through carefully calibrated capacity expansion and other means, balanced overall electricity supply and demand in Korea at to end users while promoting efficiency and environmental friendliness in the consumption and production of electricity. If there is significant variance between the projected electricity supply and demand considered in planning our capacity expansions and the actual electricity supply and demand or if these plans otherwise fail to meet their intended goals or have other unintended consequences, this may result in inefficient use of our working capital, mispricing of electricity and undue financing costs on the part of us and our generation subsidiaries, among others, which may have a material adverse effect on our results of operations, financial condition and cash flows.

 

66


Table of Contents

Capital Investment Program

The table below sets forth, for each of the years ended December 31, 2018, 2019 and 2020, the amounts of capital expenditures for the construction of generation, transmission and distribution facilities.

 

2018

  2019     2020  
(In billions of Won)  
₩13,695   15,795     15,485  

The table below sets forth the currently estimated installed capacity for new or expanded generation units to be completed by our generation subsidiaries in each year from 2021 to 2023 based on the Ninth Basic Plan, as amended.

 

Year

   Number of Units    Type of Units    Total Installed Capacity  
               (Megawatts)  

2021

   1    Nuclear power      1,400  
   1    Coal-fired      1,000  
   20    Renewables      124  

2022

   1    Nuclear power      1,400  
   15    Renewables      151  

2023

   1    LNG-combined      495  
   3    Renewables      110  

For the period from 2024 to 2025, our generation subsidiaries currently plan to complete two additional nuclear units with an aggregate installed capacity of 2,800 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 construct and the timing of such construction are subject to change depending upon a variety of factors, including, among others, changes in the Basic Plan, 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.

 

67


Table of Contents

The table below sets forth, for the period from 2021 to 2023, the budgeted amounts of capital expenditures pursuant to our capital investment program, which primarily consist of budgets for the construction of generation, transmission and distribution facilities and, to a lesser extent, renewable energy generation and new energy industry projects. The budgeted amounts may vary from the actual amounts of capital expenditures for a variety of reasons, including, among others, the implementation of the Ninth Basic Plan currently in place, 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.

 

     2021      2022      2023      Total  
     (in billions of Won)  

Generation(1):

           

Nuclear

   3,126      3,308      2,547      8,981  

Thermal

     2,382        3,340        3,718        9,440  

Renewables and others

     644        1,295        870        2,809  
  

 

 

    

 

 

    

 

 

    

 

 

 

Sub-total

     6,152        7,943        7,135        21,230  
  

 

 

    

 

 

    

 

 

    

 

 

 

Transmission and Distribution:

           

Transmission

     2,804        3,157        3,043        9,005  

Distribution

     3,589        3,804        3,703        11,095  
  

 

 

    

 

 

    

 

 

    

 

 

 

Sub-total

     6,393        6,961        6,746        20,100  
  

 

 

    

 

 

    

 

 

    

 

 

 

Others(2)

     1,852        1,406        1,435        4,693  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   14,397      16,310      15,316      46,023  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Notes:

 

(1)

The budgeted amounts for our generation facilities are based on the Ninth Basic Plan, as amended.

(2)

Principally consists of investments in telecommunications and new energy industry projects, among others.

In January 2016, the Ministry of Trade, Industry and Energy announced an initiative to promote the new energy industry by creating the New Energy Industry Fund, which is made up of funds sponsored by government-affiliated energy companies. We contributed Won 500 billion to the funds in 2016. The purpose of these funds is to invest in substantially all frontiers of the new energy industry, including renewable energy, energy storage systems, electric vehicles, small-sized self-sustaining electricity generation grids known as “micro-grids”, among others, as well as invest in start-up companies, ventures, small- to medium-sized enterprise and project businesses that engage in these businesses but have not previously attracted sufficient capital from the private sector.

Furthermore, as a measure to address the high level of particulate matter pollution, in October 2018, the Government introduced a pilot regulation to lower the output of 35 coal-fired generation units to approximately 80% of their capacity that emit more than a certain amount of particulate matter. The regulation was formally implemented in January 2019, targeting 40 coal-fired power plants with high emissions of particulate matter. From March to June 2019, the scope expanded to cover 60 units in total. In addition, coal-fired generation units originally scheduled for preventive maintenance during the second half of 2019 were required to undertake such maintenance earlier in the spring of 2019. In November 2019, the Government pursued a reduction of coal-fired generation units in order to implement the Special Measures to Respond to the High Concentration Period (December to March) of Particulate Matter. During December 2019 to March 2020, 8 to 15 coal-fired generation units that require preventive maintenance or are otherwise older units were first shut down, with a maximum of 49 coal-fired generation units subject to a cap of 80% on the output within the remaining reserve capacity range. We plan to continue to participate in the effort to reduce the particulate matter emissions from coal-fired generation units, not only during the winter but also during the spring. For example, from December 2020 to February 2021, 9 to 17 coal-fired generation units were shut down, with a maximum of 46 coal-fired generation

 

68


Table of Contents

units subject to a cap of 80% on the output within the remaining reserve capacity range. In March 2021, we suspended the operations of 19 to 28 coal power generation plants and imposed a cap of 80% on the output of up to 37 coal-fired generation units. Additionally, the Government adjusted the schedule to close down two decrepit coal-fired generation units (Boryeong #1 and #2), which were shut down in December 2020. Also, other coal-fired generation units, Samcheonpo #1 and #2, are planned to be shut down in May 2021 and Honam #1 and #2 units in December 2021. According to the Ninth Basic Plan announced in December 2020, the total coal-fired power plant capacity in 2030 will decrease to 32.6 gigawatts from 35.8 gigawatts in 2020, and its percentage of total power generation capacity will decrease to 18.9% from 28.1% in 2020. In addition, the Government will introduce a system that will limit the annual power generation of coal-fired power plants in line with its greenhouse gas reduction target. While such measures may be subject to change, we expect to incur significant costs of complying with such measures, including in connection with more stringent particulate matter pollution regulations, retrofitting and overall replacement of environmental facilities.

We have financed, 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, borrowings from overseas financial institutions. In addition, in order to prepare for potential liquidity shortage, we and our generation subsidiaries maintain several credit facilities with financial institutions in the aggregate amounts of Won 5,119 billion and US$1,810 million, the full amount of which was available as of December 31, 2020. We, KHNP, KOMIPO and KOWEPO also maintain global medium-term note programs in the aggregate amount of US$13 billion, of which approximately US$8 billion remains currently available for future drawdown. KOSEP also maintains an A$2 billion Australian dollar medium-term note program, of which approximately A$1.7 billion remains currently available for future drawdown. See also Item 5.B. “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 annual 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, we and 11 of our electricity-related subsidiaries formed the CEO Coordination Committee in June 2016. Additionally, we are endeavoring to develop and implement greenhouse gas reduction strategy in line with the new climate regime set forth by the Paris Climate Agreement.

We continuously endeavor to contribute to sustainable growth (whether as an economy, a society or an ecosystem) by actively taking actions that befit our social responsibility as a corporate citizen in the energy industry. For example, in 2005, we became the first public company in Korea 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 economic, environmental and social policies. As part of our involvement with such initiative, we issue an annual report named the “Sustainability Report” to disclose our activities from the perspectives of economy, environment and society, in accordance with the reporting guidelines of the Global Reporting Initiative, the official collaborating center of the United Nations Environment Program that works in cooperation with United Nations Secretary General. In recognition of our efforts and achievements to reduce greenhouse gas emissions in response to global climate change, in May 2013, we obtained the Carbon Trust Standard certification issued by Carbon Trust, a British nonprofit organization with the goal of establishing a sustainable, low carbon economy. In 2015, we obtained recertification from Carbon Trust by satisfying even more rigorous evaluation criteria. We are also a participant of the Carbon Disclosure

 

69


Table of Contents

Project, an international organization that promotes transparency in informational disclosure of carbon management process, and in 2017, 2018, 2019 and 2020, we were recognized by the Carbon Disclosure Project and received honors in energy and utility sector. In 2020, pursuant to the Dow Jones Sustainability Indices, which measures management performance in terms of contribution to sustainability, we were selected as one of the notable companies in the Asia Pacific in the global electricity utility sector for 7 years in a row from 2014. We recognize the interest in ESG within the investors’ community and are continuously pursuing safe and clean energy supply and distribution by reducing greenhouse gas emissions and enhancing our ability to respond to climate change, the details of such efforts provided through periodic sustainability reports.

We established an Environment, Social and Governance (“ESG”) Committee in our Board of Directors to reinforce ESG-based management system and to ensure continuous performance in this area. Our ESG Committee is charged with resolving major management issues related to ESG, establishing ESG management strategies and business plans and checking on the overall direction of sustainable management. In addition, we made detailed disclosures on our sustainability reports in accordance with the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) and the standards of the Sustainability Accounting Standards Board (SASB) regarding our activities in response to the global climate crisis and our efforts to transition into safe and clean energy sources. In October 2020, we made a statement that we intend to focus on low-carbon and eco-friendly overseas projects, such as new renewable energy and combined gas power generation, and not pursue new projects in coal-fired power plants. For those overseas coal-fired power plant projects we are already engaged in, we intend to work on those in an environmentally friendly way by applying more stringent environmental standards than the international standards. Also, we issued green bonds in 2019 and 2020, each issuance with the principal amount of US$500 million, to expand domestic and overseas renewable energy businesses and renewable energy related facilities.

The table below sets forth the number of emission control equipment installed at thermal power plants by our generation subsidiaries as of December 31, 2020.

 

     KOSEP      KOMIPO      KOWEPO      KOSPO      EWP  

Flue Gas Desulphurization System

     12        12        11        8        15  

Selective Non-catalytic Reduction System

     1        —          —          —          7  

Selective Catalytic Reduction System

     22        21        19        19        29  

Electrostatic Precipitation System

     16        14        10        12        17  

Low NO2 Combustion System

     22        366        27        30        28  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     73        413        67        69        96  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

In accordance with the Act on Allocation and Trading of Greenhouse Gas Emission Allowances, enacted in March 2013, the Government implemented a greenhouse gas emission trading system under which the Government will allocate the amount of permitted greenhouse gas emission to companies by industry and a company whose business emits more carbon than the permitted amount is required to purchase the right to emit more carbon through the Korea Exchange. The categories of allowances traded include the Korean Allowance Unit (KAU), which is the emissions allowance allocated to applicable companies by the Government; Korean Credit Unit (KCU), which is a tradable unit converted from external carbon offset certifications including the Korean Offset Credit; and Korean Offset Credit (KOC), which is the verified carbon offset credit obtained by companies for reducing carbon emissions through absorption or otherwise. The greenhouse gas emission trading system is expected to be implemented in three stages. During the first phase (2015 to 2017), the Government set up and conducted a test run of the trading system to ensure its smooth operation, allocating the greenhouse gas emission allowances free of charge. In July 2018, the Government released the allocation plan for the second phase (2018 to 2020), during which 97% of the greenhouse gas emission allowances were allocated free of charge, with 3% allocated through an auction. During the third phase (2021 to 2025), the Government expanded the scale of the system with aggressive greenhouse gas emission reduction targets and allocating 10% of the greenhouse gas emission allowances through an auction. In December 2016, the Government announced the

 

70


Table of Contents

Climate Change Response Initiatives and the 2030 National Greenhouse Gas Reduction Roadmap, which set forth the greenhouse gas emission trading system as one of the primary means to reach the emission and greenhouse gas reduction targets of the policies. According to the Nationally Determined Contributions (NDC) announced by the Government in December 2020, the total greenhouse gas emission target level by 2030 is a 24.4% reduction as compared to the level in 2017, and the reduction target for the electricity conversion sector as a whole which we are the part of is a total of 60 million tons as compared to the level in 2017. In addition, in December of 2020, the government announced the Long-term low greenhouse gas Emission Development Strategies (LEDS) and presented a long-term vision and national strategy for achieving carbon neutrality in 2050.

Adhering to such emission and greenhouse gas reduction requirement may result in significant additional compliance costs. For example, the daily market price of the KAUs traded through the Korea Exchange was Won 8,640 per ton in early 2015, and the price has increased continuously thereafter, reaching its peak price at Won 42,500 per ton on April 2, 2020. Since then, the price has been lowered due to the influence of COVID-19, and, as of the end of 2020, the price has been formed in the range of Won 20,000 per ton.

The table below sets forth the amount of annual emission from all generating facilities of our generation subsidiaries for the periods indicated. The amount of CO2 emissions is expected to decrease in the long-term, principally due to an increased use of LNG on account of the fact that 24 coal-fired power plants with total capacity of 12.7 gigawatts are scheduled to be converted into LNG-fired power plants before the end of 2034, an increased use of renewable energy and the implementation of the greenhouse gas emission trading system.

 

Year(1)

   SOx
(g/MWh)
     NOx
(g/MWh)
     TSP(2)
(g/MWh)
     CO2
(kg/MWh)
 

2016

     156        246        7        477  

2017

     138        177        7        506  

2018

     120        146        7        516  

2019

     89        114        5        494  

 

Notes:

 

(1)

The amounts of annual emission for 2020 are expected to be determined in June 2021.

(2)

“TSP” means Total Suspended Particles.

While the Third Basic National Energy Plan prohibits construction of new coal-fired power plants, the additional coal-fired power plants under construction by KEPCO are pursuant to the Sixth Basic Plan released in 2013. In constructing the new power plants, we are applying the “Ultra Super Critical” technology designed to minimize emission of pollutants and maximize the efficiency by reducing the coal consumption. We are also committed to lowering our exposure to coal-generated energy in the long-term. For additional information, see Item 3.D. “Risk Factors—We are subject to various environmental legislations, regulations and related government initiatives, including in relation to climate change, which could cause significant compliance costs and operational liabilities.”

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 environment-friendly measures to foster community goodwill. For example, under the Persistent Organic Pollutants Management Act enacted in 2007, we are required to remove polychlorinated biphenyl, or PCB, a toxin, from the insulating oil of our transformers by 2025. 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, and we 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 example, by using more environment-friendly technology and hardware. In addition, we also undertake measures to minimize losses during the

 

71


Table of Contents

transmission and distribution process 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 acquired the ISO 14001 certification, an environmental management system widely adopted internationally, in 2007 and have made it a high priority to make our electricity generation and distribution more environmentally friendly. In 2014, we were awarded the presidential award for environmental contributions as a corporate citizen, after scoring the highest among 102 corporations that competed for the award. In order to encourage the implementation of environment-friendly measures by other corporations and enhance environmental awareness at a social level, we have been disclosing our environment-related activities and achievements to the public through the Environment Information System managed by the Ministry of Environment since 2012.

Our environmental measures, including the use of environment-friendly but more expensive parts and equipment and allocation of 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 on 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.

As part of our long-term strategic initiatives, we plan to take other measures designed to promote the generation and use of environmentally friendly, or green energy. See Item 4.B. “Business Overview—Strategy.” In line with such strategic initiatives, we are, among others:

 

   

investing in and researching technologies that capture and utilize carbon dioxide;

 

   

planning to develop capacity of 41.2 gigawatts of renewable energy by 2030 with our generation subsidiaries according to our “Renewable Energy 3020” initiative;

 

   

implementing a mid- to long-term goal of “energy shift through expanding renewable energy”, reviewed and approved by our board in October 2019;

 

   

focusing on low-carbon and eco-friendly overseas projects, such as new renewable energy and combined gas power generation, and not pursuing new projects in coal-fired power plants;

 

   

working on the overseas coal-fired power plant projects we are already engaged in an environmentally friendly way by applying more stringent environmental standards than the international standards; and

 

   

releasing detailed disclosures on our sustainability reports in accordance with the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) and the standards of the Sustainability Accounting Standards Board (SASB) regarding our activities in response to the global climate crisis and our efforts to transition into safe and clean energy sources.

Some of our generation facilities 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 our total generation capacity or generation volume of our generation subsidiaries, we expect that the portion will increase in the future, especially since we are required to comply with the Renewable Portfolio Standard program as described below.

 

72


Table of Contents

The following table sets forth the generation capacity and generation volume in 2020 of our generation facilities that are powered by renewable energy sources.

 

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

Hydraulic Power(1)

     652       1,231  

Wind Power

     144       202  

Solar Energy, Fuel Cells, Biogas and others

     1,520       6,889  
  

 

 

   

 

 

 

Subtotal

     2,316       8,322  

As percentage of total(2)

     2.8     2.1

 

Notes:

 

(1)

Excluding generation capacity and volume of pumped storage, which is generally not classified as renewable energy.

(2)

As a percentage of the total generation capacity or total generation volume, as applicable, of us and our generation subsidiaries.

In order to deal with shortage of fuel and other resources and also to comply with various environmental standards, in 2012 the Government adopted the Renewable Portfolio Standard program, which replaced the Renewable Portfolio Agreement which had been in effect from 2006 to 2011. Under this program, each of our generation subsidiaries is required to generate a specified percentage of total electricity to be generated by such generation subsidiary in a given year in the form of renewable energy or, in case of a shortfall, purchase a corresponding amount of a Renewable Energy Certificate (a form of renewable energy credit) from other generation companies whose renewable energy generation surpass such percentage. The target percentage was 6.0% in 2019, 7.0% in 2020 and 9.0% 2021 and will incrementally increase to 10.0% by 2022. Fines are to be levied on any subsidiary that fails to do so in the prescribed timeline. In 2019, all six of our generation subsidiaries met the target through renewable energy generation and/or the purchase of a Renewable Energy Certificate. Compliance by our generation subsidiaries of the 2020 target is currently under evaluation, and if any generation subsidiary is found to have failed to meet the target for 2020 or for subsequent years, such generation subsidiary may become subject to fines. Additionally, as the target percentage is subject to change, changes to the target percentage may result in additional expenses for our generation subsidiaries. From October 2021, an amendment to the Act on the Promotion of the Development, Use, and Diffusion of New and Renewable Energy will become effective to raise the upper limit of the target percentage even higher to 25% from the previous threshold of 10%.

As to how we plan to finance our capital expenditures related to our environmental programs, see “—Capital Investment Program.”

In March 2017, the Electric Utility Act was amended to the effect that starting in June 2017, future national planning for electricity supply and demand in Korea should consider the environmental and safety impacts of such planning, such as desulphurization costs. Accordingly, the costs related to environmental and safety impacts such as the desulphurization costs, have been reflected in our variable cost of generating electricity since August 2019. In December 2019, the Regulation on the Operation of the Electricity Market was revised, under which specific provisions of the Cost Evaluation Committee (defined below) to reflect the cost of greenhouse gas emission allowances were to be finalized in two years. The provisions were established in February 2021 and will be implemented from January 2022.

Furthermore, under the new electricity rate structure effected by the Government effective January 1, 2017, a temporary rate discount will apply in the case of investments in environmentally friendly facilities such as energy storage systems, renewable energy and electric cars. While the initial temporary rate discount had applied between 2017 and 2019, it was extended until 2020. Starting in January 2021, we rolled back the discount for energy storage systems by decreasing it from three times the Base Charge to one times the Base Charge and discontinuing the 50% discount on the Usage Charge. The discount of one times the Base Charge is planned to

 

73


Table of Contents

also phase out in March 2026 as we originally intended. In addition, we intend to designate a three-hour time period during peak time and induce discharge during that period by giving more discount benefits to the customers. The second of the two discounts being rolled back is a 50% discount for customers who installed a renewable energy generator for their own industrial and general uses. We originally introduced this discount to encourage an increased supply of renewable energy. We discontinued this discount in 2020 while only maintaining it for customers who are unable to sell their electricity in the market because of their small generation capacities (less than 10 kilowatts). The discount for such customers is planned to be discontinued by 2023. Furthermore, in order to mitigate any potential burden on the consumers and shock to the electric car market, the temporary rate discount will be incrementally phased out by June 2022.

In line with the spread of RE100, a global campaign by companies around the world to cover 100% of their electricity use with renewable energy by 2050, the Government in 2021 introduced its own version of RE100 that allows companies and other consumers to choose the energy sources from which their electricity is generated. In order for a domestic company to participate in RE100, it needs to enter into a power purchase agreement either with a renewable energy generator through us as an intermediary (third party PPA) or with a renewable energy generator directly such that the generator will supply electricity to the company without going through the existing electricity market (corporate PPA), or general and industrial customers may also purchase renewable energy through us in a competitive bidding process and be issued with a certificate of use of renewable energy, which we refer to as the green premium system. It is difficult to predict what effects the third party PPA will have on us as the new system has not been finalized yet, but the relevant legislation for the corporate PPA was enacted in the National Assembly in March 2021. If there is an expansion in the use of corporate PPA, it may adversely affect our market share in electricity sales. The green premium system started in January 2021 and we, on behalf of Korea Energy Agency, are in charge of managing the bidding for renewable energy, receiving bid prices from winning companies, issuing a certificate of use of renewable energy to companies on a quarterly basis and receiving fees from Korea Energy Agency for our service.

Community Programs

Building goodwill with local communities is important to us 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 and the Act on the Compensation and Support for Areas Adjacent to Transmission and Substation Facilities require that the generation companies and the affected local governments carry out various activities up to a certain amount annually to address neighboring community concerns. Pursuant to these Acts, 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.

Under the Act for Supporting the Communities Surrounding Power Plants, activities required to be undertaken under the Act are funded partly by the Electric Power Industry Basis Fund (see “—Sales and Customers—Electricity Rates”) and partly by KHNP as part of its budget. KHNP is required to make annual contributions to the affected local communities in an amount equal to Won 0.25 per kilowatt-hour of electricity generated by its nuclear generation units during the one-year period before the immediately preceding fiscal year, Won 5 million per thousand kilowatts of hydroelectric generation capacity and Won 0.5 million per thousand kilowatts of pumped-storage generation capacity. In addition, under Korean tax law, KHNP is required to pay local tax levied on its nuclear generation units in an amount equal to Won 1 (effective January 1, 2015, which reflects an increase from the previous Won 0.5 per kilowatt-hour of their generation volume in the affected areas) and Won 2 per 10 cubic meters of water used for hydroelectric generation.

The Act on the Compensation and Support for Areas Adjacent to Transmission and Substation Facilities, enacted in January 2014 with effect from July 2014, prescribes measures to be taken by power generation or transmission companies with respect to the communities adjacent to transmission and substation facilities. Under this Act, those who own land or houses in the vicinity of transmission lines and substation may claim

 

74


Table of Contents

compensation for damages or compel purchase of such properties by the power generation or transmission companies which are legally obligated in principle to pay for such damages or purchase such properties. In addition, under this Act, residents of communities adjacent to transmission and substation facilities are entitled to subsidies on electricity tariff as well as support for a variety of welfare projects and collective business ventures.

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 Trade, Industry and Energy following agreement with related administrative bodies, including 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, civic community groups may still oppose the construction and operation of generation units (including nuclear units), and such opposition could adversely impact our construction plans for generation units (including nuclear units) and have a material adverse effect on our business, results of operations and cash flow.

Upon relocation of our corporate headquarters in November 2014, we developed and established Bitgaram Energy Valley as a smart energy hub city in Gwangju and Jeollanam-do, to attract and facilitate the growth of start-ups and research institutions related to new energy industries while contributing to the local economy, balanced regional development and job creation. To achieve this goal, we provide funding, business networks and research and development assistance to companies which entered into investment contracts with us. As of December 31, 2020, we have signed agreements with 501 companies relating to investments in the Bitgaram Energy Valley, outperforming our target in 2015 of 500 companies. We are currently developing Bitgaram Energy Valley to establish a spontaneous industrial ecosystem, which will contribute to the power industry as well as the national economy.

Nuclear Safety

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

KHNP has a corporate code of ethics and is firmly committed to enhancing nuclear safety, developing new technologies and improving transparency. KHNP has also established the “Statement of Safety Policy for Nuclear Power Plants” to ensure the highest level of nuclear safety. Furthermore, KHNP invests approximately 5% of its total annual sales into research and development for the enhancement of nuclear safety and operational performance.

KHNP implements 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, including for low power-shutdown states, 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 #1, #2, #3, #4; Hanbit #1, #2, #3, #4, #5, #6; Wolsong #1, #2, #3, #4; and Hanul #1, #2, #3, #4, #5, #6 once or more. Reviews for Shin-Kori #1 and #2 are in progress. In order to enhance nuclear safety and plant performance, KHNP has established a maintenance effectiveness monitoring program based on the maintenance rules issued by the United States Nuclear Regulatory Commission, which covers all of KHNP’s nuclear power plants in commercial operation.

KHNP has developed the Risk Monitoring System for operating nuclear power plants, which it implements 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 and is developing the Severe Accident Management Guidelines for Low Power-Shutdown States in order to manage severe accidents for all of its nuclear power plants.

 

75


Table of Contents

KHNP conducts various activities to enhance nuclear safety such as quality assurance audits and reviews by the KHNP Nuclear Review. KHNP maintains a close relationship with international nuclear organizations in order to enhance nuclear safety. KHNP invites international safety review teams such as the World Association of Nuclear Operators (“WANO”) Peer Review 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. For example, KHNP conducted WANO Pre-Startup Peer Reviews for Shin-Hanul #1 unit in 2020. The recommendations and findings from this event were shared with KHNP’s other nuclear plants to implement improvements at such plants. In addition, KHNP has applied for the Operational Safety Review Team at the International Atomic Energy Agency to conduct a mission at Shin-Kori #3 and #4 units in the second half year of 2022. The purpose of such application was to ensure that KHNP nuclear generation units reflect the global safety standards.

The average level of radiation dose per unit amounted to a relatively low level of 0.34 man-Sv in 2020, which was substantially lower than the global average of 0.57 man-Sv/year in 2020 as reported in the WANO performance indicator report.

In response to the damage to the nuclear facilities in Japan as a result of the tsunami and earthquake in March 2011, the Government conducted additional safety inspections on nuclear power plants by a group of experts from governmental authorities, civic groups and academia. As a result of such inspections, the Government required KHNP to perform 46 comprehensive safety improvement measures. As of December 31, 2020, KHNP has completed implementation of 45 measures and will implement the one remaining measure by 2024. The Government also established the Nuclear Safety & Security Commission in October 2011 for neutral and independent safety appraisals. KHNP developed ten additional measures through benchmarking of overseas cases and internal analysis of current operations. As of December 31, 2020, KHNP has completed implementation of nine measures and will implement the one remaining measure by 2023.

From time to time, our nuclear generation units may experience unexpected shutdowns. For example, on September 12, 2016, multiple earthquakes including a magnitude 5.8 earthquake hit the city of Gyeongju, a home to KHNP’s headquarters and Wolsong Nuclear Power Plant. Although there was no material safety issues, KHNP had manually stopped the operations of Wolsong Nuclear Power Plant units #1, 2, 3, and 4 according to the safety guidelines. All units have resumed their operations on December 5, 2016, with the approval by the Nuclear Power Safety Commission. KHNP finished implementing measures to improve the safety by reinforcing seismic capability of its core facilities and performing stress tests across all its nuclear power plants. In 2018, KHNP finished the implementation of such measures for 24 units and enhanced seismic capability of the core facilities to withstand a magnitude 7.0 earthquake (6.5 before implementation). As for the units under construction (Shin-Kori#5 and #6), the core facilities will be able to withstand a magnitude 7.4 earthquake.

Low and intermediate level waste, or LILW, and spent fuels are stored in temporary storage facilities at each nuclear site of KHNP. The temporary LILW storage facilities at the nuclear sites had been sufficient to accommodate all LILWs produced up to 2015. Korea Radioactive Waste Agency (“KORAD”) completed the construction of a LILW disposal facility in the city of Gyeongju, and government approval for its operations was obtained in December 2014.

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 and building dry storage facilities. Through these activities, we expect that the storage capacity for spent fuels in all nuclear sites will be sufficient to accommodate all the spent fuels produced by 2021. The policy for spent fuel management options is currently under development.

In 2009, the Radioactive Waste Management Act (“RWMA”) was enacted in order to centralize management of the disposal of spent fuels and LILW and enhance the security and efficiency of related management processes. The RWMA designates KORAD to manage the disposal of spent fuels and LILW.

 

76


Table of Contents

Pursuant to the RWMA, the Government has established the Radioactive Waste Management Fund. The management expense for LILW is paid when LILW is transferred to KORAD, and the charge for spent fuels is paid based on the quantity generated every quarter. LILW-related management costs and charges for spent fuels are reviewed by the Ministry of Trade, Industry and Energy every two years. In December 2019, after the review by the committee composed of Government officials, KHNP, Korea Radioactive Waste Management Corporation and experts in finance and accounting, LILW-related management costs were increased while charges for spent fuels remained the same. The change in LILW-related management costs caused an increase in KHNP’s expenses relating to radioactive waste.

In addition, in February 2021, in accordance with the Government’s guidelines for strengthening the safety of nuclear power plants, the period for verifying seismic resilience of major equipment was extended. In light of the fact that forced efforts to shorten the process could endanger the workers, the construction period of Shin-Kori #5 and #6 units have been extend by twelve months and nine months to March 2024 and March 2025, respectively.

All of KHNP’s nuclear plants are currently in compliance with Korean law and regulations and the safety standards of the IAEA in all material respects. For a description of certain past incidents relating to quality assurance in respect of KHNP, see Item 3.D. “Risk Factors—Our risk management policies and procedures may not be fully effective at all times.”

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 implements a dismantling policy under which dismantling would take place five to ten years after the unit’s closure. KHNP renewed the operating license of Kori #1, the first nuclear power plant constructed in Korea, which commenced operation in 1978, for an additional ten years in 2007. At the recommendation of the Ministry of Trade, Industry and Energy, KHNP has decided not to renew the operating license of Kori #1 and the initial phase of decommissioning (namely, safety inspection and removal of spent fuels) of Kori #1 has begun after its permanent shutdown in June 2017. In February 2015, KHNP also renewed the operation license of Wolsong #1 (which originally expired in November 2012) for an additional ten years until 2022. In June 2015, reactivation of Wolsong #1 was approved by the NSSC after periodic inspection. However, a civic group has since then brought a lawsuit to reverse such approval, and in February 2017, a lower court ruled to annul the NSSC’s approval, which ruling has since been appealed. On June 15, 2018, the board of directors of KHNP decided to (i) retire Wolsong #1 unit earlier than planned due to comprehensive evaluation of the economic viability and regional sentiment of its continuing operation and (ii) discontinue the construction of Chunji #1 and #2 as well as Daejin #1 and #2 units. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Wolsong #1 unit accrued to Won 572,216 million and reversal of impairment loss was Won 16,693 million. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Chunji #1 and #2 as well as Daejin #1 and #2 units amounted to Won 38,886 million. Although the board of directors did not make any decisions regarding Shin-Hanul #3 and #4 units, which are new nuclear plants under construction, we cannot assure you that the construction of these units will not be discontinued. From the beginning of 2018 to the end of 2019, impairment loss in connection with the property, plant and equipment of Shin-Hanul #3 and #4 units accrued to Won 134,736 million. As of December 31, 2020, the impairment loss for each unit is still the same amount. KHNP retains full financial and operational responsibility for decommissioning its units.

KHNP has accumulated decommissioning costs as a liability since 1983. The decommissioning costs of nuclear facilities are defined by the Radioactive-Waste Management Act, which requires KHNP to credit annual appropriations separately. These costs are estimated based on studies conducted by the relevant committees, and are reviewed by the Ministry of Trade, Industry and Energy every two years. In 2019, the actual discount rates decreased and the decommissioning cost per unit increased. As of December 31, 2020, KHNP was required to accrue Won 20,074 billion for the costs of dismantling and decontaminating existing nuclear power plants, which

 

77


Table of Contents

consisted of dismantling costs of nuclear plants of Won 16,975 billion and dismantling costs of spent fuels and radioactive waste of Won 3,099 billion. For accounting treatment of decommissioning costs, see Item 5.A. “Operating Results—Critical Accounting Policies—Decommissioning Costs of Nuclear Plants, Spent Fuels and Radioactive Waste.”

Overseas Activities

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

Throughout the years, we have sought to expand our project portfolio to include the construction and operation of conventional thermal generation units, nuclear generation units and renewable energy power plants, transmission and distribution and mining and development of fuel sources. While strategically important, we believe that our overseas activities, as currently being conducted, are not in the aggregate significant in terms of scope or amount compared to our domestic activities. 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 course of negotiating the definitive agreements. In October 2020, we made a statement that we intend to focus on low-carbon and eco-friendly overseas projects, such as new renewable energy and combined gas power generation, and not pursue new projects in coal-fired power plants. For those overseas coal-fired power plant projects we are already engaged in, we intend to work on those in an environmentally friendly way by applying more stringent environmental standards than the international standards.

Below is a description of our major overseas projects.

Generation Projects

Nuclear Generation Projects

In December 2009, following an international open bidding process, we entered into a prime contract for the original contract amount of US$18.6 billion with the Emirates Nuclear Energy Corporation (“ENEC”), a state-owned nuclear energy provider of the United Arab Emirates (“UAE”), to design and construct four civil nuclear power generation units to be located in Barakah, a region approximately 270 kilometers from Abu Dhabi, for the UAE’s peaceful nuclear energy program. Under the contract, we and our subcontractors, some of which are our subsidiaries, are to perform various duties including, among others, designing and constructing four nuclear power generation units each with a capacity of 1,400 megawatts, supplying nuclear fuel for three fuel cycles including initial loading, with each cycle currently projected to last for approximately 18 months, and providing technical support, training and education related to plant operation. The target completion dates for the four units are currently under discussion for an amendment between the parties and will be disclosed after confirmation. The contract amount of US$18.6 billion was increased to US$19.1 billion as per the amendment signed in November 2017.

On October 20, 2016, in order to foster a long-term strategic partnership and stable management of the units’ post-construction we entered into an investment agreement with ENEC to jointly establish Barakah One PJSC, a special purpose company which will oversee the operation and management of the nuclear power plant currently being constructed in Barakah, United Arab Emirates. Barakah One PJSC is capitalized with loans in the amount of US$19.6 billion and equity of US$4.7 billion. We have an 18% equity interest in Barakah One PJSC, and also have an 18% equity interest in Nawah Energy Company, a subsidiary of ENEC, which will also be responsible for the operation and maintenance of the Barakah nuclear power plant. On December 20, 2018, the board of directors of KEPCO resolved to invest additional US$380 million in Barakah One PJSC. With the

 

78


Table of Contents

additional investment, KEPCO’s total capital investment amount in Barakah One PJSC is expected to be US$1.28 billion. KEPCO’s equity interest in the project is 18%, which remains unchanged. The total project cost of the construction and operation of the Barakah nuclear power plant is expected to be approximately US$29.5 billion, and the operational period is expected to be 60 years after the project commercial operation date in 2025. Actual capital contribution is currently scheduled to be made in September 2025.

Non-nuclear Generation Projects

We are currently engaged in three major power projects in the Philippines: (i) a “build, operate and transfer” of a 1,200-megawatt combined-cycle power plant project in Ilijan, of which an energy conversion agreement with National Power Corporation (“NPC”) was entered into in November 1997. Construction of this project was completed in June 2002 and which is being operated by us until 2022 (the project cost of the Ilijan project was US$721 million, for which project finance on a limited recourse basis was provided), (ii) ownership of a 39.6% equity interest in SPC Power Corporation, an independent power producer, and a 39.6% equity interest in two distribution companies in the Philippines, and (iii) a “build, operate and own” of a 200-megawatt CFBC coal power plant in Cebu for which construction began in December 2007 and was completed in May 2011, followed by operation thereof until 2036. The project cost of the Cebu project was US$451 million, for which project financing on a limited recourse basis was provided.

In April 2007, we formed a limited partnership with Shanxi International Electricity Group and Deutsche Bank in China to develop and operate power projects in Shanxi province, China, which was approved by the Chinese government. The total capital investment in these projects amounted to US$1.33 billion, of which our capital investment was US$450 million. We are expected to participate in the operation of the project for a period of 50 years ending 2057. The total capacity of these projects is 9,217 megawatts and our equity interest in the partnership was 34%.

In July 2008, a consortium consisting of us and Xenel of Saudi Arabia won the bid to “build, own and operate” a gas-fired power plant with installed capacity of 373 megawatts in Al Qatrana, near Amman, and we entered into definitive agreements in October 2009. Construction of this project was completed in December 2011, and the plant is currently in operation and will be operated until 2035. The total project cost was US$461 million, of which the consortium made an equity contribution of US$143 million and the remainder was funded with debt financing. We and Xenel own 80:20 equity interests in the project, respectively.

In December 2008, we formed a consortium with ACWA Power International of Saudi Arabia and submitted a bid for the 1,204 megawatts oil-fired power project in Rabigh, Saudi Arabia. In March 2009, we were selected as the preferred bidder, and in July 2009, we entered into a power purchase agreement with Saudi Electricity Company. Construction of the project was completed in April 2013, and we will participate in the operation of the plant for 20 years. The total project cost was approximately US$2.5 billion. We currently hold a 40.0% equity interest in the joint venture entity, Rabigh Electricity Company, which operates the project.

In August 2010, a consortium led by us was selected as the preferred bidder in an international auction for the construction and operation of the Norte II gas-fueled combined-cycle electricity generation facility in Chihuahua, Mexico, as ordered by the Commission Federal de Electricidad (“CFE”) of Mexico. The consortium established a special purpose vehicle, KST Electric Power Company (“KST”), to act as the operating entity, and in September 2010, KST entered into a power purchase agreement with CFE in relation to the construction and operation of a 433-megawatt combined-cycle power plant at Chihuahua in Mexico. In October 2010, KST was licensed by the Mexican government as an independent power producer, which allows it to produce and sell electricity to CFE during the specified contract period. The project will be undertaken on a “build, own and operate” basis. The total cost of the project is approximately US$427 million. We hold a 56% equity interest in the consortium, with the remaining equity interests held by Samsung Asset Management (34% equity interest) and Techint, a company based in Mexico (10% equity interest). Approximately 6% (equating to 24% before refinancing) of the total project costs is being financed through equity investments by the consortium and the

 

79


Table of Contents

remaining 94% (equating to 77.5% before refinancing) through the project bond issuance guaranteed by Export-Import Bank of Korea. Commercial operation of this project commenced in December 2013, and the operation period will run for 25 years until 2038. Our wholly-owned subsidiary, KEPCO Energy Service Company, currently manages the operation of the project.

In October 2010, a consortium including us was selected by Abu Dhabi Water & Electricity Authority (“ADWEA”), a state-run utilities provider in the UAE, as the preferred bidder in an international bidding for the construction and operation of the combined-cycle natural gas-fired electricity generation facilities in Shuweihat, UAE with aggregate capacity of 1,600 megawatts. Construction was completed in July 2014 and we will participate in the operation of the plant until 2039. The total project cost was approximately US$1.4 billion, of which 20% was financed through equity investments by the consortium members and the remaining 80% through debt financing. Equity interests in the consortium are owned by ADWEA (60.0%), Sumitomo (20.4%) and us (19.6%). The total amount of our equity investment in the project is approximately US$56 million.

In January 2012, a consortium consisting of us, Mitsubishi Corporation and Wartsila Development & Financial Services of Finland was selected by National Electric Power Corporation, a state-run electricity provider in Jordan, to construct and operate a diesel engine power project in Al Manakher with an expected total generation capacity of 573 megawatts. Construction of this project was completed in October 2014 and the plant is currently in operation and will be operated until 2039. The total project cost was approximately US$760 million, of which the consortium made an equity contribution of approximately US$190 million and the remainder was funded with debt financing. We, Mitsubishi Corporation and Wartsila Development & Financial Services own 60:35:5 equity interests in the project, respectively. Our equity investment in this project is US$104 million.

In March 2013, a consortium consisting of us and Marubeni, a Japanese corporation, was selected by the Ministry of Industry and Trade of Vietnam for the construction and operation of a 1,200 megawatts coal-fired power plant in Thanh Hoa province, Vietnam. We started construction in July 2018 and to complete completion by July 2022, followed by operation for 25 years. The total project cost is expected to be US$2.5 billion, of which 24% will be funded by equity contribution and the remaining 76% by debt financing. The share capital of the special purpose entity in charge of this project is US$568 million, and we, Marubeni, and Tohoku Power hold 50%, 40%, and 10% equity interest in the consortium, respectively.

On October 6, 2016, a consortium comprised of us, Marubeni Corporation and four local entities, with equity interest in the consortium of 24.5%, 24.5% and 51.0%, respectively, was notified that it has been selected by the Republic of South Africa Department of Energy as the preferred bidder for the construction and operation project of a coal-fired power plant in the Republic of South Africa. However, in consideration of environmental lawsuits and deteriorating coal-fired power plant business conditions, we plan to discuss discontinuing the project with the relevant department once the COVID-19 situation in South Africa eases off.

On January 2, 2020, Pulau Indah Power Plant, a special purpose company in which KEPCO owned 25% shares, received a Letter of Notification to develop a 1,200MW combined-cycle gas-fired power plant from Energy Commission, the host entity of the project. The project is now being developed by a consortium of us (25%) and Worldwide Holding Bhd (75%), a wholly owned subsidiary of the Selangor State Development Corporation. The construction started in December 2020 and is expected to be completed by January 2024. The total project cost is expected to be approximately US$766 million, and we expect to invest approximately US$39 million for the equity interest. We signed a power purchase agreement (PPA) in August 2020 with Tenaga Nasional Berhad (TNB), which will be effective from January 2024 for a period of 21 years. This project marks our first entry into the Malaysian power generation market.

On November 5, 2019, we entered into an Energy Conversion Agreement comprising of a power purchase agreement with the Guam Power Authority for a term of 25 years to construct and operate Ukudu gas-fired power plants in Guam, United States, including 198 megawatts gas fired power plant, 39 megawatts back-up

 

80


Table of Contents

diesel generator and 25 megawatts energy storage facility. KEPCO and Korea East-West Power Co., Ltd., hold 60% and 40% shares in the project, respectively. The total project cost is expected to be approximately US$727 million, and we expect to invest US$87 million for the equity interest. The construction of the project is expected to commence in 2021 upon approval of the environmental impact assessment and the issuance of relevant permits. The power station is expected to commence commercial operation in 2024. The completed power plants are expected to be operated as base load generators, replacing the existing old heavy fuel power plants in Guam.

On June 30, 2020, our board of directors approved our plan to invest US$51 million in the expansion of two coal-fired power plants called Java 9 and Java 10 on the Indonesian island of Java. We will invest together with PT Perusahaan Listrik Negara (“PLN”), an Indonesian state electricity company, and PT Barito Pacific Tbk., an Indonesian company. The total investment will be approximately US$3.39 billion and each of KEPCO, PLN and Barito Pacific will respectively own 15%, 51% and 34% shares in the joint venture. The joint venture will manage the construction of two planned units of one gigawatt generation capacity each. Doosan Heavy Industries & Construction Co., Ltd. and PT. Hutama Karya, an Indonesian government-owned company, formed a consortium to act as the construction contractor for the project. Korea Development Bank, the Export-Import Bank of Korea, and Korea Trade Insurance Corporation are our lenders for the project. The construction of Java 9 is expected to be completed in the fourth quarter of 2024 and Java 10 is expected to be completed in the first quarter of 2025. The joint venture is a party to a 25-year power purchase agreement with PLN.

On October 5, 2020, our board of directors approved our plan to invest US$2.05 million in the construction of Vung Ang 2 coal-fired power plant in Vietnam in exchange for 40% shares in the project. The new plant will be located in Ha Tinh Province, Vietnam, adjacent to Vung Ang 1 power plant and will consist of two units with 600 megawatts generation capacity each. The construction is expected to start in the first half of 2021. The power plant is expected to be completed in 2025. Diamond Generating Asia, a subsidiary of Mitsubishi Corporation, a Japanese corporation, is the main sponsor of this project. Doosan Heavy Industries & Construction Co., Ltd. and Samsung C&T Corporation will participate as the Engineering, Procurement, and Construction (EPC) contractors. We will secure financing from the Export-Import Bank of Korea. We will operate this plant together with other co-investors for 25 years.

Exploration and Production Projects

In order to secure a more reliable supply of fuel for power generation and hedge against fluctuations in fuel price, from 2007 to 2016, we pursued overseas exploration and production projects, including five bituminous coal projects and five uranium projects involving investments of approximately Won 1.4 trillion. However, pursuant to the Government’s Proposal for Adjustment of Functions of Public Institutions (Energy Sector) announced in June 2016, as of December 31, 2016, except for the Bylong project described below, we transferred all our assets and liabilities for our overseas resource business to our six generation subsidiaries, which are the end-consumers of fuels and are therefore expected to more responsively manage these projects. The amount of net assets that we transferred to our generation subsidiaries as of December 31, 2016 was Won 622 billion.

One exception to the transfers on such date was our 90% equity interest in KEPCO Bylong Pty Ltd (“KEPCO Bylong”). We transferred 10% of our equity interest in the KEPCO Bylong to our five non-nuclear generation subsidiaries as of December 31, 2016, and we plan to gradually transfer the remainder of our interest to them subject to the progress of the regulatory approval process and resource production phase of the project. In July 2015, KEPCO Bylong lodged a development application to the State Government of New South Wales (the “NSW”) of Australia. In September 2019, Independent Planning Commission of the NSW, which is the governmental authority with the approval power, refused to grant KEPCO Bylong’s development application. As of December 31, 2020 we have invested approximately Won 810 billion in the Bylong project, and, as of December 31, 2020, impairment loss in connection with the Bylong project accrued to approximately Won 540 billion. We filed for a judicial review against the Independent Planning Commission at the Land and Environment Court of New South Wales, Australia in December 2019 for its violations in the development

 

81


Table of Contents

permit evaluation process. The Court ruled against us in December 2020 but we submitted a Notice of intention to appeal to the Supreme Court of New South Wales, Court of Appeal, and plan to proceed with the appeal.

Our nuclear generation subsidiary, KHNP, is also pursuing development projects for procurements of uranium in countries including Canada, France and Niger.

Renewable Energy Projects

Our overseas renewable energy projects include the generation of electricity through renewable energy sources.

Since 2005, joint ventures between us and China Datang Corporation of the People’s Republic of China have built and operated a number of wind farms in Inner Mongolia, Liaoning and Gansu provinces. We own 40% of these joint ventures, whose equity in the aggregate amount is approximately US$450 million. The projects are funded one-third by equity contributions and two-thirds by debt financing. As of December 31, 2020, the joint venture operated 22 wind farms with a total capacity of 1,017 megawatts and a 7-megawatt photovoltaic power station.

In December 2015, we entered into an agreement with the Ministry of Energy and Mineral Resources of Jordan to build, own and operate a wind farm with installed capacity of 89.1 megawatts in Fujeij, Ma’an, Jordan. Commercial operations commenced on July 14, 2019. Total project cost is approximately US$181 million, of which 40% is financed through equity investments by us and the remaining 60% through debt financing. We believe that this project will help us to further diversify our business portfolio in the Middle East from the existing focus on nuclear and thermal power plants to expand to renewable energy facilities.

In June 2015, we entered into a memorandum of understanding with Energy Product, a Japanese local developer, to build, own and operate photovoltaic power station with a capacity of 28 megawatts, together with a 13.7 megawatts-hour energy storage system, in Chitose, Hokkaido prefecture in Japan. The parties subsequently signed the joint development agreement and other definitive agreements. The power station, in which we own 80.1% interest, started commercial operation in July 2017. Total project cost is approximately JPY 10.9 billion, of which 20% was financed through 80:20 equity investments by us and EP. The remaining 80% is funded through debt financing.

In August 2016, we entered into a Purchase and Sale Agreement with Cogentrix Solar Holdings to operate a photovoltaic power station in Colorado, United States, with a capacity of 30 megawatts for 25 years. Total project cost is approximately US$85 million, of which 50.1% was financed through 50.1:49.9 equity investments by us and a private equity fund formed by us and National Pension Service. It was our first foray into the North American power market.

In June 2017, we won a project to build, own and operate a photovoltaic power station in Guam, United States, with a capacity of 60 megawatts and a 32 megawatts-hour energy storage system for 25 years. The total project cost is approximately US$186 million, and we will be financing 22% of the cost through equity investment and hold 100% of the equity interests. The remaining 78% will be funded through debt and tax equity financing. We have entered into a Power Purchase Agreement with Guam Power Authority in August 2018. The construction started in May 2020, and it is expected to be completed in December 2021. The entire volume of electricity generated from the power station will be purchased by Guam Power Authority for 25 years.

In September 2017, we entered into an agreement with Recurrent Energy to operate 3 solar photovoltaic project in southern California, United States, with a capacity of 235MW for 34 years. KEPCO partnered with the Corporate Partnership Fund, a Korean private equity fund. We invested USD 38 million in the project, and the transaction marks our largest investment in the U.S. solar market.

 

82


Table of Contents

In October 2018, we entered into a Share Purchase Agreement and Share Subscription Agreement to operate a photovoltaic power station with a capacity of 50 megawatts in Calatagan in the Philippines. The parties, KEPCO and Solar Philippines Power Project Holdings, Inc., subsequently signed the Shareholders’ Agreement in December 2018, in which KEPCO owns 38% interest. We financed PHP 2.25 billion (approximately USD 42.8 million) for the Calatagan Project, of which 80% was financed through equity investments and the remaining 20% was funded through debt financing.

In October 2019, KEPCO and Sprott Korea as a consortium entered into a Share Purchase Agreement and Shareholders Agreement with Canadian Solar INC to develop and operate a photovoltaic power station with a capacity of 294 megawatts in Mexico, including the State of Sonora, for 35 years. We invested USD 41 million in the project, and the transaction marks KEPCO’s first investment in the solar market in Mexico. The financing for the photovoltaic power stations in Horus, Mexico and Tastiota, Mexico was secured in March 2020 and September 2020, respectively. The construction of the photovoltaic power station in Horus, Mexico was completed in November 2020.

In July 2020, KEPCO agreed to enter into a Termination Agreement to the Power Purchase Agreement with the Public Service Company of Colorado. In September 2020, the Public Service Company of Colorado applied for an approval of the Termination Agreement by the Colorado Public Utilities Commission. The Colorado Public Utilities Commission will make its decision in 2021 and such approval is a condition precedent to the Termination Agreement.

Although renewable energy projects are currently insignificant as a proportion of our total overseas activities and our generation activities, we expect the portion of renewable energy projects to increase in the future as we seek to penetrate the overseas renewable energy market, diversify our businesses and actively address climate change. We expect to further diversify our business in the renewable energy sector to also include smart transmission and distribution facilities, smart grids and utilization of new energy related technologies.

North Korea

Kaesong Industrial Complex

Since 2005, we have provided 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 Industrial 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. In March 2005, we built a 22.9 kilovolt distribution line from Munsan substation in Paju, Gyeonggi Province to the Kaesong Industrial 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 Industrial Complex as well as Pyunghwa substation in the complex and began operations in May 2007.

At the end of 2015, we supplied electricity to 254 units, including administrative agencies, support facilities and resident corporations, using a tariff structure identical to that of South Korea. However, we suspended power transmission to the Kaesong Industrial Complex since February 11, 2016 following the Government’s decision to halt operations of the industrial complex to impede North Korea’s utilization of funds from the industrial complex to finance its nuclear and missile programs. On August 14, 2018, we resumed power transmission to the facilities that are part of the Joint Liaison Office between South and North Korea but we suspended it again on June 16, 2020 in compliance with the request by the Ministry of Unification of the Korean Government. It has been reported in the media that the parties have now temporarily closed the Joint Liaison Office in accordance with the request by North Korea to stop the spread of COVID-19 and all KEPCO personnel have withdrawn from the facilities without resuming power transmission since June 16, 2020.

 

83


Table of Contents

As of December 31, 2020, the book value of our facility located at the Kaesong Industrial Complex was Won 15.5 billion. For the year ended December 31, 2020, the amount of trade receivables from the companies residing in Kaesong Industrial Complex was Won 2.9 billion. It is currently uncertain if we can exercise the property rights for our facility in the Kaesong Industrial Complex. No assurance can be given that we will not experience any material losses as a result of the suspension of this project or failure of the project as a result of a breakdown or escalation of hostilities in the relationship between the Republic and North Korea. See Item 3.D. “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.”

Insurance

We and our generation subsidiaries carry insurance covering against certain risks, including fire, in respect of key assets, including buildings, equipment, machinery, construction-in-progress and procurement in transit, as well as, in the case of us, directors’ and officers’ liability insurance. We and our generation subsidiaries maintain casualty and liability insurance against risks related to our business to the extent we consider appropriate. Other than KHNP, neither we nor our generation subsidiaries separately insure against terrorist attacks. These insurance and indemnity policies, however, cover only a portion of the assets that we 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 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. 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-insures 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. KHNP carries property damage insurance covering up to US$1 billion per accident for all properties within its plant complexes, which includes property insurance coverage for acts of terrorism up to US$300 million and for breakdown of machinery up to US$300 million. In addition to the insurance on operating nuclear power generation units, KHNP has construction insurance for Shin-Kori #5 and #6 and Shin-Hanul #1 and #2. KHNP maintains nuclear liability insurance for personal injury and third-party property damage for coverage of up to 300 million Special Drawing Rights, or SDRs, which amounts to approximately US$432.1 million, at the rate of 1 SDR = US$1.44027 as posted on the Internet homepage of the International Monetary Fund on December 23, 2020 per plant complex, for a total coverage of 1.5 billion SDRs. KHNP is also the beneficiary of a Government indemnity with respect to such risks for damage claims of up to Won 300 million SDRs per nuclear plant complex, for a total coverage of 1.5 billion SDRs. Under the Nuclear Damage Compensation Act of 1969, as amended, KHNP is liable only up to 300 million SDRs, per single accident per plant complex; provided that such limitation will not apply where KHNP intentionally causes harm or knowingly fails 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 300 million SDRs 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. KHNP carries insurance for its generation units and nuclear fuel transportation, and we believe that the level of insurance is generally adequate and is in compliance with relevant laws and regulations. In addition, KHNP is the beneficiary of Government indemnity which covers a portion of liability in excess of the insurance. However, 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 or a natural disaster to the extent it is neither insured nor covered by the government indemnity. See Item 3.D. “Risk Factors—Risks Relating to KEPCO—The amount and scope of coverage of our insurance are limited.”

Competition

As of December 31, 2020, we and our generation subsidiaries owned approximately 64.9% of the total electricity generation capacity in Korea (excluding plants generating electricity for private or emergency use).

 

84


Table of Contents

New entrants to the electricity business will erode our market share and create significant competition, which could have a material adverse impact on our financial condition and results of operations.

In particular, we compete with independent power producers with respect to electricity generation. The independent power producers accounted for 28.6% of total power generation in 2020 and 35.1% of total generation capacity as of December 31, 2020. As of December 31, 2020, there were 20 independent power producers in Korea, excluding renewable energy producers. Private enterprises became permitted to own and operate coal-fired power plants in Korea only after the Ministry of Trade, Industry and Energy approved plans for independent power producers to construct coal-fired power plants under the Sixth Basic Plan announced in February 2013. Under the Ninth Basic Plan announced in December 2020, six coal-fired power plants are planned to be constructed by independent power producers by 2024. While it remains to be seen whether construction of these generation units will be completed as scheduled, if these units were to be completed as scheduled and/or independent power producers are permitted to build additional generation capacity (whether coal-fired or not), our market share in Korea may decrease.

An amendment to the Electric Utility Act is underway that will enable us to directly participate in the development of renewable power generation. Under the current Electric Utility Act, a single business entity cannot participate in two or more types of electric businesses. The proposed amendment allows a market-type public institution like us to participate in renewable power generation business to a limited degree. The amendment bill was proposed in July 2020 and is now pending deliberation by the Korean national assembly. When the bill passes, we intend to pursue renewable power generation projects such as large-scale offshore wind power.

In addition, under the Community Energy System adopted by the Government in 2004, a minimal amount of electricity is supplied directly to consumers on a localized basis by independent power producers outside the cost-based pool system. Such system is used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. The purpose of this system is to geographically decentralize electricity supply and thereby reduce transmission losses 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 March 31, 2021, the aggregate generation capacity of suppliers participating in the Community Energy System amounted to less than 1% of that of our generation subsidiaries in the aggregate. We currently do not expect the Community Energy System to be widely adopted, especially in light of the significant level of capital expenditure required for such direct supply. However, if the Community Energy System is widely adopted, it may erode our currently dominant market position in the generation and distribution of electricity in Korea and may have a material adverse effect on our business, results of operations and financial condition.

Our market dominance in the electricity distribution in Korea also may face potential erosion in light of the recent Proposal for Adjustment of Functions of Public Institutions (Energy Sector) announced by the Government in June 2016. This proposal contemplates a gradual opening of the electricity trading market to the private sector although no detailed roadmap has been provided for such opening. It is currently premature to predict to what extent, or in what direction, the liberalization of the electricity trading market will happen. Nonetheless, any significant liberalization of the electricity trading market may result in substantial reduction of our market share in electricity distribution in Korea, which would have a material adverse effect on our business, results of operation and cash flows.

The electric power 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. See Item 4.B. “Business Overview—Restructuring of the Electric Power Industry in Korea.”

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 other household appliances, which is available on commercially affordable terms.

 

85


Table of Contents

In the commercial sector, electricity is the dominant energy source for lighting, office equipment and air conditioning. For 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, electricity is the dominant energy source for a number of industrial applications, including lighting and power for many types of industrial machinery and processes that are available on commercially affordable terms. For other uses, such as 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 a stable supply of electric power and further contributing toward the sound development of the national economy through facilitating development of electric power resources and carrying out proper and effective operation of the electricity business. The KEPCO Act (including the amendment thereto) prescribes that we engage in the following activities:

 

  1.

development of electric power resources;

 

  2.

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

 

  3.

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

 

  4.

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

 

  5.

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

 

  6.

businesses incidental to items 1 through 5;

 

  7.

Development and operation of certain real estate held by us to the extent that:

 

  a.

it is necessary to develop certain real estate held by us due to external factors, such as relocation, consolidation, conversion to indoor or underground facilities or deterioration of our substation or office; or

 

  b.

it is necessary to develop certain real estate held by us to accommodate development of relevant real estate due to such real estate being incorporated into or being adjacent to an area under planned urban development; and

 

  8.

other activities 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 20.0% or more of profits as a legal reserve until the accumulated reserve reaches one-half of our capital;

 

   

third, to pay dividends to shareholders;

 

   

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.

As of December 31, 2020, the legal reserve was Won 1,605 billion and the voluntary reserve was Won 32,179 billion, which consisted of reserve for business expansion of Won 26,362 billion, reserve for investment in social overhead capital of Won 5,277 billion, reserve for research and human development of Won 330 billion and reserve for equalizing dividends of Won 210 billion.

 

86


Table of Contents

We are under the supervision of the Ministry of Trade, Industry and Energy, which has principal supervisory responsibility (in consultation with other Government agencies, such as the Ministry of Economy and Finance, as applicable) over us with respect to the appointments of our directors and our other senior management as well as approval of electricity tariff rate adjustments, among others.

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

The Electric Utility Act requires that licenses be obtained in relation to generation, transmission, distribution and sales of electricity, with limited exceptions. We hold the license to transmit, distribute and sell electricity. Each of our six generation subsidiaries holds an electricity generation license. The Electric Utility Act governs the formulation and approval of electricity rates in Korea. See “—Sales and Customers—Electricity Rates” above. An amendment to the Electric Utility Act is underway that will enable us to directly participate in the development of renewable power generation. Under the current Electric Utility Act, a single business entity cannot participate in two or more types of electric businesses. The proposed amendment allows a market-type public institution like ourselves to participate in renewable power generation business to a limited degree. The amendment bill was proposed in July 2020 and is now pending deliberation by the Korean national assembly. When the bill passes, we intend to pursue renewable power generation projects such as large-scale offshore wind power.

Our operations are subject to various laws and regulations relating to environmental protection and safety.

Debt Reduction Program and Related Activities

In light of the general policy guideline of the Government for public institutions (including us and our generation subsidiaries) to reduce their respective overall debt levels, we and our generation subsidiaries have, in consultation with the Ministry of Trade, Industry and Energy and as approved by the Committee for Management of Public Institutions, previously set target debt-to-equity levels every year from 2014 to 2017 and undertook various programs to reduce debt and improve the overall financial health, including through rationalizing and applying stricter review to (from a profitability and efficiency perspective) various aspects of our operations (both domestic and overseas), inviting private sector investments, disposing of non-core assets (such as non-core or loss-generating overseas operations and real property unrelated to operations), reducing costs, exploring alternative ways to generate additional revenue and developing contingency plans for further cost savings. Such debt-reduction initiatives ended at the end of 2017 as initially planned. However, we have carried out similar initiatives to manage our level of debt. In 2021, we adopted a new tariff system more aligned to our costs (including fuel cost pass-through adjustment) to lay the foundation for mid and long-term financial stability. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.” In addition, we are pursuing systematic cost management efforts by dividing the areas of cost in detail and reinforcing the concept of cost per unit.

Despite our best efforts, however, for reasons beyond our control, including macroeconomic environments, government regulations and market forces (such as international market prices for our fuels), we cannot assure whether we or our generation subsidiaries will be able to successfully reduce debt burdens or otherwise improve our financial health or to a level that would be optimal for our capital structure. If we or our generation subsidiaries fail to do so or the measures taken by us or our generation subsidiaries to reduce debt levels or improve financial health have unintended adverse consequences, such developments may have an adverse effect on our business, results of operations and financial condition.

Establishment of a University

In order to enhance the competitiveness of the national energy industry, cultivate high-quality talents to revitalize the Gwangju-Jeonnam energy valley, and secure a differentiated research platform to create a new

 

87


Table of Contents

energy market, we are in the process of establishing a university in Jeollanam-do Province in the southwestern region of Korea in accordance with the Government’s five-year state management plan.

The university is a research and entrepreneurship-oriented university specializing in the energy field and aims to be a small yet robust university with 100 faculty members and 1,000 students. On April 17, 2020, the Ministry of Education gave us the permission to form a legal entity for the university. The opening date is tentatively scheduled in 2022. The total funding expected until 2025 when the university’s organization will be complete is Won 828.9 billion, excluding the land that was freely endowed to us.

The funding for establishing the university will be jointly borne by us and the central and municipal governments. We plan to cooperate with one another through an intra-governmental university establishment and support committee.

For ten years after the commencement of the university, we expect to receive funding (to be used as expenses for operating the university) from the municipal government in the amount of Won 200 billion. In addition, we expect to receive funding from the central government that is at least in the same amount as we expect to receive from the municipal government. After taking into account the funding from the governments, we anticipate our contribution to the university until 2025 to be approximately Won 500 billion depending on the amount of contribution from the central government.

On August 8,