Edgar Filing: KOREA ELECTRIC POWER CORP

Form 20-F

As filed with the Securities and Exchange Commission on April 30, 2013

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 F

Form 20-F

(Mark One)

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

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

For the fiscal year ended December 31, 2012

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

For the transition period from to

¨	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)*

167 SAMSEONG-DONG, GANGNAM-GU, SEOUL 135-791, KOREA

(Address of principal executive offices)

Jungin Yoon, +822 3456 4216, junginyoon@kepco.co.kr, +822 3456 4299

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

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


Title of each class:		Name of each exchange on which registered:
Common stock, par value Won 5,000 per share		New York Stock Exchange*
American depositary shares, each representing one-half of share of common stock		New York Stock Exchange

*	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:

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

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

6% Debentures due December 1, 2026

7% Debentures due February 1, 2027

6³/₄% Debentures due August 1, 2027

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

covered by the annual report:

641,964,077 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 þ No ¨

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

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

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

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

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

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

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

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

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

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

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 3A.	Selected Financial Data		2
	Item 3B.	Capitalization and Indebtedness		4
	Item 3C.	Reasons for the Offer and Use of Proceeds		4
	Item 3D.	Risk Factors		4
ITEM 4.	INFORMATION ON THE COMPANY			20
	Item 4A.	History and Development of the Company		20
	Item 4B.	Business Overview		20
	Item 4C.	Organizational Structure		73
	Item 4D.	Property, Plant and Equipment		76
ITEM 4A.	UNRESOLVED STAFF COMMENTS			76
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS			76
	Item 5A.	Operating Results		76
	Item 5B.	Liquidity and Capital Resources		95
	Item 5C.	Research and Development, Patents and Licenses, etc.		99
	Item 5D.	Trend Information		100
	Item 5E.	Off-Balance Sheet Arrangements		100
	Item 5F.	Tabular Disclosure of Contractual Obligations		100
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES			104
	Item 6A.	Directors and Senior Management		104
	Item 6B.	Compensation		107
	Item 6C.	Board Practices		107
	Item 6D.	Employees		108
	Item 6E.	Share Ownership		109
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS			109
	Item 7A.	Major Shareholders		109
	Item 7B.	Related Party Transactions		109
	Item 7C.	Interests of Experts and Counsel		110
ITEM 8.	FINANCIAL INFORMATION			110
	Item 8A.	Consolidated Statements and Other Financial Information		110
	Item 8B.	Significant Changes		110
ITEM 9.	THE OFFER AND LISTING			111
	Item 9A.	Offer and Listing Details		111
	Item 9B.	Plan of Distribution		113
	Item 9C.	Markets		113
	Item 9D.	Selling Shareholders		116
	Item 9E.	Dilution		116
	Item 9F.	Expenses of the Issue		116
ITEM 10.	ADDITIONAL INFORMATION			116
	Item 10A.	Share Capital		116
	Item 10B.	Memorandum and Articles of Incorporation		116
	Item 10C.	Material Contracts		123
	Item 10D.	Exchange Controls		123
	Item 10E.	Taxation		128
	Item 10F.	Dividends and Paying Agents		139
	Item 10G.	Statements by Experts		139
	Item 10H.	Documents on Display		139
	Item 10I.	Subsidiary Information		139


			Page
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			140
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES			145
	Item 12A.	Debt Securities		145
	Item 12B.	Warrants and Rights		145
	Item 12C.	Other Securities		145
	Item 12D.	American Depositary Shares		145
PART II				148
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES			148
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS			148
ITEM 15.	CONTROLS AND PROCEDURES			148
ITEM 16.	[RESERVED]			149
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT			149
ITEM 16B.	CODE OF ETHICS			149
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES			150
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE			150
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS			150
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANTS			150
ITEM 16G.	CORPORATE GOVERNANCE			150
ITEM 16H.	MINE SAFETY DISCLOSURE			155
PART III				156
ITEM 17.	FINANCIAL STATEMENTS			156
ITEM 18.	FINANCIAL STATEMENTS			156
ITEM 19.	EXHIBITS			156

CERTAIN DEFINED TERMS AND CONVENTIONS

All references to “Korea” or the “Republic” in this annual report on Form 20-F, or this report, are references to The Republic of Korea. All references to the “Government” in this report are references to the government of the Republic. All references to “we,” “us,” “our,” “ours,” the “Company” or “KEPCO” in this 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 Strategy and Finance” include the respective predecessors thereof (and, for the avoidance of doubt, in the case of the Ministry of Trade, Industry and Energy, including the Ministry of Knowledge Economy). 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 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 report has been prepared on a consolidated basis and in accordance with IFRS.

In addition, in this report, all references to:

•

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

•

“EWP” are to Korea East-West 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 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 operating or financial performance identify forward-looking statements. In addition, all statements other than statements of historical facts included in this report are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report.

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

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 3A. Selected Financial Data

The selected consolidated financial data set forth below as of and for the years ended December 31, 2010, 2011 and 2012 have been derived from our audited consolidated financial statements which have been prepared in accordance with IFRS.

Our consolidated financial statements as of and for the years ended December 31, 2010, 2011 and 2012 included in this report have been audited by Deloitte Anjin LLC, a member firm of Deloitte Touche Tohmatsu Limited, a UK private company limited by guarantee. Deloitte Anjin LLC is a Korean independent registered public accounting firm and is our current independent registered public accounting firm.

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 Earnings Data


	2010			2011			2012
	(in billions of Won and millions of US$, except per share data)
Sales	￦	39,507		￦	43,175		￦	49,121		$	46,199
Cost of sales		36,188			42,725			48,459			45,577
Gross Profit		3,319			450			662			622
Other operating income (expense), net		467			451			600			564
Selling and administrative expenses		1,645			1,752			1,780			1,674
Other income (loss)		119			166			(1,782	)		(1,676	)
Operating income (loss)		2,260			(685	)		(2,300	)		(2,164	)
Finance income (expense), net		(1,967	)		(1,911	)		(1,940	)		(1,824	)
Profits of affiliates and joint ventures using equity method		77			123			177			166
Income (loss) before income taxes		370			(2,473	)		(4,063	)		(3,822	)
Income tax expenses		439			820			(985	)		(926	)
Net loss for the year		(69	)		(3,293	)		(3,078	)		(2,896	)
Other comprehensive loss		(43	)		(262	)		(322	)		(303	)
Total comprehensive loss		(112	)		(3,555	)		(3,400	)		(3,199	)
Net income (loss) attributable to:
Owners of the Company		(120	)		(3,370	)		(3,167	)		(2,980	)
Non-controlling interests		51			77			89			84
Total comprehensive income attributable to:
Owners of the Company		(152	)		(3,628	)		(3,448	)		(3,244	)
Non-controlling interests		40			73			48			45
Earnings (loss) per share
Basic⁽¹⁾		(193	)		(5,411	)		(5,083	)		(4,781	)
Diluted⁽²⁾		(193	)		(5,411	)		(5,083	)		(4,781	)
Earnings (loss) per ADS
Basic⁽¹⁾		(97	)		(2,706	)		(2,542	)		(2,391	)
Diluted⁽²⁾		(97	)		(2,706	)		(2,542	)		(2,391	)
Dividends per share		—			—			—			—

Consolidated Statements of Financial Position Data


	As of December 31,
	2010			2011			2012
	(in billions of Won and millions of US$, except share and per share data)
Net working capital surplus (deficit)⁽³⁾	￦	(916	)	￦	(3,973	)	￦	(4,884	)	$	(4,594	)
Property, plant and equipment, net		107,406			112,385			122,376			115,097
Total assets		129,518			136,468			146,153			137,460
Total shareholders’ equity		57,277			53,804			51,064			48,027
Controlling interest		56,818			53,270			49,889			46,922
Non-controlling interest		459			534			1,175			1,105
Common stock		3,208			3,210			3,210			3,019
Number of common shares as adjusted to reflect any changes in capital stock		641,567,712			641,964,077			641,964,077			641,964,077
Long-term debt (excluding current portion)		32,848			39,198			45,525			42,817
Other long term liabilities		25,321			25,725			30,747			28,918

Notes:

(1)	Basic earnings 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.

(2)	Diluted earnings per share are calculated in a manner consistent with basic earnings per share, while giving effect to the potential dilution that could occur if convertible securities, options or other contracts to issue common shares were converted into or exercised for common shares.

(3)	Net working capital means current assets minus current liabilities.

Currency Translations and Exchange Rates

In this report, unless otherwise indicated, all references to “Won” or “￦” are to the currency of Korea, and all references to “U.S. dollars,” “Dollars,” “$” or “US$” are to the currency of the United States of America, all references to “Euro” or “€” are references to the currency of the European Union, and all references to “Yen” or “¥” are references to the currency of Japan. Unless otherwise indicated, all translations from Won to U.S. dollars were made at Won 1,063.2 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, 2012. The source of these rates is the Federal Reserve Bank of New York until December 31, 2008. Since January 1, 2009, the Federal Reserve Bank of New York discontinued publication of foreign exchange rates. The source of the rates since January 1, 2009 is the H.10 statistical release of the Federal Reserve Board. On April 5, 2013, the Noon Buying Rate was Won 1,136.8 to US$1.00. The exchange rate between the U.S. dollar and Korean Won may be highly volatile from time to time and the U.S. dollar amounts referred to in this report should not be relied upon as an accurate reflection of our results of operations. No representation is made that the Won or U.S. dollar amounts referred to in this report could have been or could be converted into U.S. dollars or Won, as the case may be, at any particular rate or at all.

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


Year Ended December 31,	At End of Period		Average⁽¹⁾		High		Low
	(Won per US$1.00)
2008		1,262.0		1,098.7		1,507.9		935.2
2009		1,163.7		1,274.6		1,570.1		1,149.0
2010		1,130.6		1,155.7		1,253.2		1,104.0
2011		1,158.5		1,106.9		1,197.5		1,049.2
2012		1,063.2		1,126.2		1,185.0		1,063.2
October		1,090.2		1,105.4		1,114.6		1,090.2
November		1,081.8		1,087.0		1,091.8		1,081.8
December		1,063.2		1,075.2		1,083.7		1,063.2
2013 (through April 5)		1,136.8		1,088.3		1,136.8		1,056.0
January		1,087.5		1,066.5		1,091.2		1,056.0
February		1,083.9		1,087.3		1,095.7		1,078.2
March		1,112.5		1,102.9		1,119.2		1,083.9
April (through April 5)		1,136.8		1,121.9		1,136.8		1,114.4

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

Note:

(1)	Represents the daily average of the Noon Buying Rates during the relevant period.

Item 3B.

Capitalization and Indebtedness

Not Applicable

Item 3C.

Reasons for the Offer and Use of Proceeds

Not Applicable

Item 3D.

Risk Factors

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

Risks Relating to KEPCO

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

Fuel costs constituted 48.5% and 49.2% of our sales and cost of sales, respectively, in 2012. Our generation subsidiaries purchase substantially all of the fuel that they use (except for anthracite coal) from a limited number of suppliers outside Korea at prices determined in part by prevailing market prices in currencies other than Won. For example, most of the bituminous coal requirements (which accounted for approximately 42.2% of our entire fuel requirements in 2012 in terms of electricity output) are imported from a limited number of countries principally consisting of Indonesia and Australia and, to a lesser extent, the United States and Russia, which accounted for approximately 43.6%, 33.4%, 5.7% and 5.2%, respectively, of the annual bituminous coal requirements of our generation subsidiaries in 2012. Approximately 80.3% of the bituminous coal requirements of our generation subsidiaries in 2012 were purchased under long-term contracts and the remaining 19.7% from

the spot market. Pursuant to the terms of our long-term supply contracts, prices are adjusted annually 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 4B. “Business Overview—Fuel.”

In recent years, the prices of bituminous coal, oil and liquefied natural gas, or LNG, have fluctuated significantly, creating uncertain outlook for our overall fuel costs. For example, the average “free on board” Newcastle coal 6300 GAR spot price index published by Platts was US$99.2 per ton in 2010, US$121.3 per ton in 2011, US$96.2 per ton in 2012 and US$92.3 per ton as of April 9, 2013. 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 varied from US$106.2 per barrel in 2011 to US$108.9 per barrel in 2012 and to US$103.9 per barrel as of April 5, 2013. If fuel prices increase sharply within a short span of time, our generation subsidiaries may be unable to secure requisite 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 cost. We cannot assure you that the fuel prices will not significantly increase in the remainder of 2013 or thereafter.

Because the Government regulates the rates we charge for the electricity we sell to our customers (see Item 4B. “Business Overview—Sales and Customers—Electricity Rates”), our ability to pass on fuel and other cost increases to our customers is limited. The increase in fuel prices led to our recording of an operating loss in 2011 and 2012 and a net loss from 2008 to 2012. We expect that a sudden and substantial rise in the level of fuel prices will have a material adverse effect on our results of operation in 2013 and beyond. If fuel prices remain at the current level or continue to increase and the Government, out of concern for inflation or for other reasons, maintains the current level of electricity tariff or does not increase it to a level to sufficiently offset the impact of high fuel prices, the fuel price increases will negatively affect our profit margins or even cause us to suffer operating and/or net losses and our business, financial condition, results of operations and cash flows would suffer. In addition, partly because the Government may have to undergo a lengthy deliberative process to approve an increase in electricity tariff, which represents a key component of the consumer price index, the electricity tariff may not be adjusted to a level sufficient to ensure a fair rate of return to us in a timely manner or at all. For example, in August 2010, August 2011, December 2011, August 6, 2012 and January 14, 2013, the Government increased the electricity tariff by an average of 3.5%, 4.9%, 4.5%, 4.9% and 4.0%, respectively. However, such increases were insufficient to fully offset the adverse impact from the rise in fuel costs. Similarly, we cannot assure that any future tariff increase by the Government will be sufficient to fully offset the adverse impact on our results of operations from the current or potential rises in fuel costs.

Further to the announcement by the Ministry of Trade, Industry and Energy in February 2010, a new electricity tariff system went into effect on July 1, 2011. This system is designed to overhaul the prior system for determining electricity tariff chargeable to customers by more closely aligning the tariff levels to the movements in fuel prices, with the aim of providing more timely pricing signals to the market regarding the expected changes in electricity tariff levels and encouraging more efficient use of electricity by customers. Previously, the electricity tariff consisted of two components: (i) base rate and (ii) usage rate based on the cost of electricity and the amount of electricity consumed by the end-users. Under the new tariff system, the electricity tariff is also to have a third component of fuel cost pass-through adjustment (“FCPTA”) rate, which is to be added to or subtracted from the sum of the base rate and the usage rate on a monthly basis based on the three-month average movements of coal, LNG and oil prices, which is reflected as FCPTA two months later. The new tariff system is intended to provide greater financial stability and ensure a minimum return on investment to electricity suppliers, such as us. However, due to inflationary and other policy considerations relating to protecting the consumers from sudden and substantial rises in electricity tariff, the Ministry of Trade, Industry and Energy issued a hold order on July 29, 2011 suspending our billing and collecting of the FCPTA amount. The hold order remains in effect to-date. Furthermore, on January 11, 2013, the Ministry of Trade, Industry and Energy informed us that the FCPTA system needed to be reassessed in light of the current circumstances such as the prolonged unbilled

period since the announcement of the FCPTA system. There is no assurance as to when the Government will lift the hold order and allow us to bill and collect the accumulated FCPTA amount or whether the new tariff system will undergo other amendments to the effect that it will not fully cover our fuel and other costs on a timely basis or at all, or will not have unintended consequences that we are not presently aware of. Any such development may have a material adverse effect on our business, financial condition, results of operations and cash flows. For further discussion, including in relation to accounting, see Item 4B. “Business Overview—Recent Developments—Correction of Accounting for Fuel Cost Pass-through Adjustment”, Item 4B. “Business Overview—Sales and Customers—Electricity Rates”, Item 4B. “—Recent Developments— Correction of Accounting for Fuel Cost Pass-through Adjustment,” Item 5B. “Operating and Financial Review and Prospects—Overview,” Item 5B. “Operating and Financial Review and Prospects—Critical Accounting Policy—Correction of Accounting for Fuel Cost Pass-through Adjustment” and Notes 2, 15 and 36 to the notes to our consolidated annual financial statements.

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 altered 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 4B. “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 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 2003 due to prevailing market conditions and other policy considerations.

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 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 came to have separate management structures (although with limits on its autonomy), financial accounting systems and performance evaluation systems, but with a common focus on maximizing profitability.

On August 25, 2010, the Ministry of Trade, Industry and Energy announced the Proposal for the Improvement in the Structure of the Electric Power Industry, whose key initiatives included the following: (i) maintain the current structure of having six generation subsidiaries, (ii) designate the six generation subsidiaries as “market-oriented public enterprises” under the Public Agency Management Act in order to foster competition among them and autonomous and responsible management by them, (iii) create a supervisory unit to act as a “control tower” in reducing inefficiencies created by arbitrary division of labor among the six generation subsidiaries and fostering economies of scale among them and require the presidents of the generation subsidiaries to hold regular meetings, (iv) 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, (v) 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 (vi) create separate accounting systems for electricity generation,

transmission, distribution and sales with the aim of introducing competition in electricity sales in the intermediate future. Pursuant to this Proposal, in December 2010 the Ministry of Trade, Industry and Energy announced guidelines for a cooperative framework between us and our generation subsidiaries, and in January 2011 the five non-nuclear generation subsidiaries formed a “joint cooperation unit” and transferred their pumped-storage hydroelectric business units to KHNP. 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 outside directors of each such subsidiary is subject to approval by the minister of the Ministry of Strategy 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 Commission conducts performance evaluation of such subsidiaries. Previously, our president appointed the president and the statutory auditor of each such subsidiary; the selection of outside 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.

In addition, in order to deal with the shortage of fuel and other resources and also to comply with various environmental standards, the Government has adopted the Renewable Portfolio Standard (“RPS”), under which each generation subsidiary was required to supply 2.0% of the total energy generated from such subsidiary in the form of renewable energy in 2012 and will be required to supply 10.0% by 2022. The current budgeted amount of capital expenditure for implementation of the RPS as currently planned for the period from 2012 to 2022 is approximately Won 45 trillion. We expect that such additional capital expenditure will be covered by a corresponding increase in electricity tariff. However, there is no assurance that the Government will in fact raise the electricity tariff to a level sufficient to fully cover such additional capital expenditures or at all. For further details, see Item 4B. “Business Overview—Renewable Energy.”

Other than as set forth above, we are not aware of any specific plan by the Government to resume the implementation of the Restructuring Plan or otherwise change the current structure of the electric power industry or the operations of us or our generation subsidiaries 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. Any such measures may have a negative effect on our business, results of operation 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 with respect to our business and operations, and such initiatives may vary from the interest and objectives of our other shareholders.

Our capacity expansion plans, which are 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 based on the Basic Plan Relating to the Long-Term Supply and Demand of Electricity, or the Basic Plan, which is generally announced and revised every two years by the Government. In February 2013, the Government announced the sixth Basic Plan relating to the future supply and demand of electricity. The sixth Basic Plan, which is effective for the period from 2013 to 2027, focuses on, among other things, (i) minimizing the need to construct new generation facilities through active consumer demand management, (ii) ensuring that we maintain adequate electricity reserve appropriate to the size of the national economy, and (iii) expanding our generation capacity to promote efficient supply of electricity in consideration of the stability of the national electricity grid network and the specific needs of localities. The Government may announce a supplemental plan for the construction of additional nuclear plants, which was not included in the sixth Basic Plan; such plan may increase the amount of our required capital expenditure. We cannot assure that the sixth Basic Plan, or the plans to be subsequently adopted, will successfully achieve their intended goals, the foremost of which is to formulate a capacity expansion plan that will result in balanced overall electricity supply and demand in Korea at an affordable cost to the end users. If there is a significant variance between the projected electricity supply and

demand considered in planning our capacity expansions and the actual electricity supply and demand, this may result in inefficient use of our capital, mispricing of electricity and undue financing costs on the part of us and our generation subsidiaries, 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. For example, due to extremely cold weather during winters of recent years, our electricity reserve level fell from time to time to a level lower than the normal level despite emergency measures mandated by the Government, such as reduced daytime railway services and reduced daytime industrial use of electricity during peak hours. In addition, due to the unanticipated late heat wave in mid-September 2011 and the resulting spike in the use of air conditioning, our reserve level fell to a level that resulted in temporary suspensions of electricity supply across several regions of Korea on that day despite emergency measures by the Government, such as direct load control and voluntary conservation, which prevented a full-scale blackout. Circumstances such as these may lead to increased end-user complaints and greater public scrutiny, which may in turn result in our need to modify our capacity expansion plans, and if we were to substantially modify our capacity plans, this may result in additional capital expenditures, which may have a material adverse effect on our results of operations, financial condition and cash flows.

In light of these temporary power shortages, the Government has increasingly expanded its efforts to encourage conservation of electricity, including through a public relations campaign, but there is no assurance such efforts will have the desired effect of substantially reducing the demand for electricity or improving efficient use thereof.

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 make acquisitions and investments related to overseas natural resources. In 2010, 2011 and 2012, our capital expenditures (including capitalized interest) for the construction of generation, transmission and distribution facilities amounted to ￦11,414 billion, ￦11,984 billion and ￦13,215 billion, respectively, and our budgeted capital expenditures for 2013, 2014 and 2015 amount to ￦19,714 billion, ￦20,376 billion and ￦18,651 billion, respectively. While we currently do not expect to face any material difficulties in procuring short-term borrowing 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 or debt repayment obligations, which could have a material adverse impact 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 in recent years, especially as a result of the ongoing global financial instability, especially in Europe. See Item 3A. “Selected Financial Data—Currency Translations and Exchange Rates.” Depreciation of Won against U.S. dollar and other foreign currencies typically results 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. dollars. Changes in foreign exchange rates may also impact the cost of servicing our foreign currency-denominated debt. As of December 31, 2012, approximately

21.4% of our long-term debt (including the current portion but excluding issue discounts and premium) before accounting for swap transactions was denominated in foreign currencies, principally in U.S. dollars. In addition, even if we make payments in Won for certain fuel materials and equipment, some of these fuel materials (for example, all of our requirements for LNG are purchased from Korea Gas Corporation) 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 substantially all of our revenues are denominated in Won, we must generally obtain foreign currencies through foreign-currency denominated financings or from foreign currency exchange markets to make such purchases or service such debt. As a result, any significant depreciation of Won against 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 undertake new, or expand existing, projects such as strengthening of our renewable energy generation capabilities under the Renewable Portfolio Standards initiative, adoption of the “smart grid” projects to improve the operational efficiency of our electricity transmission and distribution network, and expansion in overseas markets, particularly in the construction and operation of nuclear generation units and the exploration and production of natural resources.

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

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

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

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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;

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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

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

As part of our business strategy, we may also seek, evaluate or engage in potential acquisitions, mergers, joint ventures, strategic alliances, restructurings, combinations, rationalizations, divestments or other similar 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 business. As a result of such review, we may decide to exit from or to reduce the resources that we allocate to new 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 international 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 plan to expand, on a selective basis, our overseas operations in the future. In particular, we plan to further diversify the geographic focus of our operations from Asia to the rest of the world, including the resource-rich Middle East, Australia and Africa as well as expand

our project portfolio, which has to-date involved primarily the construction and operation of conventional thermal generation units, to include the construction and operation of nuclear power plants as well as mining and development of fuel sources in order to increase the level of self-sufficiency in the procurement of fuels.

Overseas operations generally carry risks that are different from those we face in our domestic operations. These risks include:

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

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

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difficulties in enforcing creditors’ rights in foreign jurisdictions;

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

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difficulties in establishing, staffing and managing foreign operations;

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differing labor regulations;

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

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lack of familiarity with local markets and competitive conditions;

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

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obstacles to the repatriation of earnings and cash.

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 business opportunities in a prudent and selective manner, some of our new international business ventures, such as mining and resource exploration, carry inherent risks that are different from our traditional business of electricity power generation, transmission and distribution. While these new businesses in the aggregate currently do not comprise a material portion of our overall business, as we are relatively inexperienced in these types of businesses, the actual revenues and profitability from, and investments and expenditures into, these business ventures may be substantially different from what we planned or anticipated and have a material adverse impact on our overall business, results of operations, financial condition and cash flows.

The proliferation of competing systems for independent generation of electricity by and/or sourcing from private power producers would erode our market position and hurt our business, growth prospects, revenues and profitability.

In 2012, we and our generation subsidiaries owned approximately 84.2% of the total electricity generation capacity in Korea (excluding plants generating electricity for private or emergency use). 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 conditions and results of operation.

For example, while preparing for the sixth Basic Plan, which was announced in February 2013, the Ministry of Trade, Industry and Energy accepted applications from private independent power producers, in addition to those from our generation subsidiaries, for construction of additional coal-fired power plants. Previously, private enterprises were not permitted to own and operate coal-fired power plants in Korea. Out of such applications by 15 independent power producers for construction of a total of 40 coal-fired generation units with aggregate generation capacity of 37,100 megawatts, the Government approved applications for the construction of six generation units with aggregate generation capacity of 6,000 megawatts as well as two additional generation

units with aggregate generation capacity of 2,000 megawatts to provide for the contingency of failed or delayed construction of these six generation units. Construction for the six generation units is scheduled to be completed between 2018 and 2021. While it remains to be seen whether construction of these generation units will be completed as scheduled, if it were to be completed as scheduled 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, in July 2004, the Government adopted the Community Energy System to enable regional districts to source electricity from independent power producers to supply electricity without having to undergo the cost-based pool system used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. A supplier of electricity under the Community Energy System must be authorized by the Korea Electricity Commission and be approved by the minister of the Ministry of Trade, Industry and Energy in accordance with the Electricity Business Act. The purpose of this system is to decentralize electricity supply and thereby reduce transmission costs and improve the efficiency of energy use. These entities do not supply electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System. As of March 31, 2013, 14 districts were using this system. The generation capacity installed or under construction of the electricity suppliers in these 14 districts amounted to approximately 1% of the aggregate generation capacity of our generation subsidiaries as of March 31, 2013. Since the introduction of the Community Energy System in 2004, a total of 31 districts have obtained the license to supply electricity through the Community Energy System, but 17 of such districts have reportedly abandoned plans to adopt the Community Energy System, largely due to the relatively high level of capital expenditure required, the rise in fuel costs and the lower-than-expected electricity output per cost. However, if the Community Energy System is widely adopted, it will erode our currently dominant market position in the generation and distribution of electricity in Korea, and may have a material adverse effect on our business, growth, revenues and profitability.

Labor unrest may adversely affect our operations.

We and each of our generation subsidiaries have separate labor unions. As of December 31, 2012, approximately 68.4% of our and our generation subsidiaries’ employees in the aggregate were members of these labor unions. Since the six-week labor strike in 2002 by the union members of our generation subsidiaries in response to the proposed privatization of one of our generation subsidiaries, there has been no material subsequent labor dispute. However, we cannot assure you that there will not be a major labor strike or other disruptions 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.

Planned relocation of the headquarters of us and our generation subsidiaries may reduce our operational efficiency.

In June 2005, as part of an initiative to foster balanced economic growth in the provinces, the Government announced a plan to relocate the headquarters of select government-invested enterprises, including us and our six generation and certain other subsidiaries, from the Seoul metropolitan area to other provinces in Korea. Currently, our headquarters and those of our generation subsidiaries are within close vicinity of each other in the City of Seoul. Pursuant to the Government’s relocation policy, our headquarters are scheduled to be relocated to Naju in Jeolla Province, which is approximately 300 kilometers south of Seoul. Although the relocation was initially scheduled to occur by the end of 2012, due to construction delays, we currently expect that the relocation will occur by the end of 2014. In addition, the headquarters of certain of our subsidiaries are scheduled to be relocated to various other cities in Korea. While we intend to comply with the relocation plan, there can be no assurance that, following such relocation, we will be able to maintain the current level of operational efficiency due to geographic dispersion of our business units.

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 23 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 29.8% of electricity generated in Korea in 2012. Due to significantly lower unit fuel costs compared to those for conventional power plants, our nuclear power plants are generally operated at full capacity with only routine shutdowns for fuel replacement and maintenance, with limited exceptions. The breakdown, failure or suspension of operation of a nuclear unit could result in a material loss of revenues, an increase in fuel costs related to the use of alternative power sources, additional repair and maintenance costs, greater risk of litigation and increased social and political hostility to the use of nuclear power, any of which could have a material adverse impact on our financial conditions and results of operation.

In response to the damage to the nuclear facilities (including nuclear meltdowns) in Japan as a result of the tsunami and earthquake in March 2011, the Government announced plans to further enhance the safety and security of nuclear power facilities, including by establishing the Nuclear Safety Commission in July 2011 for neutral and independent safety appraisals, subjecting nuclear power plants to additional safety inspections by governmental authorities and civic groups and requiring KHNP to prepare a comprehensive safety improvement plan. As a result of the foregoing, as well as a generally higher level of public and regulatory scrutiny of nuclear power following the recent nuclear incident in Japan, KHNP plans to implement a significant number of measures to improve the safety and efficiency of its generation facilities for target completion by 2015. We expect to incur additional compliance costs and capital expenditures in relation to our improvement measures, which could have a material adverse impact on our financial conditions and results of operation.

The construction and operation of nuclear-fuel generation units involve difficulties, such as civic opposition from civic groups, which may have an adverse effect on us.

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

On February 9, 2012, our nuclear generation unit Kori-1 experienced a station blackout for approximately 12 minutes during a scheduled maintenance overhaul which began on February 4, 2012 and was scheduled to be completed on March 4, 2012. This incident was reported to the Nuclear Safety and Security Commission on March 12, 2012, which ordered a temporary shut-down of the Kori-1 on March 13, 2012, pending further safety evaluation. In addition, it was recently discovered that certain machinery parts used in our nuclear-fuel generation units had been supplied using forged quality certification documents, resulting in a temporary shutdown of two nuclear-fuel generation units in Yonggwang from November 2012 to January 2013. The Government has initiated a probe in order to investigate the extent of the forgeries and has ordered the Nuclear Safety & Security Commission to perform inspections on all of the nuclear-fuel generation units operated by us. Although we believe that the fraudulently certified parts are not material to the function or safety of our nuclear-fuel generation units, the investigation and unexpected blackouts may raise social and political concerns regarding the safety of our nuclear units, which could have an adverse impact on our financial conditions and results of operation.

We are subject to environmental regulations, including in relation to climate change, and our operations could expose us to substantial liabilities.

We are subject to national, local and overseas environmental laws and regulations, including increasing pressure to reduce emission of carbon dioxide relating to our electricity generation activities as well as our natural resource development endeavors overseas. Our operations could expose us to the risk of substantial liability relating to environmental or health and safety issues, such as those resulting from 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 currently operate extensive programs to comply with various environmental regulations, including the Renewable Portfolio Standard program, under which each generation subsidiary was required to supply 2.0% of the total energy generated from such subsidiary in the form of renewable energy in 2012 and will be required to supply 10.0% by 2022, with fines being levied on any unit failing to do so in the prescribed timeline. Satisfaction of the supply target for 2012 by our generation subsidiaries is currently under evaluation, and our generation subsidiaries found to have failed to satisfy the supply target may become subject to fine or other penalty although we are currently unable to predict the type or amount of fine or other penalty that will be imposed. There is no assurance that such fine or other penalty will not be substantial. If substantial, such fine or other penalty may have a material adverse effect on our business, results of operations or financial condition.

Our environmental measures, including the use of environmentally friendly but more expensive parts and equipment and budgeting capital expenditures for the installation of such facilities, may result in increased operating costs and liquidity requirement. The actual cost of installation and operation of such equipment and related liquidity requirement will depend 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, including in respect of climate change. See Item 4B. “Business Overview—Environmental Programs” and “Business Overview—Renewable Energy.”

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 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.

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 the non-nuclear generation subsidiaries own and operate and do not cover all types or amounts of loss that could arise in connection with the ownership and operation of these power plants. In addition, unlike us, our generation subsidiaries are not permitted to self-insure, and accordingly have not self-insured, against risks of their uninsured assets or business. Accordingly, material adverse financial consequences could result from a serious accident to the extent it is uninsured.

In addition, because neither we nor our generation subsidiaries, other than KHNP, carry any insurance against terrorist attacks, an act of terrorism would result in significant financial losses. See Item 4B. “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 51.0% of our issued capital stock. As of December 31, 2012, the last day on which our shareholder registry was closed, the Government, directly and through Korea Finance Corporation (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 (other than sales of treasury stock).

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 operation 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.

The ongoing challenges affecting the European, U.S. and global financial sectors, fluctuations in oil and commodity prices and the general weakness of the European, U.S., Chinese and global economy have increased the uncertainty of global economic prospects in general and have adversely affected, and may continue to adversely affect, the Korean economy. 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. Furthermore, as a result of adverse global and Korean economic conditions, there has been continuing volatility in the stock prices of Korean companies. While deterioration of the global economy slowed in the second half of 2009, with some signs of stabilization and improvement beginning in 2010, substantial uncertainties have resurfaced in the form of fiscal and financial sector crisis in several European countries (including Greece, Spain, Italy, Ireland, France and Portugal), as well as threats to the viability of the Euro as a common European currency, a downgrade in the sovereign or other credit ratings of governments and financial institutions in Europe and the United States and signs of cooling of the Chinese and Indian economies, and the overall prospects for the Korean and global economy in 2013 and beyond remain uncertain. While our aggregate financial exposure to the European countries currently being affected by the ongoing fiscal and financial crisis remains less than 1% of our consolidated total assets, any future deterioration of the global economy may have an adverse impact on 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. Factors that determine economic and business cycles of 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 hurt the Korean economy in the future include, among others:

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further deterioration of the fiscal and financial crisis in Europe, downgrades in the sovereign or other credit ratings of the governments and financial institutions in Europe and the United States, as well as the slowdown of the Chinese economy, which could have adverse effects on the global, and in turn Korean, credit and financial markets;

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inflation levels, volatility in foreign currency reserve levels, commodity prices (including coal, oil, LNG prices), exchange rates (including fluctuation of U.S. dollar and Japanese Yen exchange rates or revaluation of the Renminbi), interest rates, and stock markets and inflows and outflows of foreign capital, either directly, into the stock markets, through derivatives or otherwise;

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potential friction with Korea’s trading partners arising, in part, from Korea’s heavy reliance on exports;

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

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

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

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uncertainty and volatility in real estate prices arising, in part, from the Government’s policy-driven tax and other regulatory measures;

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rising fiscal deficit as a result of a decrease in tax revenues and a substantial increase in the Government’s expenditures for welfare and other social programs;

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political uncertainty or increasing strife among or within political parties in Korea, including as a result of the continued polarization of the positions of the ruling conservative party and the progressive opposition;

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

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any other development that has a material adverse effect in the global economy, such as an act of war, a terrorist act or a breakout of an epidemic such as SARS, avian flu or swine flu or natural disasters such as earthquakes and tsunamis and the related disruptions in the relevant economies with global repercussions;

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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

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an increase in the level of tensions or an outbreak of hostilities in the Korean peninsula.

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

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. In

recent years, there have been heightened security concerns stemming from North Korea’s nuclear weapons and long-range missile programs and increased uncertainty regarding North Korea’s actions and possible responses from the international community. Recently, on April 13, 2012, North Korea conducted a test of a long-range missile against the protests of many in the international community, including Korea, Japan and the United States. On December 12, 2012, North Korea conducted a rocket launch under the premise of placing a satellite in orbit. This launch has been widely criticized by the international community as a veiled attempt by North Korea to further develop its long-range ballistic missile program. The United Nations Security Council has strongly condemned the tests and the United States has cut off food aid to North Korea. North Korea has responded by issuing a statement that it is free to take necessary retaliatory measures. Most recently, on February 12, 2013, North Korea conducted a nuclear test at its underground test facility in Punggye-ri. The nuclear test has been condemned by the international community and the United National Security Council and the European Union has agreed to a set of new sanctions against North Korea. North Korea has responded to these new sanctions by announcing its withdrawal from the Korean Armistice Agreement and with provocative rhetoric which has increased tensions on the Korean peninsula. After Korea announced on October 7, 2012, that it would extend the range of its ballistic missiles from 185 to 500 miles, a distance which could hit the northeast corner of North Korea from launch sites in central Korea, the National Defense Commission (which is the top military body of North Korea) announced it was ready to wage war on the United States and its allies and threatened to launch nuclear weapons in the event the United States or its allies use nuclear weapons against North Korea.

There recently has been increased uncertainty about the future of North Korea’s political leadership and its implications for the economic and political stability of the region. Shortly after the death of Kim Jong-il, a long-standing former ruler of North Korea, in December 2011 his son Kim Jong-eun was named North Korea’s Supreme Commander of the Armed Forces. Whether Kim Jong-eun will successfully solidify his political power or whether he will implement policies that will successfully assist North Korea in withstanding the many challenges it faces, however, remains uncertain. In addition, North Korea’s economy faces severe challenges. For example, on November 30, 2009, North Korea redenominated its currency at a ratio of 100 to 1 as part of its first currency reform in 17 years as a way to control inflation and reduce the income gap among its citizens. In tandem with the currency redenomination, the North Korean government banned the use or possession of foreign currency by its residents and closed down privately run markets, which led to severe inflation and food shortages. Such developments may further aggravate social and political tensions within North Korea.

Furthermore, there have been recent military conflicts on the Korean peninsula. On March 26, 2010, the Cheonan, a Korean navy ship, sank off the western coast of Korea killing 46 soldiers. An investigation carried out by the Joint Civilian-Military Investigation Group, consisting of investigators from Korea, the United States, Australia, the United Kingdom and Sweden, concluded that the Cheonan was sunk by a North Korean torpedo. Also, on November 23, 2010, the North Korean military fired artillery shells onto the Korean island of Yeonpyeong, killing two Korean soldiers and two civilians which set off an exchange of fire between the two sides. Around the end of 2010, the International Criminal Court tentatively concluded that North Korea’s sinking of the Cheonan and shelling of the island of Yeonpyeong constituted a war crime, and launched a preliminary investigation regarding such incidents.

On August 22, 2011, North Korea unilaterally declared that it will legally dispose of all Korean-owned real estate, equipment and raw materials it seized in April 2010 within the Mt. Geumgang resort area (the “Geumgang area”), concurrent with its seizure and embargo of Korean supplies and assets and its exit order of all employees who were dispatched from Korea (the “2011 Declaration”). It is estimated that the value of the assets, including the real estate, owned by the Government, the Korea Tourism Organization and other private Korean companies in the Geumgang area amount to approximately ￦484.1 billion. Tourism in the Geumgang area has effectively been discontinued since a Korean tourist was shot and killed by a North Korean soldier on July 11, 2008. More recently, on March 27, 2013, North Korea severed the last remaining military hotline with Korea and on April 2, 2013, North Korea announced that it would restart a nuclear reactor located at Yongbyon. In addition, on April 3, 2013 North Korea suspended access to the Kaesong joint industrial zone to South Korean workers and on April 26, 2013 the Government decided to withdraw South Korean workers from the complex. Currently, the

Government is in the process of considering various other options, including legal and diplomatic measures but it is unclear whether and when the complex will resume operation.

There can be no assurance that the level of tension and instability in the Korean peninsula will not escalate in the future, or that the political regime in North Korea may not suddenly collapse. Any further increase in tension or uncertainty relating to the military or economic stability in the Korean peninsula, including a breakdown of diplomatic negotiations over the North Korean nuclear program, occurrence of military hostilities or heightened concerns about the stability of North Korea’s political leadership, could have a material adverse effect on our business, financial condition and results of operation and could lead to a decline in the market value of our common shares and our American depositary shares.

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

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

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

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 (1) 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 (2) 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.

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 40.0% ceiling on acquisitions of shares by foreigners in the aggregate. The Financial Services Commission may increase or decrease these percentages if it deems it necessary for the public interest, protection of investors or industrial policy.

In addition to the aggregate foreign investment ceiling, the Financial Investment Services and Capital Markets Act and 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 foreigners 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 foreigner 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 Code 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 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 potential 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, actions by the government, or the perception that such actions are taking place, may take place or has ceased, 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.

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.

ITEM 4. INFORMATION ON THE COMPANY

Item 4A. 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 (“KEPCO”) Act as the successor to Korea Electric Company. Our registered office is located at 167 Samseong-dong, Gangnam-gu, Seoul, Korea, and our telephone number is 82-2-3456-4216. Our website address is www.kepco.co.kr. Our agent in the United States is Korea Electric Power Corporation, New York Office, located at 7th Floor, 400 Kelby Street, Fort Lee, NJ 07024.

The Korean electric utility industry traces its origin to the establishment of the first electric utility company in Korea in 1898. On July 1, 1961, the industry was reorganized by the merger of Korea Electric Power Company, Seoul Electric Company and South Korea Electric Company, which resulted in the formation of Korea Electric Company. From 1976 to 1981, the Government acquired the private minority shareholdings in Korea Electric Company. After the Government acquired all the remaining shares of Korea Electric Company, Korea Electric Company dissolved, and we were incorporated in 1981 and assumed the assets and liabilities of Korea Electric Company. We ceased to be wholly-owned by the Government in 1989 when the Government sold 21.0% of our common stock. As of December 31, 2012, the last day on which our shareholder registry was closed, the Government maintained 51.1% ownership in aggregate of our common shares by direct holdings by the Government and indirect holdings through Korea Finance Corporation, 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 51.0% of our capital. Direct or indirect ownership of more than 50% of our outstanding common stock enables the Government to control the approval of certain corporate matters relating to us that require a shareholders’ resolution, including approval of dividends. The rights of the Government and Korea Finance Corporation 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 Finance Corporation, in consultation with the Ministry of Strategy 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 Strategy and Finance, is responsible for approving, subject to review by the Korea Electricity Commission, the electricity rates we charge our customers. See Item 4B. “Business Overview—Sales and Customers—Electricity Rates.” We furnish reports to officials of the Ministry of Trade, Industry and Energy, the Ministry of Strategy and Finance and other Government agencies and regularly consult with such officials on matters relating to our business and affairs. See Item 4B. “Business Overview—Regulation.” Our non-standing directors, who comprise the majority of our board of directors, must be appointed by the Ministry of Strategy and Finance following the review and resolution of the Public Agencies Operating Committee from a pool of candidates recommended by our director nomination committee and must have ample knowledge and experience in business management, and our President must be appointed by the President of the Republic upon the motion of the minister of the Ministry of Trade, Industry and Energy following the nomination by our Director Nomination Committee, the review and resolution of the Public Agencies Operating Committee and an approval at the general meeting of shareholders. See Item 6A. “Directors and Senior Management—Board of Directors.”

Item 4B. 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

substantially all of the electricity produced in Korea. As of December 31, 2012, we and our generation subsidiaries owned approximately 84.2% of the total electricity generating capacity in Korea (excluding plants generating electricity primarily for private or emergency use). In 2012, we sold to our customers approximately 466,593 gigawatt-hours of electricity. We purchase electricity principally from our generation subsidiaries and to a lesser extent from independent power producers. Of the 488,903 gigawatt-hours of electricity we purchased in 2012, 30.4% was generated by KHNP, our wholly-owned nuclear and hydroelectric power generation subsidiary, 57.3% was generated by our wholly-owned five non-nuclear generation subsidiaries and 12.3% was generated by independent power producers. 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 2012, we had sales of Won 49,121 billion and net loss of Won 3,167 billion (excluding non-controlling interests) compared to sales of Won 43,175 billion and net loss of Won 3,370 billion (excluding non-controlling interests) in 2011. Our sales increased primarily as a result of a 2.5% increase in kilowatt hours of electricity sold in 2012, which was attributable primarily to the general increase in demand for electricity among consumers in Korea as a result of a slow but steady economic growth in 2012. The increase in the volume of electricity sold was due to a 2.6% increase of electricity sold to the industrial sector, including light power usage, and a 2.1% increase in kilowatt hours of electricity sold to the commercial sector, and a 3.1% increase in kilowatt hours of electricity sold to the residential sector. See Item 5A. “Operating Results.”

Our revenues are closely tied to demand for electricity in Korea. Demand for electricity in Korea increased at a compounded average growth rate (“CAGR”) of 4.9% per annum from 2008 to 2012, compared to the real gross domestic product, or GDP, which increased at a CAGR of 2.9% during the same period, according to The Bank of Korea. The GDP growth rate was 2.0% for 2012 as compared to 3.6% for 2011. Demand for electricity in Korea increased by 2.5% from 2011 to 2012.

Strategy

In September 2011, we announced our new corporate strategy titled “Global Top Green & Smart Energy Pioneer KEPCO”. Under this strategy, we seek to become a leading global energy enterprise through enhanced global competitiveness (for example, by selectively expanding our overseas investments) and strengthening our contribution to the global environmental campaigns through continued development of “green” and “smart” power-related technologies. We also aim to adapt to the growing uncertainties in global economy by selectively pursuing new business opportunities and through development of innovative technologies. More specifically, we aim to achieve the following:

•

Become a global leader in “green” technology. With the increasing demand for, and embrace of, environmentally friendly, or green, energy worldwide in substitution of the conventional thermal energy, we believe that green energy represents an important business potential as well as a worthy corporate purpose befitting our status as a provider of public utility. In particular, our “green growth” initiatives will focus on the following:

(i)

Development of eco-friendly power technologies—In order to lead low-carbon green growth in response to climate change, we are continuing to develop eco-friendly green technology throughout the power supply and consumption value chain. The basic objectives are to reduce carbon emissions during the generation phase, reduce power loss during transmission and encourage efficient power consumption. To this end, we have invested heavily in research and development of eco-friendly green technologies and plan to develop and commercialize them, some examples being power generation through coal gasification.

(ii)

Improvement in efficiency in our electricity transmission and distribution — We are currently developing, or seek to develop, an intelligent power transmission and distribution network, or “smart grids,” based on advanced information technology, in order to promote a more efficient

allocation and use of electricity by consumers, a superconducting technology that will improve efficiency in the transmission of electricity over such network and localized “high-voltage direct current” technology that will reduce electricity loss over the course of transmission and distribution.

(iii)

Participation in the development of green energy infrastructure—We are currently developing, or seek to develop, charging facilities for electric vehicles and standard models for a residential unit that can be powered solely by electricity.

•

Capture and expand business opportunities. We seek to capture business opportunities presented by our leadership in green technology and transmission and distribution technology by developing commercial applications thereof, including by way of developing related information and communication technologies and diversifying our consulting business.

•

Expand overseas business. The primary focus of our overseas business diversification is twofold: (i) leveraging our experience and knowhow gained from our core business of electricity generation in Korea, including nuclear power generation, to capture business opportunities overseas so as to expand our growth potential, and (ii) direct participation in mining and other resource development projects overseas, by way of acquisition or equity investment, in order to facilitate and increase self-sufficiency in fuel procurement. We also plan to expand our geographic focus from Southeast Asia to various other regions in the world, including the resource-rich Middle East, Africa and Australia.

•

Advance innovation and operational efficiency. Promoting innovation and operational efficiency has been and will continue to be an important part of our business strategy. Specifically, we aim to foster further strategic cooperation among our affiliates and adopt innovative management systems that will enhance operational efficiency and cost control.

Recent Developments

Increase in Electricity Tariff Rates

Effective August 6, 2012, the Government increased the electricity rates that we charge to the end-users by an average of 4.9% as further set forth in the following table:

Type of
Usage*

Residential

Commercial

Industrial

Educational

Agricultural

Street
Lighting

Overnight
Usage

Low-voltage

High-voltage

Average

Low-voltage

High-voltage

Average

% increase

2.7

3.9

4.9

4.4

3.9

6.0

3.0

4.9

Effective January 14, 2013, the Government further increased the electricity rates that we charge to the end-users by an average of 4.0% as further set forth in the following table:

Type of
Usage

Residential

Commercial

Industrial

Educational

Agricultural

Street
Lighting

Overnight
Usage

Low-voltage

High-voltage

Average

Low-voltage

High-voltage

Average

% increase

2.0

2.7

6.3

4.6

3.5

4.4

3.5

3.0

5.0

We cannot assure you that such tariff increase will be sufficient to fully offset the adverse impact on our results of operations from the current or future movements in fuel costs.

Correction of Accounting for Fuel Cost Pass-through Adjustment

As of July 1, 2011, a new electricity tariff system approved by the Government took effect featuring a fuel cost pass-through adjustment (“FCPTA”). This system was intended to allow us to pass through fluctuations in fuel costs ultimately to the customers. The FCPTA amount is determined based on a prior three-months moving average of international fuel prices and other factors, which is reflected two months later. On July 29, 2011, out of inflationary and other policy considerations, the Government issued a hold-order suspending us from billing or collecting the FCPTA amount from customers.

Our accounting policy was to recognize unbilled fuel cost adjustments as assets under the IFRS Conceptual Framework when we concluded that it is probable that future economic benefits would flow to us. We had concluded that we controlled a resource as a result of past events from which future economic benefits were expected to flow to us. The Regulation for Electricity Service, which regulates the FCPTA system, provides a legal “resource” or right to bill where the costs we incur will result in future cash flows. The operation of the FCPTA system creates a right to charge rates in amounts that would permit us to recover the related costs, such amounts being subject to government approval. In addition, we relied on the authority of the Ministry of Trade, Industry and Energy, which regulates and approves the electricity tariff we charge to our customers, including the FCPTA system. As of December 31, 2011, we determined that it was probable that economic benefits associated with the unbilled fuel cost adjustments would be realizable based on the authority of the Ministry of Trade, Industry and Energy in setting and enforcing electricity rates for customers. Therefore, we concluded that as of December 31, 2011 it was probable that our unbilled FCPTA amount would be collected.

We previously recognized revenue and a receivable for the FCPTA amounts subject to the hold order in the amount of Won 357,085 million at December 31, 2011. However, we came to realize that our FCPTA rate regulatory scheme closely resembles a cost-of service scheme, and have therefore determined that the appropriate accounting for the unbilled FCPTA amounts is to reduce cost of sales by the unbilled FCPTA amounts and recognize a related non-financial asset by the same amount, which is more consistent with accounting policies for rate regulated assets of other standard setting bodies. In accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors, we used judgment in developing and applying an accounting policy that results in information that is relevant and reliable. In making that judgment, management considered pronouncements of other standard-setting bodies that use a similar conceptual framework to develop accounting standards, other accounting literature and accepted industry practices. We have concluded that the aforementioned error is immaterial, and corrected the accounting for our unbilled FCPTA amounts in our consolidated financial statements as of and for the year ended December 31, 2011 included in Item 18. “Financial Statements.”

During the fourth quarter of 2012, we had further consultations with the Ministry of Trade, Industry and Energy as to the outlook for the lifting the hold-order. Furthermore, on January 11, 2013, the Ministry of Trade, Industry and Energy informed us that the FCPTA system needed to be reassessed in light of the current circumstances such as the prolonged unbilled period since the announcement of the FCPTA system. We have therefore concluded that, in consideration of the prolonged unbilled period and recent consultations with, and information from, the Ministry, we would not be able to bill and collect the unbilled FCPTA amounts for the foreseeable future. As a result, we wrote off the entire unbilled FCPTA amounts of Won 1,877 billion recognized through December 31, 2012, including the unbilled FCPTA amounts as of December 31, 2011. As a result, there were no FCPTA amounts remaining in the consolidated statement of financial position as of December 31, 2012.

Furthermore, we will cease recording a regulatory asset prospectively related to the FCPTA amounts unless and until the likelihood of recovery once again satisfies the probable threshold contained in the IFRS Conceptual Framework or enacted IFRS at such time.

See Item 4B. “Business Overview—Recent Developments— Correction of Accounting for Fuel Cost Pass-through Adjustment”, Item 4B. “Business Overview—Sales and Customers—Electricity Rates”, Item 4B. “—Recent Developments— Correction of Accounting for Fuel Cost Pass-through Adjustment,” Item 5B. “Operating and Financial Review and Prospects—Overview,” Item 5B. “Operating and Financial Review and Prospects—Critical Accounting Policy—Correction of Accounting for Fuel Cost Pass-through Adjustment” and Notes 2, 15 and 36 to the notes to our consolidated annual financial statements.

Permitted Entry of Private Enterprises in the Coal-Fired Power Generation Business

While preparing for the sixth Basic Plan, which was announced in February 2013, the Ministry of Trade, Industry and Energy accepted applications from private independent power producers, in addition to those from our generation subsidiaries, for construction of additional coal-fired power plants. Previously, private enterprises were not permitted to own and operate coal-fired power plants in Korea. Out of such applications by 15 independent power producers for construction of a total of 40 coal-fired generation units with aggregate

generation capacity of 37,100 megawatts, the Government approved applications for the construction of six generation units with aggregate generation capacity of 6,000 megawatts as well as two additional generation units with aggregate generation capacity of 2,000 megawatts to provide for the contingency of failed or delayed construction of these six generation units. Construction for the six generation units is scheduled to be completed between 2018 and 2021. While it remains to be seen whether construction of these generation units will be completed as scheduled, if it were to be completed as scheduled 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.

Implementation of the 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”) road map. In accordance with such plan, we will install “smart meters” and related communication networks and operating systems for 22 million households as part of the “smart grid” initiative in an effort to enhance efficiency in the power electricity industry and alleviate growing energy shortage concerns. Smart meters refer to digital meters that record, on a real-time basis, electricity consumption within a household and the effective tariff rate at the time of electricity usage so that consumers will have a price-based incentive to enhance efficiency in their electricity usage. On the other hand, the smart grid refers to the next-generation network for electricity distribution that integrates information technology into the existing power grid with the aim of enabling two-way real time exchange of information between electricity suppliers and consumers for optimal efficiency in electricity use. The smart grid project is scheduled to be completed in 2030, and the AMI project is currently scheduled to be completed in 2020. We expect that the smart grid initiative would 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. As of December 31, 2012, we have installed 3.8 million smart meter units, and plan to install an additional 3.2 million units in 2013. The AMI project is expected to cost an additional Won 1.7 trillion by 2020.

Government Ownership and Our Interactions with the Government

The KEPCO Act requires that the Government own at least 51.0% of our capital stock. Direct or indirect ownership of more than 50.0% of our outstanding common 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 Finance Corporation as holders of our common stock are exercised by the Ministry of Trade, Industry and Energy in consultation with the Ministry of Strategy and Finance. The Government currently has no plan to cease to own, directly or indirectly, at least 51.0% 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 provide a fair return to our security holders, as well as the Government’s overall policy considerations, such as inflation. See Item 4B. “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 increased demand for electric power. See Item 5B. “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 non-nuclear wholly-owned subsidiaries (namely, KOMIPO, KOSEP, KOWEPO, KOSPO and EWP), each with its own management structure, assets and liabilities. These steps were completed upon the approval of the split-off at our shareholders’ meeting in April 2001.

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

While our ownership percentage of the non-nuclear and non-hydroelectric generation subsidiaries will depend on the further adjustments to the Restructuring Plan to be adopted by the Government, we plan to retain 100.0% ownership of both KHNP and 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.

In order to support the logistics of the cost-based pool system, the Government established the Korea Power Exchange in April 2001 pursuant to the Electricity Business Law. 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 Non-nuclear 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. We may resume the stock listing process for KOSEP in due course, after taking into consideration the overall stock market conditions and other pertinent matters. The aggregate foreign ownership of our generation subsidiaries is limited to 30.0% of total power generation capacity in Korea. In consultation with us, the Government will determine the size of the ownership interest to be sold and the timing of such sale, with a view to encouraging competition and assuring adequate electricity supply and debt service capability.

We believe the Government currently has no specific plans to resume the public offering of KOSEP or commence the same for any of our other generation subsidiaries in the near future. However, we cannot assure that our generation subsidiaries will not become part of Government-led privatization initiatives in the future for reasons relating to a change in Government policy, economic and market conditions and/or other factors.

Suspension of the Plan to Form and Privatize Distribution Subsidiaries

Initiatives to Improve the Structure of Electricity Generation

On August 25, 2010, based on deliberations with various interested parties, the Ministry of Trade, Industry and Energy announced the Proposal for the Improvement in the Structure of the Electric Power Industry, whose key initiatives include the following: (i) maintain the current structure of having six generation subsidiaries, (ii) designate the six generation subsidiaries as “market-oriented public enterprises” under the Public Agency Management Act in order to foster competition among them and autonomous and responsible management by them, (iii) create a supervisory unit to act as a “control tower” in reducing inefficiencies created by arbitrary division of labor among the six generation subsidiaries and fostering economies of scale among them and require the presidents of the generation subsidiaries to hold regular meetings, (iv) 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, (v) 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 (vi) create separate accounting systems for electricity generation, transmission, distribution and sales with the aim of introducing competition in electricity sales in the intermediate future.

Pursuant to this Proposal, in December 2010 the Ministry of Trade, Industry and Energy announced guidelines for a cooperative framework between us and our generation subsidiaries, and in January 2011 the five non-nuclear generation subsidiaries formed a “joint cooperation unit” and transferred their pumped-storage

hydroelectric business units to KHNP. Furthermore, in January 2011 the six generation subsidiaries were officially designated as “market-oriented public enterprises,” whereupon the President of Korea appoint the president and the statutory auditor of each such subsidiary; the selection of outside directors of each such subsidiary is subject to approval by the minister of the Ministry of Strategy 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 Commission conducts performance evaluation of such subsidiaries. Previously, our president appointed the president and the statutory auditor of each such subsidiary; the selection of outside 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.

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 Electricity Business Act with responsibilities for setting the price of electricity, handling the trading and collecting relevant data for the electricity market in Korea. The suppliers of electricity in Korea consist of our six generation subsidiaries, which were spun off from us in April 2001, and independent power producers, which numbered 439 as of December 31, 2012. We distribute electricity purchased through the Korea Power Exchange to the end users.

Our Relationship with the Korea Power Exchange

We have certain relationships with the Korea Power Exchange as follows: (i) we and our six generation subsidiaries are member corporations of the Korea Power Exchange and collectively own 100.0% of its share capital, (ii) three of the 10 members of the board of directors of the Korea Power Exchange are currently our or our subsidiaries’ employees, and (iii) one of our employees is currently a member in three of the key committees of the Korea Power Exchange that are responsible for evaluating the costs of producing electricity, making rules for the Korea Power Exchange and gathering and disclosing information relating to the Korean electricity market.

Notwithstanding the foregoing relationships, however, we do not have control over the Korea Power Exchange or its policies since, among others, (i) the Korea Power Exchange, its personnel, policies, operations and finances are closely supervised and controlled by the Government, namely through the Ministry of Trade, Industry and Energy, and are subject to a host of laws and regulations, including, among others, the Electricity Business Act and the Public Agencies Management Act, as well as the Articles of Incorporation of the Korea Power Exchange, (ii) we are entitled to elect no more than one-third of the Korea Power Exchange directors and our representatives represent only a minority of its board of directors and committees (with the other members being comprised of representatives of the Ministry of 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 on April 12, 2005 that stated that we are not deemed to have significant influence or control over the decision-making process of the Korea Power Exchange relating to its business or financial affairs.

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

Marginal Price

The primary purpose of the marginal price is to compensate the generation companies for fuel costs, which represents the principal component of the variable costs of generating electricity. The concept of marginal price under the cost-based pool system has undergone several changes in recent years in large part due to the sharp fluctuations in fuel prices.

Under the system marginal price regime adopted on May 1, 2008 and currently in effect, the marginal price of electricity at which our generation subsidiaries sell electricity to us is determined using the following formula:

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

The system marginal price represents, in effect, the marginal price of electricity at a given hour at which the projected demand for electricity and the projected supply of electricity for such hour intersect, as determined by the merit order system, which is a system used by the Korea Power Exchange to allocate which generation units will supply electricity for 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 peak-hour versus non-peak hour demand analysis. The projected supply of electricity at a given hour is determined as the aggregate of the available capacity of all generation units that have submitted bids to supply electricity for such hour. 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. 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 (comprised of representatives from the Ministry of Trade, Industry and Energy, the Korea Power Exchange, generation companies, scholars and researchers as well as us) on a monthly basis and reflected in the following month based on the fuel costs as of two months prior to such determination. The final allocation of electricity supply, however, is further adjusted on the basis of other factors, including the proximity of a generation unit to the geographical area to which power is being supplied, network and fuel constraints and the amount of power loss.

The purpose of the merit order system is to encourage generating 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 additional adjustment mechanism is designed to improve the overall cost-efficiency in the distribution and transmission of electricity to the end-users by adjusting for losses arising from the distribution and transmission process.

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

The adjusted coefficient applies in principle to all generation units that use the same type of fuel. However, the adjusted coefficient does not apply to independent power producers using LNG or oil as fuel. The adjusted

coefficient is determined by the Cost Evaluation Committee in principle on an annual basis, although in exceptional cases driven by external factors such as fuel costs and electricity tariff rates, the adjusted coefficient may be adjusted on a quarterly basis.

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 costs of constructing generation facilities and to provide incentives for new construction. The capacity price is determined annually by the Cost Evaluation Committee based on the construction costs and maintenance costs of a standard generation unit and is paid to each generation company for the amount of available capacity indicated in the bids submitted the day before trading. From time to time, the capacity price is adjusted in ways to soften the impact of changes in the marginal price over time based on the expected rate of return for our generational subsidiaries. Currently, the capacity price is Won 7.46/kWh and since January 1, 2012 has applied equally to all generation units, regardless of fuel types used.

Effective as of January 1, 2007, a regionally differentiated capacity price system was introduced by setting a standard capacity reserve margin in the range of 12.0% to 20.0% 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 a failure 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 satisfaction of the standard capacity reserve margin receive reduced capacity price. Since 2006, the capacity price received by generation units has been subject to 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 a “peak” hour, a “shoulder-peak” hour or an “off-peak” hours (it being highest for the peak hour and lowest for the off-peak hour) 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 same capacity pricing mechanism applies to all generation units regardless of fuel types used.

Following the suspension of the plan to form separate distribution subsidiaries through privatization (see “—Restructuring of the Electric Power Industry in Korea—Suspension of the Plan to Form and Privatize Distribution Subsidiaries”), there was a discussion of replacing the current cost-based pool system with a more market-oriented system known as a two-way bidding pool system. Under the two-way bidding pool system, a pool of generating companies on the supply side and a pool of retail distributors on the demand side would each make a bid based on which the electricity price will be determined, which would contrast with the current system where we have a virtual monopoly of the demand side as the purchaser and distributor of substantially all of electricity in Korea. However, we believe that due to the indefinite suspension of the restructuring plan, the two-way bidding pool system is unlikely to be adopted in the near future absent any unexpected change in government policy.

Power Trading Results

The results of power trading, as effected through the Korea Power Exchange, for our generation subsidiaries for the year ended December 31, 2012 are as follows:


	Items	Volume (Gigawatt hours)		Percentage of Total Volume (%)		Sales to KEPCO (in billions of Won)		Percentage of Total Sales (%)		Unit Price (Won/kWh)
Generation Companies	KHNP		148,416		31.5		6,733		15.8		45.4
	KOSEP		60,098		12.7		4,533		10.6		75.4
	KOMIPO		50,005		10.6		5,413		12.7		108.2
	KOWEPO		54,094		11.5		5,936		13.9		109.7
	KOSPO		61,041		12.9		6,937		16.3		113.7
	EWP		54,857		11.6		5,836		13.7		106.4
	Others⁽¹⁾		42,992		9.2		7,199		17.0		167.5

	Total		471,503		100.0		42,587		100.0		90.3

Energy Sources	Nuclear		143,453		30.4		5,682		13.3		39.6
	Bituminous coal		184,485		39.1		12,238		28.7		66.3
	Anthracite coal		8,015		1.7		833		2.0		103.9
	Oil		14,516		3.1		3,673		8.6		253.0
	LNG		3,763		0.8		791		1.9		210.1
	Combined-cycle		101,355		21.5		16,888		39.7		166.6
	Hydro		3,346		0.7		605		1.4		181.0
	Pumped-storage		3,631		0.8		809		1.9		222.9
	Others		8,939		1.9		1,068		2.5		119.4
	Total		471,503		100.0		42,587		100.0		90.3
Load	Base load		332,456		70.5		18,200		42.7		57.7
	Non-base load		139,047		29.5		24,387		57.3		175.4

	Total		471,503		100.0		42,587		100.0		90.3

Note:

(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).

Power Purchased from Independent Power Producers Under Power Purchase Agreements

In 2012, we purchased an aggregate of 17,400 gigawatt hours of electricity generated by independent power producers under existing power purchase agreements. These purchases were made outside of the cost-based pool system of power trading. These independent power producers had an aggregate generating capacity of 4,650 megawatts as of December 31, 2012.

Power Generation

As of December 31, 2012, we and our generation subsidiaries had a total of 563 generation units, including nuclear, thermal, hydroelectric and internal combustion units, representing total installed generating capacity of 68,848 megawatts. Our thermal units produce electricity using steam turbine generators fired by coal, oil and LNG. 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, 2012 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		23		20,716		82.3
Thermal:
Coal		51		24,534		91.7
Oil		16		3,950		38.9
LNG		4		888		40.2

Total thermal		71		29,372		83.1

Internal combustion		206		367		35.4
Combined-cycle		109		12,936		65.1
Hydro		69		5,330		10.4
Wind		31		70		20.1
Solar		50		51		12.4
Fuel cell		4		6		78.1

Total		563		68,848		72.4

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.

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

We seek to achieve efficient use of fuels and diversification of generating capacity by fuel type. In the past, we relied principally upon oil-fired thermal generation units for electricity generation. Since the oil shock in 1974, however, Korea’s power development plans have emphasized the construction of nuclear generation units. While nuclear units are more expensive to construct than non-nuclear units of comparable capacity, nuclear fuel is less expensive than fossil fuels in terms of electricity output per unit cost. However, efficient operation of nuclear units requires that such plants be run continuously at relatively constant energy output levels. As it is impractical to store large quantities of electrical energy, we seek to maintain nuclear power production capacity at approximately the level at which demand for electricity is continuously stable. 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 is currently the least expensive thermal fuel per kilowatt-hour of electricity produced, and therefore we seek to maximize the use of bituminous coal for generation needs in excess of the stable demand level, except for meeting short-term surges in demand which require rapid start-up and shutdown. Thermal units fired by LNG, hydroelectric units and 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 recommissioned thermal and internal combustion units in order to help meet power demand. Subject to market conditions, our generation subsidiaries plan to continue to

add additional thermal and internal combustion units. 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-1970s. Since then, we have diversified our fuel sources and constructed relatively few oil-fired thermal units compared to units of other fuel types.

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.


	2008		2009		2010		2011		2012		% of 2012 Gross Generation⁽¹⁾
	(in gigawatt hours, except percentages)
Electricity generated by generation subsidiaries:
Nuclear		150,958		147,771		148,596		154,723		150,327		29.8
Thermal:
Coal		174,156		193,803		198,287		199,516		198,715		39.4
Oil		7,981		11,970		10,874		9,456		14,188		2.8
LNG		1,518		762		2,288		2,233		3,256		0.6

Total thermal		183,655		206,535		211,449		211,205		216,159		42.8

Internal combustion		503		697		731		821		692		0.1
Combined-cycle		55,909		47,580		70,081		71,668		75,733		15.0
Hydro		3,836		4,091		4,393		4,815		5,051		1.0
Wind		53		82		91		117		128		0.02
Solar and fuel cells		15		24		44		60		68		0.01

Total generation		394,929		406,780		435,384		443,409		448,158		88.8

Electricity generated from others:
Thermal		25,699		25,274		37,197		42,240		54,720		10.8
Hydro and other renewable		1,727		1,550		2,079		11,244		2,023		0.4

Total generation (others)		27,426		26,824		39,276		53,484		56,743		11.2

Gross generation		422,355		433,604		474,660		496,893		504,863		100
Auxiliary use⁽²⁾		17,374		18,258		19,372		19,689		15,740		2.9
Pumped-storage ⁽³⁾		3,243		3,713		3,663		4,257		4,789		0.9

Total net generation⁽⁴⁾		401,726		411,631		451,433		472,947		484,334		96.1

Transmission and distribution losses⁽⁵⁾		16,106		16,770		18,034		17,430		17,291		3.6

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 is gross generation minus auxiliary and pumped-storage use.

(5)	Total transmission and distribution losses divided by total net generation.

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


	2008		2009		2010		2011		2012
	(Megawatts)
Total capacity		70,353		73,310		76,078		76,649		81,806
Peak load		62,794		66,797		71,308		73,137		75,987
Average load		48,082		49,498		54,185		56,723		57,601

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, we transferred all of our nuclear and hydroelectric power generation assets and liabilities to KHNP.

KHNP owns and operates 23 nuclear generation units at four power plant complexes in Korea, located in Kori, Wolsong, Yonggwang and Ulchin, 50 hydroelectric generation units including 16 pumped storage hydro generation units as well as five solar generation units and one wind generation unit as of December 31, 2012.

The table below sets forth the number of units and installed capacity as of December 31, 2012 and the average capacity factor by types of generation units in 2012.


	Number of Units		Installed Capacity⁽¹⁾		Average Capacity Factor⁽²⁾
			(Megawatts)		(Percent)
Nuclear		23		20,716		82.3
Hydroelectric		50		5,303		10.7
Wind		1		0.8		6.0
Solar		5		16		13.3

Total		79		26,035.8

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.

Shin-Kori-2 and Shin-Wolsong-1, each with a 1,000 megawatt capacity, commenced commercial operation in July 2012. We are currently building five additional nuclear generation units, consisting of one unit with a 1,000 megawatt capacity and four units each with a 1,400 megawatt capacity at the Shin-Kori and Shin-Ulchin sites, respectively. We expect to complete these units between 2013 and 2018. In addition, we plan to build four additional nuclear units, each with a 1,400 megawatt capacity, and two additional nuclear units, each with a 1,500 megawatt capacity at the Shin-Kori and Shin-Ulchin sites between 2019 and 2024.

Nuclear

The table below sets forth certain information with respect to the nuclear generation units of KHNP as of December 31, 2012.

Unit

Reactor
Type⁽¹⁾

Reactor Design⁽²⁾

Turbine and

Generation⁽³⁾

Commencement
of Operations

Installed
Capacity

(Megawatts)

Kori-1

PWR

GEC, Hitachi, D

1978

587

Kori-2

PWR

GEC

1983

650

Kori-3

PWR

GEC, Hitachi

1985

950

Kori-4

PWR

GEC, Hitachi

1986

950

Shin-Kori-1

PWR

D, KOPEC, W

D, GE

2011

1,000

Shin-Kori-2

PWR

D, KOPEC, W

D, GE

2012

1,000

Wolsong-1

PHWR

AECL

1983

679

Wolsong-2

PHWR

AECL, H, K

H, GE

1997

700

Wolsong-3

PHWR

AECL, H

H, GE

1998

700

Wolsong-4

PHWR

AECL, H

H, GE

1999

700

Shin-Wolsong-1

PWR

D, KOPEC, W

D, GE

2012

1,000

Yonggwang-1

PWR

W, D

1986

950

Yonggwang-2

PWR

W, D

1987

950

Yonggwang-3

PWR

H, CE, K

H, GE

1995

1,000

Yonggwang-4

PWR

H, CE, K

H, GE

1996

1,000

Yonggwang-5

PWR

D, CE, W, KOPEC

D, GE

2002

1,000

Yonggwang-6

PWR

D, CE, W, KOPEC

D, GE

2002

1,000

Ulchin-1

PWR

1988

950

Ulchin-2

PWR

1989

950

Ulchin-3

PWR

H, CE, K

H, GE

1998

1,000

Ulchin-4

PWR

H, CE, K

H, GE

1999

1,000

Ulchin-5

PWR

D, KOPEC, W

D, GE

2004

1,000

Ulchin-6

PWR

D, KOPEC, W

D, GE

2005

1,000

Total nuclear

20,716

Notes:

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

(2)	“W” means Westinghouse Electric Company (U.S.A.); “AECL” means Atomic Energy Canada Limited (Canada); “F” means Framatome (France); “H” means Hanjung; “CE” means Combustion Engineering (U.S.A.); “D” means Doosan Heavy Industries; “K” means Korea Atomic Energy Research Institute.

(3)	“GEC” means General Electric Company (UK); “P” means Parsons (Canada and UK); “W” means Westinghouse Electric Company (U.S.A.); “A” means Alsthom (France); “H” means Hanjung; “GE” means General Electric (U.S.A.); “D” means Doosan Heavy Industries; “Hitachi” means Hitachi Ltd. (Japan).

The table below sets forth the average capacity factor and average fuel cost per kilowatt for 2012 with respect to each nuclear generation unit of KHNP.


Unit	Average Capacity Factor		Average Fuel Cost Per kWh
	(Percent)		(Won)
Kori-1		51.0		5.8
Kori-2		84.5		5.5
Kori-3		78.1		5.1
Kori-4		100.1		5.0
Shin-Kori-1		81.2		5.3
Shin-Kori-2		98.5		7.2
Wolsong-1		81.0		7.7
Wolsong-2		94.4		7.5
Wolsong-3		90.7		7.8
Wolsong-4		100.2		7.7
Shin-Wolsong-1		95.7		5.9
Yonggwang-1		92.9		5.8
Yonggwang-2		101.7		4.3
Yonggwang-3		80.1		5.9
Yonggwang-4		88.8		4.6
Yonggwang-5		72.1		5.4
Yonggwang-6		83.1		4.8
Ulchin-1		80.1		5.2
Ulchin-2		98.7		5.0
Ulchin-3		69.4		5.5
Ulchin-4		0.0		0.0
Ulchin-5		100.4		5.0
Ulchin-6		88.2		4.8

Total nuclear		82.3		5.6

Under extended-cycle operations, nuclear units can be run continuously for periods longer than the conventional 12-month period between scheduled shutdowns for refueling and maintenance. 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 average duration of shutdown for routine fuel replacement and maintenance was 52.6 days, except for Uljin unit-4 which was shut down for long-term maintenance.

KHNP’s nuclear units experienced an average of 0.39 unplanned shutdowns per unit in 2012. 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. Beginning in November 2012, two nuclear units at Yonggwang were shut down for approximately two months pending investigation of allegations that certain parts were supplied using of fraudulent quality assurance documents. See Item 3D. “Risk Factors—Risks Relating to KEPCO—Operation of nuclear power generation facilities inherently involves numerous hazards and risks, any of which could result in a material loss of revenues or increased expenses.”

Hydroelectric

Effective January 1, 2011, pursuant to the Government’s Proposal for Improvements in the Structure of the Electric Power Industry announced on August 25, 2010, the five non-nuclear generation companies transferred

all of the assets and liabilities relating to their pumped-storage and five other hydroelectric business units to KHNP. The table below sets forth certain information, including the installed capacity as of December 31, 2012 and the average capacity factor in 2012.


Location of Unit	Number of Units		Classification	Year Built		Installed Capacity		Average Capacity Factor
						(Megawatts)		(%)
Hwacheon		4	Dam waterway		1944		108.0		17.5
Chuncheon		2	Dam		1965		62.3		21.2
Euiam		2	Dam		1967		45.0		34.4
Cheongpyung		4	Dam		1943		139.6		23.6
Paldang		4	Dam		1973		120.0		42.9
Seomjingang		3	Basin deviation		1945		34.8		46.3
Boseonggang		2	Basin deviation		1937		4.5		63.9
Kwoesan		2	Dam		1957		2.8		29.7
Anheung		3	Dam waterway		1978		0.5		47.0
Kangreung		2	Basin deviation		1991		82.0		0.0
Topyeong		1	Dam		2011		0.05		29.2
Muju⁽¹⁾		1	Dam		2003		0.4		28.0
Sancheong⁽¹⁾		1	Dam		2001		1.0		36.0
Yangyang⁽¹⁾		2	Dam		2005		1.4		16.2
Yecheon⁽¹⁾		1	Dam		2011		0.9		21.1
Cheongpeoung⁽¹⁾		2	Pumped Storage		1980		400		4.3
Samrangjin⁽¹⁾		2	Pumped Storage		1985		600		8.0
Muju⁽¹⁾		2	Pumped Storage		1995		600		8.9
Sancheong⁽¹⁾		2	Pumped Storage		2001		700		9.2
Yangyang⁽¹⁾		4	Pumped Storage		2006		1,000		7.9
Cheongsong⁽¹⁾		2	Pumped Storage		2006		600		10.7
Yecheon⁽¹⁾		2	Pumped Storage		2011		800		11.3

Total		50					5,303		10.7

Note:

(1)	Indicates facilities that have been transferred from our five non-nuclear generation companies to KHNP as of January 1, 2011.

Solar/Wind

The table below sets forth certain information, including the installed capacity as of December 31, 2012 and the average capacity factor in 2012, regarding each solar and wind power unit of KHNP. Yecheon-units 1 and 2 began commercial operation in July 2012 and December 2012, respectively. KHNP added a 11-megawatt capacity unit to the Younggwang Solar Park, for which unit commercial operation began in November 2012.


Location of Unit	Classification	Year Built		Installed Capacity		Average Capacity Factor
				(Megawatts)		(Percent)
Yonggwang	Solar		2008		13.9		13.1
Kori	Wind		2008		0.8		6.0
Yecheon-1	Solar		2012		1.4		14.4
Yecheon-2	Solar		2012		0.6		13.2

Total					16.7

K-Water (formerly 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 the Republic available for commercially viable hydroelectric power generation. Consequently, we expect that no new major hydroelectric power plants will be built in the foreseeable future. Due to the ease of its start-up and shut-down mechanism, hydroelectric power generation is reserved for peak 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, 2012 and the average capacity factor and average fuel cost per kilowatt in 2012 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:
Samchunpo #1, 2, 3, 4, 5, 6		20.8		3,248		92.3		49.1
Yong Hung #1, 2, 3, 4		5.8		3,373		92.5		48.3
Anthracite:
Yongdong #1, 2		35.4		326		92.1		77.3
Oil-fired:
Yosu #1, 2		35.6		330		82.2		74.0

Total thermal		20.7		7,277		89.8		51.1

Combined cycle and internal Combustion:
Bundang gas turbine #1,2,3,4,5,6,7,8; steam turbine #1, 2		18.5		924		56.3		171.6

Total		19.7		8,201		87.5		60.6

Korea Midland Power Co., Ltd.


	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		17.9		4,000		88.6		63.5
Anthracite:
Seocheon #1, 2		29.4		400		86.5		120.6
Oil-fired:
Jeju #2, 3		12.4		150		68.4		289.2
LNG-fired:
Seoul #4, 5		43.0		388		48.9		239.0
Incheon #1, 2		40.3		500		36.3		226.3

Total thermal		21.4		5,438		80.3		95.3

Combined-cycle and internal combustion:
Boryeong gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3,		13.8		1,350		53.0		169.7
Incheon gas turbine #1, 2, 3, 4; steam turbine #1, 2		3.8		1,012		79.4		150.1
Jeju Gas Turbine #3		35.1		55		0.5		5,124.9
Jeju Internal Combustion Engine #1,2		5.5		80		67.1		261.5

Total		9.0		2,947		63.6		163.6

Wind-powered:
Yangyang #1, 2		6.5		3		13.5		184.6


Hydroelectric:
Boryeong		3.8		7.5		26.7		62.8

Photovoltaic power & Fuel Cell generation:
Boryeong (Photo) site		4.7		0.6		12.8		342.2
Seocheon (Photo) site		4.9		1.2		14.2		413.8
Jeju (Photo) site		0.8		1.1		12.2		171.6
Seoul(Photo) site		1.4		1.3		14.6		23.7
Yeosu(Photo) site		0.8		2.2		14.6		73.7
Incheon(Poto) site		1.0		0.3		14.6		189.9
Boryeong (fuel Cell) site		4.3		0.3		16.0		275.6

Total Photovoltaic & Fuel Cell generation		2.1		7.1		71.5		189.3

Total		17.7		7,953		74.7		108.2

Korea Western Power Co., Ltd.


	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		12.4		4,000		93.2		49.2
Oil-fired:
Pyeongtaek #1, 2, 3, 4		31.1		1,400		29.3		204.1

Total thermal		17.2		5,400		76.6		65.2

Combined cycle:
Pyeongtaek		20.5		480		36.3		172.3
West Incheon		20.5		1,800		79.7		142.6
Gunsan		2.6		718.4		88.8		135.9

Total combined-cycle		16.2		2,998.4		74.9		143.0

Hydroelectric:
Taean		5.3		2.2		22.8		—

Total hydroelectric		5.3		2.2		22.8		—

Solar:
Taean		7.4		0.1		12.4		—
Taean2		0.9		0.6		12.8		—
Gunsan		2.5		0.3		14.0		—
Samryangjin		5.1		3.0		14.6		—
Sejong City		0.5		5.0		12.8		—

Total solar		2.2		9.0		14.0		—

Total		16.8		8,409.5		76.0		93.1

Korea Southern Power Co., Ltd.


	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		12		4,000		100.8		49.2
Oil-fired:
Youngnam #1, 2		41.5		400		36.5		235.5
Nam Jeju #3, 4		6.5		200		78.2		244.9

Total thermal		14.3		4,600		94.3		62.1
Combined cycle:
Shin Incheon #9, 10, 11, 12		16.7		1,800		78.2		141.5
Busan #1, 2, 3, 4		9.5		1,800		85.9		137.3
Yeongwol #1		2.3		848		58.8		144.7
Hallim		16.5		105		13.1		278.8

Total combined cycle		11.1		4,553		75.8		140.8

Internal combustion:
Nam Jeju		22.3		40		14.2		223.9

Total internal combustion		22.3		40		14.2		223.9

Wind power:
Hankyung		6.9		21		23.9		0.8
Seongsan		3.3		20		26.1		0.6

Total wind power		5.1		41		25.0		0.7

Solar		2.2		6		13.5		0.1

Total		12.7		9,240		84.7		96.3

Korea East-West Power Co., Ltd.


	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		9.5		4,000		95.6		63.3
Honam #1, 2		39.8		500		80.8		84.4
Anthracite:
Donghae #1, 2		13.8		400		88.2		101.0
Oil-fired:
Ulsan #1, 2, 3, 4, 5, 6		36.7		1,800		40.3		236.3

Total thermal		24.89		6,700		76.2		67.8

Combined cycle:
Ulsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3		15.9		1,200		66		162.1
Ilsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2		17.3		900		50.8		198.4

Total combined-cycle and internal combustion		16.6		2,100		58.3		175.4

Dangjin (Mini hydro)		3.0		5.0		64.0		84.4

Total Mini hydro		3.0		5.0		64.0		84.4

Dangjin (Photovoltaic)		2.0		1.0		14.4		157.6
Ulsan (Photovoltaic)		1.0		0.5		14.2		161.7
Kwangyang (Photovoltaic)		1.1		2.3		12.2		125.8
Dangjin Waste Treatment Facility (Photovoltaic)		1.0		1.3		12.1		113.7
Donghae (Photovoltaic)		6.0		1.0		12.8		732.5

Total Photovoltaic		2.2		6.1		13.1		231.62

Ilsan #1 (Fuel Cell)		3.1		2.4		64.3		271.7
Ilsan # 2 (Fuel Cell)		1.1		2.8		87.7		226.6

Total Fuel Cell		2.1		5.2		76.9		244.0

Total		9.8		8,816.3		74.5		107.4

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.


Power Plant	Capacity	Completed (Year)	Extension	Company
Taean #1-8	4,000MW (500MW×8)	FGD⁽¹⁾: 1998 to 2007 SCR⁽²⁾: 2005 to 2007 EP⁽³⁾: 1995 to 2007 LNCS⁽⁴⁾:1995 to 2007 EP⁽³⁾ upgrade (#5, 2009) EP⁽³⁾ upgrade (#6, 2010) EP⁽³⁾ upgrade (#4, 2011) EP⁽³⁾ upgrade (#1, 2012)	Anti-pollution	KOWEPO
Pyeongtaek #1-4	1,400 MW (350×4)	FGD⁽¹⁾: 2005 SCR⁽²⁾: 2006 to 2007 EP⁽³⁾: 1992 EP⁽³⁾ upgrade (#1, 2009) EP⁽³⁾ upgrade (#2, 2010)	Anti-pollution	KOWEPO
Seoincheon CC	1,800 MW (gas turbines 150 MW ×8) (steam turbines 75 MW ×8)	LNCS⁽⁴⁾: 1992 Gas turbine upgrade (2003 to 2006)	Anti-pollution Efficiency improvement	KOWEPO
Honam #1	250 MW	2010	10 years	EWP
Honam #2	250 MW	2010	10 years	EWP
Gunsan CC	718.4 MW (gas turbines 233.3 MW ×2) (steam turbines 251.8 MW ×1)	LNCS⁽⁴⁾: 2010	Anti-pollution	KOWEPO
Boryeong #1-8	4,000 MW (500×8)	FGD⁽¹⁾: 1996 to 2009 SCR⁽²⁾: 2006 to 2009 LNCS⁽⁴⁾: 1993 to 2009 EP⁽³⁾: 1984 to 2009 2009 (#1,2) Control System upgrade (#6, 2011, #3,5, 2012)	Anti-pollution 10 years Performance- improvement	KOMIPO
Incheon #1-2	500 MW (250×2)	SCR⁽²⁾: 2002 to 2005 LNCS⁽³⁾: 2002 to 2005	Anti-pollution	KOMIPO
Seoul #4,5	387.5 MW (137.5×1) (250×1)	SCR⁽²⁾ : 2001 to 2002	Anti-pollution	KOMIPO
Seocheon #1,2	400 MW (200×2)	FGD⁽¹⁾: 1998, SCR : 2006 LNCS⁽⁴⁾: 2004 to 2005 EP⁽³⁾: 1982 to 1983	Anti-pollution	KOMIPO
Incheon #1,2	500 MW (250×2)	1996(#1) 2002(#2)	10 years	KOMIPO


Power Plant	Capacity	Completed (Year)	Extension	Company
Incheon CC #2	508.9 MW (gas turbines 164 MW × 2) (steam turbines 181 MW × 1)	SCR : 2012	Anti-pollution	KOMIPO
Jeju T/P #2~3	150 MW (75 × 2)	SCR⁽²⁾: 2010 EP⁽³⁾: 2000	Anti-pollution	KOMIPO
Jeju D/P #1~2	80 MW (40 × 2)	SCR⁽²⁾: 2005 to 2009 EP⁽³⁾: 2005 to 2009 FGD⁽¹⁾: 2005 to 2009	Anti-pollution	KOMIPO
Yonghung #5-6	1,750 MW (870 × 2)	2014	30 years	KOSEP
Hadong #1-8	4,000 MW (500 × 8)	FGD⁽¹⁾ : 1998 to 2009 EP ⁽³⁾ : 1997 to 2009 LNCS⁽³⁾ :1997 to 2009 SCR⁽²⁾: 2006 to 2009	Anti-pollution	KOSPO
Shin-Incheon CC	1,800 MW (gas turbines 150 × 8) (steam turbines 150 × 4)	LNCS⁽⁴⁾ : 1996	Anti-pollution	KOSPO
Busan CC	1,800 MW (gas turbines 150 × 8) (steam turbines 150 × 4)	LNCS⁽⁴⁾ : 2003 to 2004	Anti-pollution	KOSPO
Youngnam #1-2	400 MW (200 × 2)	FGD⁽¹⁾: 1999 SCR⁽²⁾: 2002 EP⁽³⁾: 1988 to 1990 LNCS⁽⁴⁾: 2002-	Anti-pollution	KOSPO
Namjeju T/P #3-4	200 MW (100 × 2)	FGD⁽¹⁾: 2006 to 2007 SCR⁽²⁾: 2006 to 2007 EP ⁽³⁾: 2006 to 2007	Anti-pollution	KOSPO
Namjeju D/P #1-4	40 MW (10 × 4)	SCR⁽²⁾: 1999 to 2000 EP⁽³⁾: 1990 to 1991	Anti-pollution	KOSPO
Yeongwol CC	848MW (gas turbines 183 × 3) (steam turbines 299 × 1)	LNCS⁽⁴⁾: 2010	Anti-pollution	KOSPO

Notes:

(1)	“FGD” means a flue gas desulphurization system.

(2)	“SCR” means a selective catalytic reduction system.

(3)	“EP” means an electrostatic precipitation system.

(4)	“LNCS” means a low nitrodioxide (NO2 ) combustion system.

Transmission and Distribution

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

In July 2004, the Government adopted the Community Energy System to enable regional districts to source electricity from independent power producers to supply electricity without having to undergo the cost-based pool system used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. A supplier of electricity under the Community Energy System must be authorized by the Korea Electricity Commission and be approved by the minister of the Ministry of Trade, Industry and Energy in accordance with the Electricity Business Act. The purpose of this system is to decentralize electricity supply and thereby reduce transmission costs and improve the efficiency of energy use. These entities do not supply

electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System. As of March 31, 2013, 14 districts were using this system. The generation capacity installed or under construction of the electricity suppliers in these 14 districts amounted to approximately 1% of the aggregate generation capacity of our generation subsidiaries as of March 31, 2013. Since the introduction of the Community Energy System in 2004, a total of 31 districts have obtained the license to supply electricity through the Community Energy System, but 17 of such districts have reportedly abandoned plans to adopt the Community Energy System, largely due to the relatively high level of capital expenditure required, the rise in fuel costs and the lower-than-expected electricity output per cost. However, if the Community Energy System is widely adopted, it will erode our currently dominant market position in the generation and distribution of electricity in Korea, and may have a material adverse effect on our business, growth, revenues and profitability.

The table below sets forth as of December 31, 2010, 2011 and 2012 and March 31, 2013, the number of districts with government permits to participate in the Community Energy Supply, the number of apartments in such districts and generating capacity to be installed.


As of the date specified below	Number of Districts with Permit to Participate		Number of Apartments		Generating Capacity
			(in thousands)		(Megawatts)
December 31, 2010⁽¹⁾		31		320		1,474
December 31, 2011⁽¹⁾		31		320		1,474
December 31, 2012⁽²⁾		15		130		608
March 31, 2013⁽³⁾		14		110		488

Note:

(1)

Includes 17 districts with a permit to participate in the Community Energy System, which have subsequently announced to-date that they will not adopt such system. The number of apartments and generating capacity represented by such districts are approximately 210 thousand units and 986 megawatts, respectively.

(2)	As of December 31, 2012, 16 districts with permits had announced that they would not adopt the Community Energy System.

(3)	As of March 31, 2013, one additional district announced that it will not adopt the system, resulting in 14 districts with permits.

As of December 31, 2012, our transmission system consisted of 31,622 circuit kilometers of lines of 765 kilovolts and others including high voltage direct current lines, and we had 768 substations with an aggregate installed transformer capacity of 271,247 megavolt-amperes.

As of December 31, 2012, our distribution system consisted of 104,082 megavolt-amperes of transformer capacity and 8,583,423 units of support with a total line length of 442,641 circuit kilometers.

In recent years, we have made substantial investments in our transmission and distribution systems to increase coverage and improve efficiency. Our current projects principally focus on increasing capabilities of the existing lines and reducing our transmission and distribution loss, which was 3.6% in 2012. In light of the increased damage to large-scale transmission and distribution facilities, we plan to reinforce stability of our transmission and distribution facilities through stricter design and material specifications. In addition, we also plan to expand underground transmission and distribution facilities to meet customer demand for more 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 upgrading our evaluation technologies, automation of electricity transmission and development of new transmission technologies.

In particular, as part of our overall business strategy, we are currently developing, or seek to develop, an intelligent power transmission and distribution network, or “smart grids,” based on advanced information technology, in order to promote a more efficient allocation and use of electricity by consumers, a superconducting technology that will improve efficiency in the transmission of electricity over such network and localized “high-voltage direct current” technology that will reduce electricity loss over the course of transmission and distribution. See “—Strategy.” In July 2012, the Government implemented a master plan to build out a smart grid, which include the Advanced Metering Infrastructure (AMI) road map as further described in “—Overview—Recent Developments—Implementation of the Advanced Metering Infrastructure”. In accordance with such plan, we will install “smart meters” and related communication networks and operating systems for 22 million households as part of the “smart grid” initiative in an effort to reduce nationwide electricity consumption and alleviate growing energy shortage concerns. The smart grid project is scheduled to be completed in 2030, and the AMI project is currently scheduled to be completed in 2020. We expect that the smart grid initiative would 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. As of December 31, 2012, we have installed 3.8 million smart meter units, and plan to install an additional 3.2 million units in 2013. The AMI project is expected to cost an additional Won 1.7 trillion by 2020.

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.

Fuel

Nuclear

Uranium, the principal fuel source for nuclear power, accounted for 34.1%, 34.9% and 33.6% of our fuel requirements for electricity generation in 2010, 2011 and 2012, respectively.

All uranium ore concentrates 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 in U.S. dollars.

In order to ensure stable supply, KHNP enters into long-term and medium-term contracts with various suppliers and supplements such supplies with purchases in spot markets. In 2012, KHNP purchased 100%, or approximately 4,432 tons, of its uranium concentrate requirement under long-term supply contracts with suppliers in Australia, Canada, France, Germany, Russia, Kazakhstan, the United States and Niger. 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, Germany, Japan, Russia, the United Kingdom and the United States. 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 43.6%, 43.1% and 42.2% of our fuel requirements for electricity generation in 2010, 2011 and 2012, respectively, and anthracite coal accounted for 1.9%, 1.9% and 2.0% of our fuel requirements for electricity generation in 2010, 2011 and 2012, respectively.

In 2012, our generation subsidiaries purchased approximately 78.6 million tons of bituminous coal, of which approximately 43.6%, 33.4%, 5.7%, 5.2% and 12.1% were imported from Indonesia, Australia, the United States, Russia, and others, respectively. Approximately 80.3% of the bituminous coal requirements of our generation

subsidiaries in 2012 were purchased under long-term contracts with the remaining 19.7% purchased in the spot market. Some of our long-term contracts relate to specific generating plants and extend through the end of the projected useful lives of such plants, subject in some cases to periodic renewal. Pursuant to the terms of our long-term supply contracts, prices are adjusted annually based on market conditions. The average cost of bituminous coal per ton purchased under such contracts amounted to Won 107,413, Won 116,073 and Won 113,705 in 2010, 2011 and 2012, respectively. Due to price increases as well as increased shipping cost for bituminous coal, our generation subsidiaries may not be able to secure their respective bituminous coal supply at prices comparable to those of prior periods. See Item 3D. “Risk Factors—Risks Relating to KEPCO—Increases in fuel prices will adversely affect our results of operations and profitability, as we may not be able to pass on the increased cost to consumers at a sufficient level or on a timely basis.”

In 2012, our generation subsidiaries purchased approximately 1.3 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 130,836, Won 136,471 and Won 141,669 in 2010, 2011 and 2012, respectively.

Oil

Oil accounted for 2.7%, 2.4% and 3.5% of our fuel requirements for electricity generation in 2010, 2011 and 2012, respectively.

In 2012, our generation subsidiaries purchased approximately 16.7 million barrels of fuel oil, of which 42.6% was purchased from domestic refiners and the remainder from foreign sources, in each case, through competitive open bidding. Purchase prices are based on the spot market price in Singapore. The average cost per barrel was Won 98,023, Won 128,395 and Won 139,204 in 2010, 2011 and 2012, respectively.

LNG

LNG accounted for 16.6%, 16.7% and 17.6% of our fuel requirements for electricity generation in 2010, 2011 and 2012, respectively. In 2012, we purchased approximately 11.3 million tons of LNG from Korea Gas Corporation, a Government-controlled entity in which we currently own a 24.5% equity interest. Under the terms of the LNG contract with Korea Gas Corporation, our annual minimum purchase quantity is determined by our negotiations with Korea Gas Corporation, subject to the Government’s approval, and may be adjusted through negotiations between the parties. Under this contract, all of our five non-nuclear generation subsidiaries were jointly and severally obligated to purchase a total of 10.3 million tons of LNG in 2012, subject to an automatic price adjustment based on a pre-determined formula if the actual purchased amount exceeds or falls short of the contracted amount. In addition, the annual purchase quantity of LNG to be purchased from Korea Gas Corporation will exclude any amount of LNG purchased from a source other than Korea Gas Corporation. We believe the quantities of LNG provided under such contract will be adequate to meet the needs of our generation subsidiaries for LNG for the next several years. The LNG supply contract between our generation subsidiaries and Korea Gas Corporation generally have a term of 20 years.

The annual purchase price for LNG is determined by our negotiations with Korea Gas Corporation, subject to approval by the Ministry of Trade, Industry and Energy. Korea Gas Corporation imports LNG primarily from Indonesia, Malaysia, Brunei, Qatar, Oman, Australia, Egypt and Nigeria and supplies LNG to us and other Korean gas companies. The average cost per ton of LNG under our contract with Korea Gas Corporation was Won 778,866, Won 888,808 and Won 1,020,528 in 2010, 2011 and 2012, respectively.

Hydroelectric

As of December 31, 2012, hydroelectric units represented approximately 1.1% of our total installed generating capacity.

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.

As of January 1, 2011, assets and liabilities relating to the pumped storage units of the five non-nuclear generation subsidiaries were recognized and transferred to KHNP pursuant to the Government’s Proposal for Improvements in the Korean Electric Power Industry.

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 4.9% per annum for the five years ended December 31, 2012. According to The Bank of Korea, the compounded growth rate for real gross domestic product, or GDP, was approximately 2.9% for the same period. The GDP growth rate was approximately 6.2% in 2010, approximately 3.6% in 2011 and approximately 2.0% in 2012.

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


	2008			2009			2010			2011			2012
Growth in GDP (at 2008 constant prices)		2.3	%		0.3	%		6.2	%		3.6	%		2.0	%
Growth in electricity consumption		4.5	%		2.4	%		10.1	%		4.8	%		2.5	%

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 electrical 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 the 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.


	2008 (GWh)		YoY growth (%)			2009 (GWh)		YoY growth (%)			2010 (GWh)		YoY growth (%)		2011 (GWh)		YoY growth (%)			2012 (GWh)		YoY growth (%)			% of Total 2012
Residential		57,878		3.9			59,426		2.7			63,200		6.3		63,524		0.5			65,484		3.1			14.0
Commercial		86,827		5.6			89,619		3.2			97,410		8.7		99,504		2.1			101,593		2.1			21.8
Educational		5,783		9.0			6,465		11.8			7,453		15.3		7,568		1.5			7,860		3.9			1.7
Industrial		203,475		4.4			207,216		1.8			232,672		12.3		251,491		8.1			258,102		2.6			55.3
Agricultural		8,869		8.0			9,671		9.0			10,654		10.2		11,232		5.4			12,776		13.8			2.7
Street lighting		2,847		1.9			2,954		3.8			3,081		4.3		3,145		2.1			3,158		0.4			0.7
Overnight Power		19,391		(0.4	)		19,122		(1.4	)		19,690		3.0		18,606		(5.5	)		17,620		(5.3	)		3.8

Total		385,070		4.5			394,475		2.4			434,160		10.1		455,070		4.8			466,593		2.5			100.0

The industrial sector represents the largest segment of electricity consumption in Korea. Demand from the industrial sector was 258,102 gigawatt hours in 2012, representing a 2.6% increase from 2011, largely due to the continued export-led growth of the Korean economy. Demand from the commercial sector has increased in recent years, largely due to increased commercial activities in Korea and the rapid expansion of the service sector of the Korean economy, which has resulted in increased office building construction, office automation and use of air conditioners. Growth in the commercial sector is also attributable to the construction industry and the expansion of the leisure and distribution industries. Demand from the commercial sector was 101,593 gigawatt hours in 2012, representing a 2.1% increase from 2011, largely as a result of the increased commercial activities in Korea, which was partially offset by weakened consumer sentiment in light of the enhanced uncertainties in the global economy.

In 2012, we distributed electricity to approximately 20 million households, which represent substantially all of the households in Korea. Demand from the residential sector is largely dependent on population growth and increased use of air conditioners and other electrical appliances. Demand from the residential sector was 65,484 gigawatt hours in 2012, representing a 3.1% increase compared to 2011 due to increased usage of heating and air conditioning.

Demand Management

Our ability to provide an adequate supply of electricity is principally measured by the facility capacity reserve margin and the supply reserve margin. The facility capacity 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.


	2008			2009			2010			2011			2012
Facility reserve margin		12.0	%		9.8	%		6.7	%		4.8	%		7.7	%
Supply reserve margin		9.1	%		7.9	%		6.2	%		5.5	%		5.2	%

While the facility reserve margin increased from 2011 to 2012 due to an increase in our generation capacity, the supply reserve margin decreased in 2012 compared to 2011 because of an increase in overhaul periods for our base-load generators and an increase in demand for electricity as a result of economic recovery and extreme weather conditions in 2012.

While we seek to meet the growing demand for electricity in Korea primarily by continuing to expand our generating capacity through the addition of new generating facilities, we also implement several measures to curtail electricity consumption, especially during peak periods. We apply time-of-use rate schedules 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 the peak hours and seasons such as providing incentives for reducing power consumption during peak hours.

Electricity Rates

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

Under the Electricity Business Law 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 equal to the sum of:

•

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

•

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

•

our equity interests in generation subsidiaries; and

•

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

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

For the purpose of determining the fair rate of return, the rate base is divided into two components 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, a Korean equity market index, and the correlation of the stock price of our company with KOSPI. In 2011, the approved rate of return on the debt component of the rate base was 3.9% while the approved rate of return on the equity component of the rate base was 7.3%. As a result of such approved rates of returns, the fair rate of return in 2011 was determined to be 5.9%. The fair rate of return for 2012 has not yet been determined.

The Electricity Business Law 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 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 since 2006, our actual rates of return have been 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. Partly in response to the variance between our actual rates of return and the fair rates of return, the Government from time to time adjusts the electricity tariff rates, but there typically is a significant time lag for the tariff adjustment as such adjustment requires a series of deliberative

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. Furthermore, there is no assurance that the tariff adjustments will have the desired effect at a level anticipated or at all, or that they will not have unintended adverse consequences.

Recent adjustments to the electricity tariff rates by the Government involve the following, which were made principally in response to the rising fuel prices which hurt our profitability as well as to encourage a more efficient use of electricity by the different sectors:

•

effective August 1, 2010, a 3.5% overall increase in our average tariff rate, consisting of increases in the residential, educational, industrial, street lighting and overnight power usage tariff rates by 2.0%, 5.9%, 5.8%, 5.9% and 8.0%, while making no changes to the commercial and agricultural tariff.

•

effective August 1, 2011, a 4.9% overall increase in our average tariff rate, consisting of increases in the industrial, commercial, residential, educational, street lighting and overnight power usage tariff rates by 6.1%, 4.4%, 2.0%, 6.3%, 6.3% and 8.0%, while making no changes to the agricultural tariff.

•

effective December 5, 2011, a 4.5% overall increase in our average tariff rate, consisting of increases in the industrial, commercial, educational and street lighting tariff rates by 6.5%, 4.5%, 4.5% and 6.5%, while making no changes to the residential, agricultural and overnight power usage tariff.

•

effective August 6, 2012, a 4.9% overall increase in our average tariff rate, consisting of increases in the residential, commercial, educational, industrial, street lighting, agricultural and overnight power usage tariff rates by 2.7%, 4.4%, 3.0%, 6.0%, 4.9%, 3.0% and 4.9%, respectively.

•

effective January 14, 2013, a 4.0% overall increase in our average tariff rate, consisting of increases in the residential, commercial, educational, industrial, street lighting, agricultural and overnight power usage tariff rates by 2.0%, 4.6%, 3.5%, 4.4%, 5.0%, 3.0% and 5.0%, respectively.

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 day, the rate option selected by the user and, in the residential sector, the amount of electricity used per household, as well as other factors. For example, we adjust for seasonal tariff variations by applying higher rates when demand tends to rise such as during the months of 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.

Our current tariff schedule, which became effective as of January 14, 2013, is summarized below by the type of usage:

•

Industrial. The basic charge varies from Won 5,270 per kilowatt to Won 8,050 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from Won 51 per kilowatt hour to Won 192.5 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

•

Commercial. The basic charge varies from Won 5,990 per kilowatt to Won 8,050 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from Won 51.5 per kilowatt hour to Won 189.4 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

•

Residential. Residential tariff includes a basic charge ranging from Won 400 for electricity usage of less than 100 kilowatt hours to Won 12,230 for electricity usage in excess of 500 kilowatt hours. Residential tariff also includes an energy usage charge ranging from Won 59.1 to Won 690.8 per kilowatt hour for electricity usage depending on the amount of usage and voltage.

•

Educational. The basic charge varies from Won 5,740 per kilowatt to Won 6,980 per kilowatt depending on the voltage used and the rate option. The energy usage charge varies from Won 43.8 per kilowatt hour to Won 160.4 per kilowatt hour depending on the voltage used, the season and the rate option.

•

Agricultural. The basic charge varies from Won 350 per kilowatt to Won 1,150 per kilowatt depending on the type of usage. The energy usage charge varies from Won 21.2 per kilowatt-hour to Won 39.1 per kilowatt hour depending on the type of usage.

•

Street-lighting. The basic charge is Won 5,970 per kilowatt and the energy usage charge is Won 81.5 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 35.6 per watt applies, with the minimum charge per month of Won 1,160.

Fuel Cost Pass-through Adjustment to the Tariff System

Further to the announcement by the Ministry of Trade, Industry and Energy in February 2010, a new electricity tariff system went into effect on July 1, 2011. This system is designed to overhaul the prior system for determining electricity tariff chargeable to customers by more closely aligning the tariff levels to the movements in fuel prices, with the aim of providing more timely pricing signals to the market regarding the expected changes in electricity tariff levels and encouraging more efficient use of electricity by customers. Previously, the electricity tariff consisted of two components: (i) base rate and (ii) usage rate based on the cost of electricity and the amount of electricity consumed by the end-users. Under the new tariff system, the electricity tariff is also to have a third component of fuel cost pass-through adjustment (“FCPTA”) rate, which is to be added to or subtracted from the sum of the base rate and the usage rate on a monthly basis based on the three-month average movements of coal, LNG and oil prices, which is reflected as FCPTA two months later. The new tariff system is intended to provide greater financial stability and ensure a minimum return on investment to electricity suppliers, such as us. However, due to inflationary and other policy considerations relating to protecting the consumers from sudden and substantial rises in electricity tariff, the Ministry of Trade, Industry and Energy issued a hold order on July 29, 2011 suspending our billing and collecting of the FCPTA amount. The hold order remains in effect to-date. In addition, on January 11, 2013, we were informed by the Ministry of Trade, Industry and Energy that the fuel cost-based tariff adjustment system would need to be reassessed in light of the prolonged unbilled period after the announcement of such system.

There is no assurance as to when the Government will lift the hold order and allow us to bill and collect the accumulated FCPTA amount or whether the new tariff system will undergo other amendments to the effect that it will not fully cover our fuel and other costs on a timely basis or at all, or will not have unintended consequences that we are not presently aware of. Any such development may have a material adverse effect on our business, financial condition, results of operations and cash flows. See Item 4B. “Business Overview—Recent Developments—Correction of Accounting for Fuel Cost Pass-through Adjustment”, Item 4B. “Business Overview—Sales and Customers—Electricity Rates”, Item 4B. “—Recent Developments—Correction of Accounting for Fuel Cost Pass-through Adjustment,” Item 5B. “Operating and Financial Review and Prospects—Overview”, Item 5B. “Operating and Financial Review and Prospects—Critical Accounting Policy—Fuel Cost Pass-through Adjustment” and Notes 2, 15 and 36 to the notes to our consolidated annual financial statements.

Power Development Strategy

In February 2013, the Government announced the sixth Basic Plan relating to the future supply and demand of electricity. The sixth Basic Plan, which is effective for the period from 2013 to 2027, focuses on, among other

things, (i) minimizing the need to construct new generation facilities through active consumer demand management, (ii) ensuring that we maintain adequate electricity reserve appropriate to the size of the national economy, and (iii) expanding our generation capacity to promote efficient supply of electricity in consideration of the stability of the national electricity grid network and the specific needs of localities. The Government may announce a supplemental plan for the construction of additional nuclear plants, which was not included in the Sixth Plan; such plan may increase the amount of our required capital expenditure. We cannot assure that the sixth Basic Plan, or the plans subsequently adopted, will successfully achieve their intended goals, the foremost of which is to formulate a capacity expansion plan that will result in balanced overall electricity supply and demand in Korea at an affordable cost to the end users. If there is a significant variance between the actual capacity expansions by us and our generation subsidiaries based on the projected electricity supply and demand and the actual supply and demand, this may result in inefficient use of our capital, mispricing of electricity and undue financing costs on the part of us and our generation subsidiaries, which may have a material adverse effect on our results of operations, financial condition and cash flows.

Capital Investment Program

The table below sets forth, for each of the years ended December 31, 2010, 2011 and 2012, the amounts of capital expenditures (including capitalized interest) for the construction of generation, transmission and distribution facilities.


2010	2011		2012
(In billions of Won)
￦11,414	￦	11,984	￦	13,215

In accordance with the sixth Basic Plan, our generation subsidiaries currently intend to add new installed capacity of 54,743 megawatts during the period from 2013 to 2027 by newly constructing 11 nuclear units, 27 coal-fired units, and 23 LNG-combined units. As currently contemplated in accordance with the sixth Basic Plan and subject to any further plan to be announced by the Government in relation to the construction of additional nuclear generation capacity which was not included in the Sixth Plan, the total capacity of all generating facilities at the end of 2027 is expected to be 130,853 megawatts, with nuclear power plants accounting for 27.4% of the total capacity. Coal-fired plants, LNG combined plants, oil-fired plants and hydroelectric and other plants are expected to account for 34.7%, 24.3%, 0.9% and 12.7%, of the total capacity, respectively. The table below sets forth the currently estimated installed capacity for new or expanded generation units to be completed by our generation subsidiaries according to the sixth Basic Plan in each year from 2013 to 2015.


Year	Number of Units		Type of Units	Total Installed Capacity
				(Megawatts)
2013		2	Nuclear power		2,400
		4	LNG-combined		2,175
2014		1	Nuclear power		1,400
		2	Coal-fired		1,540
		8	LNG-combined		6,066
2015		2	Coal-fired		2,020
		4	LNG-combined		3,132

From 2016 and 2027, our generation subsidiaries currently plan to complete eight nuclear units with an aggregate installed capacity of 11,400 megawatts (subject to any further plan to be announced by the Government in