Edgar Filing: KOREA ELECTRIC POWER CORP

Form 20-F

As filed with the Securities and Exchange Commission on April 30, 2014

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, 2013

¨	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)*

512 YEONGDONGDAERO, GANGNAM-GU, SEOUL 135-791, KOREA

(Address of principal executive offices)

Younseung Lee, +822 3456 4217, winstraight@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 annual 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			22
	Item 4A.	History and Development of the Company		22
	Item 4B.	Business Overview		23
	Item 4C.	Organizational Structure		74
	Item 4D.	Property, Plant and Equipment		77
ITEM 4A.	UNRESOLVED STAFF COMMENTS			78
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS			78
	Item 5A.	Operating Results		78
	Item 5B.	Liquidity and Capital Resources		93
	Item 5C.	Research and Development, Patents and Licenses, etc.		97
	Item 5D.	Trend Information		99
	Item 5E.	Off-Balance Sheet Arrangements		99
	Item 5F.	Tabular Disclosure of Contractual Obligations		99
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES			104
	Item 6A.	Directors and Senior Management		104
	Item 6B.	Compensation		108
	Item 6C.	Board Practices		108
	Item 6D.	Employees		109
	Item 6E.	Share Ownership		109
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS			110
	Item 7A.	Major Shareholders		110
	Item 7B.	Related Party Transactions		110
	Item 7C.	Interests of Experts and Counsel		111
ITEM 8.	FINANCIAL INFORMATION			111
	Item 8A.	Consolidated Statements and Other Financial Information		111
	Item 8B.	Significant Changes		112
ITEM 9.	THE OFFER AND LISTING			112
	Item 9A.	Offer and Listing Details		112
	Item 9B.	Plan of Distribution		114
	Item 9C.	Markets		114
	Item 9D.	Selling Shareholders		117
	Item 9E.	Dilution		117
	Item 9F.	Expenses of the Issue		117
ITEM 10.	ADDITIONAL INFORMATION			117
	Item 10A.	Share Capital		117
	Item 10B.	Memorandum and Articles of Incorporation		117
	Item 10C.	Material Contracts		124
	Item 10D.	Exchange Controls		124
	Item 10E.	Taxation		130
	Item 10F.	Dividends and Paying Agents		140
	Item 10G.	Statements by Experts		140
	Item 10H.	Documents on Display		140
	Item 10I.	Subsidiary Information		141


			Page
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			141
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES			147
	Item 12A.	Debt Securities		147
	Item 12B.	Warrants and Rights		147
	Item 12C.	Other Securities		147
	Item 12D.	American Depositary Shares		148
PART II				150
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES			150
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS			150
ITEM 15.	CONTROLS AND PROCEDURES			150
ITEM 16.	[RESERVED]			151
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT			151
ITEM 16B.	CODE OF ETHICS			151
ITEM 16C.	PRINCIPAL AUDITOR FEES AND SERVICES			151
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE			152
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS			152
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANTS			152
ITEM 16G.	CORPORATE GOVERNANCE			153
ITEM 16H.	MINE SAFETY DISCLOSURE			158
PART III				159
ITEM 17.	FINANCIAL STATEMENTS			159
ITEM 18.	FINANCIAL STATEMENTS			159
ITEM 19.	EXHIBITS			159

CERTAIN DEFINED TERMS AND CONVENTIONS

All references to “Korea” or the “Republic” in this annual report on Form 20-F, or this annual report, are references to the Republic of Korea. All references to the “Government” in this annual report are references to the government of the Republic. All references to “we,” “us,” “our,” “ours,” the “Company” or “KEPCO” in this annual report are references to Korea Electric Power Corporation and, as the context may require, its subsidiaries, and the possessive thereof, as applicable. All references to “the Ministry of Trade, Industry and Energy” and “the Ministry of Strategy and Finance” include the respective predecessors thereof. All references to “tons” are to metric tons, equal to 1,000 kilograms, or 2,204.6 pounds. Any discrepancies in any table between totals and the sums of the amounts listed are due to rounding. All references to “IFRS” in this annual report are references to the International Financial Reporting Standards as issued by the International Accounting Standard Board. Unless otherwise stated, all of our financial information presented in this annual report has been prepared on a consolidated basis and in accordance with IFRS.

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

•

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

This annual report discloses, under the caption Item 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, 2012 and 2013 have been derived from our audited consolidated financial statements which have been prepared in accordance with IFRS.

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

Consolidated Statement of Comprehensive Income (Loss) Data


	2010			2011			2012			2013
	(in billions of Won and millions of US$, except per share data)⁽¹⁾
Sales	￦	39,507		￦	43,175		￦	49,121		￦	53,713		$	50,898
Gross Profit		3,319			450			661			3,117			2,954
Selling and administrative expenses		1,645			1,752			1,780			1,923			1,822
Other gains (losses)		118			166			(1,782	)		129			122
Operating profit (loss)		2,260			(685	)		(2,300	)		1,948			1,846
Finance income (expense), net		(1,967	)		(1,911	)		(1,940	)		(2,302	)		(2,181	)
Income (loss) before income taxes		370			(2,473	)		(4,063	)		(396	)		(376	)
Income tax (expense) benefit		(439	)		(820	)		985			571			541
Profit (loss) for the period		(69	)		(3,293	)		(3,078	)		174			165
Other comprehensive income (loss)		(43	)		(262	)		(322	)		186			176
Total comprehensive income (loss)		(112	)		(3,555	)		(3,400	)		360			341
Profit (loss) attributable to:
Owners of the Company		(120	)		(3,370	)		(3,167	)		60			57
Non-controlling interests		51			77			89			114			108
Total comprehensive income (loss) attributable to:
Owners of the Company		(152	)		(3,628	)		(3,448	)		245			233
Non-controlling interests		40			73			48			115			109
Earnings (loss) per share
Basic⁽²⁾		(193	)		(5,411	)		(5,083	)		96			91
Earnings (loss) per ADS
Basic⁽²⁾		(97	)		(2,706	)		(2,542	)		48			46
Dividends per share		—			—			—			90			85

Consolidated Statements of Financial Position Data


	As of December 31,
	2010			2011			2012			2013
	(in billions of Won and millions of US$, except share and per share data)⁽¹⁾
Net working capital deficit⁽³⁾	￦	(916	)	￦	(3,973	)	￦	(4,884	)	￦	(4,945	)	$	(4,686	)
Property, plant and equipment, net		107,406			112,385			122,376			129,638			122,844
Total assets		129,518			136,468			146,153			155,527			147,377
Total shareholders’ equity		57,277			53,804			51,064			51,451			48,755
Equity attributable to owners of the Company		56,818			53,270			49,889			50,260			47,626
Non-controlling interests		459			534			1,175			1,191			1,129
Share capital		3,208			3,210			3,210			3,210			3,042
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			641,964,077
Long-term debt (excluding current portion)		32,848			39,198			45,525			52,801			50,034
Other long term liabilities		25,321			25,725			30,747			31,062			29,434

Notes:

(1)	The financial information denominated in Won as of and for the year ended December 31, 2013 has been translated into U.S. dollars at the exchange rate of Won 1,055.3 to US$1.00, which was the Noon Buying Rate as of December 31, 2013.

(2)

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. Dilutive loss per share is not presented as such amount was anti-dilutive for the periods indicated.

(3)	Net working capital is defined as current assets minus current liabilities. For the periods indicated, current liabilities exceeded current assets, which gave rise to working capital deficit.

Currency Translations and Exchange Rates

In this annual 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 1,055.3 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, 2013, which rates are available on the H.10 statistical release of the Federal Reserve Board. On April 11, 2014, the Noon Buying Rate was Won 1,035.4 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 annual 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 annual report could have been or could be converted into U.S. dollars or Won, as the case may be, at any particular rate or at all.

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)
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
2013		1,055.3		1,094.7		1,161.3		1,050.1
October		1,060.8		1,065.9		1,075.5		1,057.5
November		1,057.8		1,061.6		1,072.7		1,054.8
December		1,055.3		1,055.6		1,061.4		1,050.1
2014 (through April 11)		1,035.4		1,067.1		1,084.2		1,035.4
January		1,080.4		1,067.1		1,083.7		1,050.3
February		1,066.0		1,071.3		1,084.2		1,062.1
March		1,064.7		1,070.5		1,079.6		1,064.1
April (through April 11)		1,035.4		1,050.1		1,058.3		1,035.4

Source: Federal Reserve Board.

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 45.1% and 47.8% of our sales and cost of sales, respectively, in 2013. Our generation subsidiaries purchase substantially all of the fuel that they use (except for anthracite coal) from suppliers outside Korea at prices determined in part by prevailing market prices in currencies other than Won. For example, most of the bituminous coal requirements (which accounted for approximately 43.0% of our entire fuel requirements in 2013 in terms of electricity output) are imported principally from Indonesia and Australia and, to a lesser extent, the United States and Russia, which accounted for approximately 41.6%, 38.2%, 9.5% and 9.5%, respectively, of the annual bituminous coal requirements of our generation subsidiaries in 2013. Approximately 89.0% of the bituminous coal requirements of our generation subsidiaries in 2013 were purchased under long-term contracts and the remaining 11.0% from the spot market. Pursuant to the terms of our long-term supply contracts, prices are adjusted periodically based on prevailing market conditions. In addition, our generation subsidiaries purchase a significant portion of their fuel requirements under contracts with limited duration. See Item 4B. “Business Overview—Fuel.”

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 costs. In recent years, however, the prices of our main fuel types, namely, bituminous coal, oil and liquefied natural gas, or LNG have generally declined in tandem with their international market prices. For example, the average “free on board” Newcastle coal 6300 GAR spot price index published by Platts declined from US$96.2 per ton in 2012 to US$85.1 per ton in 2013 and US$73.8 per ton as of April 11, 2014. 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 declined from US$108.9 per barrel in 2012 to US$105.4 per barrel in 2013 and to US$104.1 per barrel as of April 11, 2014. However, we cannot assure you that the fuel prices will remain at similarly low levels or will not significantly increase in the remainder of 2014 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. If fuel prices increase rapidly and substantially 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 (as was the case from 2008 to 2012 when we suffered consecutive net losses and, from time to time, operating 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. 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 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 also has 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. 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 other factors 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 5A. “Operating and Financial Review and Prospects—Critical Accounting Policy—Correction of Accounting for Fuel Cost Pass-through Adjustment.”

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 thermal generation companies, in each case, to be wholly owned by us. In 2002, the Government introduced a plan to privatize one of our five thermal 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 have a greater degree of autonomy with respect to management, financial accounting and performance evaluation while having a common focus on increasing profitability.

In August 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 thermal 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.

Other than as set forth above, we are not aware of any specific plans by the Government to resume the implementation of the Restructuring Plan or otherwise change the current structure of the electric power industry or the operations of us or our generation subsidiaries 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 conditions. 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 revised and announced 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. In addition, while the Sixth Basic Plan did not contemplate the construction of additional nuclear plants in light of the heightened public concern over nuclear safety following the nuclear power plant meltdown in Japan in March 2011, there is no assurance that the Government will not implement a supplemental plan for the construction of additional nuclear plants in the future, which may increase the amount of our required capital expenditure.

In addition, on January 13, 2014, the Ministry of Trade, Industry and Energy adopted the Second Basic National Energy Plan following consultations with representatives from civic groups, the power industry and academia. The Second Basic National Energy Plan, which is a comprehensive plan that covers the entire spectrum of energy industries in Korea, will cover the period from 2013 to 2035 (compared to 2008 to 2030 under the First Basic National Energy Plan) and focuses on the following six key tasks: (i) shifting the focus of energy policy to demand management with a goal of reducing electricity demand by 15% by 2035, (ii) establishing a geographically decentralized electricity generation system so as to reduce transmission losses with a goal of supplying at least 15% of total electricity through such system by 2035, (iii) applying latest greenhouse gas emission reduction technologies to newly constructed generation units in order to further promote safety and environmental friendliness, (iv) strengthening exploration and procurement capabilities to enhance Korea’s energy security and to ensure stable supply of energy and increasing the portion of electricity supplied from renewable sources to 11% by 2035, (v) reinforcing the system for stable supply of conventional energy, such as oil and gas, and (vi) introducing in 2015 an energy voucher system in lieu of a tariff discount system for the benefit of consumers in the low income group. In addition, the Second Basic National Energy Plan contemplates revising the target level of electricity generated by nuclear sources as a percentage of total electricity generated to 29%, compared to 41% under the First Basic National Energy Plan announced in 2008.

We cannot assure that the Sixth Basic Plan, the Second Basic National Energy Plan or the respective plans to be subsequently adopted will successfully achieve their intended goals, the foremost of which is to ensure, through carefully calibrated capacity expansion and other means, balanced overall electricity supply and demand in Korea at affordable costs to the end users while promoting efficiency and environmental friendliness in the consumption and production of electricity. 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 or if these plans otherwise fail to meet their intended goals or have other unintended consequences, 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, among others, which may have a material adverse effect on our results of operations, financial condition and cash flows.

From time to time, we may experience temporary power shortages or circumstances bordering on power shortages due to factors beyond our control, such as extreme weather conditions. 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 for several hours to prevent 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/or make acquisitions and investments related to overseas natural resources. In 2011, 2012 and 2013, our capital expenditures for construction of generation, transmission and distribution facilities amounted to Won 11,984 billion, Won 12,751 billion and Won 15,831 billion, respectively, and our budgeted capital expenditures for 2014, 2015 and 2016 amount to Won 19,898 billion, Won 18,479 billion and Won 16,339 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.

Recently, in light of the general policy guideline of the Government for public enterprises (including us and our generation subsidiaries) in general to reduce their respective overall debt levels, including by way of disposing of non-core assets, we are currently evaluating ways to reduce our debt levels. We cannot assure whether we or our generation subsidiaries will be able to successfully reduce debt burdens to a level contemplated by the Government or to a level that would be optimal for our capital structure. If we or our generation subsidiaries fail to reduce debt burdens to a level contemplated by the Government or the measures taken by us or our generation subsidiaries to reduce debt levels have unintended adverse consequences, such developments may have an adverse effect on our business, results of operation 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 difficulties in the global financial markets. 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, 2013, approximately 20.9% 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 U.S. dollars. In addition, even if we make payments in Won for certain fuel materials and equipment, some of these fuel materials may originate from other countries and their prices may be affected accordingly by the exchange rates between the Won and foreign currencies, especially the U.S. dollar. Since the substantial majority of our revenues are denominated in Won, we must generally obtain foreign currencies through foreign currency-denominated financings or from foreign currency exchange markets to make such purchases or service such debt. As a result, any significant depreciation of Won against the U.S. dollar or other major foreign currencies will have a material adverse effect on our profitability and results of operations.

We may not be successful in implementing new business strategies.

As part of our overall business strategy, we plan to (i) strengthen reliability of our domestic operations by enhancing efficiency of our generation, transmission and distribution networks, (ii) expand overseas business by selectively exploring renewable energy, smart transmission and distribution facilities and fuel procurement projects in the overseas markets along with our traditional businesses in the generation sector, (iii) create a platform for new business growth opportunities by gaining “first mover” advantages in new businesses through technological development, and (iv) fulfill social responsibilities as an electricity provider by seeking a balance between our public policy mandate and profitability.

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

•

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

•

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

•

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

•

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

•

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

As part of our business strategy, we may also seek, evaluate or engage in potential acquisitions, 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 businesses. As a result of such review, we may decide to exit from or to reduce the resources that we allocate to new or existing ventures in the future. There is a risk that these ventures may not achieve profitability or operational efficiencies to the extent originally anticipated, and we may fail to recover investments or expenditures that we have already made. Any of the foregoing may have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.

We plan to pursue 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 may expand, on a selective basis, our overseas operations in the future. In particular, we may 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 construction and operation of conventional thermal generation units) to include 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:

•

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

•

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

•

difficulties in enforcing creditors’ rights in foreign jurisdictions;

•

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

•

difficulties in establishing, staffing and managing foreign operations;

•

differing labor regulations;

•

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

•

lack of familiarity with local markets and competitive conditions;

•

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

•

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.

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

As of December 31, 2013, we and our generation subsidiaries owned approximately 81.5% 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.

In particular, we compete with independent power producers with respect to electricity generation. The independent power generators accounted for 13.2% of total power generation in 2013 and 18.5% of total generation capacity as of December 31, 2013. As of December 31, 2013, there were 10 independent power generators in Korea, excluding renewable energy producers. Prior to December 2010, private enterprises had not been permitted to own and operate coal-fired power plants in Korea. However, the Fifth Basic Plan announced in December 2010 included for the first time a plan for independent power producers to own and operate coal-fired power plants, namely four generation units with aggregate capacity of 2,290 megawatts for completion in 2016. In addition, in connection with the Sixth Basic Plan announced in February 2013, the Ministry of Trade, Industry and Energy accepted additional applications from independent power producers for construction of coal-fired power plants. 15 independent power producers applied for construction of a total of 40 additional coal-fired generation units with aggregate generation capacity of 37,100 megawatts, of which the Government approved applications for the construction of six generation units with aggregate generation capacity of 6,000 megawatts. The Government also approved applications from independent power producers for construction of two additional generation units with aggregate generation capacity of 2,000 megawatts to prepare for the contingency of failed or delayed construction of the foregoing 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, under the Community Energy System adopted by the Government in 2004, a minimal amount of electricity is supplied directly to consumers on a localized basis by independent power producers 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 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 geographically decentralize electricity supply and thereby reduce transmission losses and improve the efficiency of energy use. These entities do not supply electricity on a national level but are licensed to supply electricity to limited geographic areas. As of March 31, 2014, the aggregate generation capacity of suppliers participating in the Community Energy System represented less than 1% of that of our generation subsidiaries in the aggregate. Accordingly, we currently do not expect the Community Energy System to be widely adopted, especially in light of the significant level of capital expenditure required for such direct supply. However, if the Community Energy System is widely adopted, it may erode our currently dominant market position in the generation and distribution of electricity in Korea, and may have a material adverse effect on our business, results of operations and financial condition.

Labor unrest may adversely affect our operations.

We and each of our generation subsidiaries have separate labor unions. As of December 31, 2013, approximately 69.7% of our and our generation subsidiaries’ employees in the aggregate were members of these labor unions. Since a six-week labor strike in 2002 by union members of our generation subsidiaries in response to a proposed privatization of one of our generation subsidiaries, there has been no material labor dispute. However, we cannot assure you that there will not be a major labor strike or other material disruptions of operations by the labor unions of us and our generation subsidiaries if the Government resumes privatization or other restructuring initiatives or for other reasons, which may adversely affect our business and results of operations.

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 27% of electricity generated in Korea in 2013. Due to significantly lower unit fuel costs compared to those for thermal power plants, our nuclear power plants are generally operated at full capacity with only routine shutdowns for fuel replacement and maintenance, with limited exceptions.

From time to time, our nuclear generation units may experience unexpected shutdowns. For example, on February 9, 2012, Kori-1 experienced a station blackout for approximately 12 minutes during a scheduled maintenance overhaul. This incident was reported to the Nuclear Safety and Security Commission on March 12, 2012, leading to a further safety evaluation, after which Kori-1 resumed operations in August 2012. 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 and Security Commission (“NSSC”) 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.

Recent findings of falsified testing results and bribery and the subsequent prolonged shutdowns of certain of our nuclear generation units may adversely hurt our reputation, business, results of operations and financial condition.

In May 2013, the Nuclear Safety and Security Commission (“NSSC”) announced that it discovered certain control cables used in three of our then-operating nuclear generation units, Shin-Kori #1 and #2, Shin-Wolsung #1, and three units under construction, Shin-Kori #3 and #4 and Shin-Wolsung #2, had been supplied based on

forged testing results. These parts were custom-made and have critical functions in the case of emergency for activating certain safety signals. The forgery was made by a testing facility in charge of performance evaluation of the parts before delivery.

Upon such discovery, KHNP immediately began internal investigation of related certification documents and reported to the Prosecutor’s Office all testing facilities and suppliers suspected of forgery for further investigation. Currently, the NSSC, with the full cooperation of KHNP, is conducting a full scale investigation into the appropriateness of all testing results at all of our nuclear generation units. In addition, the Prosecutor’s Office has been conducting extensive investigation on all parties suspected of having been involved in the forgery and has brought several criminal and civil charges, including against several of KHNP’s former and current officers and employees. In addition, one of KHNP’s former CEOs and several former and current officers and employees of KHNP were arrested on separate bribery charges brought by the Prosecutor’s Office as part of a wider investigation into the nuclear power industry in general, and in June 2013, KHNP’s then CEO was dismissed by the Government for failure of oversight. KHNP has been fully cooperating with the authorities on these investigations and have promptly taken all appropriate disciplinary actions against KHNP’s employees allegedly involved in such incidents. KHNP has also immediately suspended all existing relationships with all of the entities alleged to have participated in any related illegal or improper activities. KHNP as an entity has not been subject to any criminal charges or sanctions. The investigations by the NSSC and the Prosecutor’s Office are still ongoing.

Immediately following the discovery of the forgery incident, Shin-Kori #1 and #2 and Shin-Wolsung #1 were shut down in May 2013 for further safety inspections. Shin-Kori #3 and #4 and Shin-Wolsung #2, where such parts were also used, currently remain under construction. Shin-Kori #1 and #2 and Shin-Wolsung #1 resumed operations in January 2014 following parts replacement and the NSSC approval. While we expect that the construction of the other units will proceed as originally planned, we cannot assure you that any or all of these units will complete construction as currently scheduled. As a result of the shutdown, we incurred additional operating expenses, including as a result of having had to purchase electricity generated from more expensive fuel sources while the aforementioned nuclear plants were suspended from operation.

The foregoing incidents follow a discovery in November 2012 that certain machinery parts, such as fuses and switches, used in KHNP’s nuclear-fuel generation units Hanbit #5 and Hanbit #6 had been supplied using forged quality certification documents. These parts were generic parts that were not essential to the function or safety of our nuclear generation, and the forgery was made by the suppliers of these parts. Following such discovery, relationships with these suppliers were immediately terminated and these units were shut down in November 2012 pending a Government investigation into the extent of the forgeries and the replacement of the affected parts, and the NSSC performed inspections on all generic supply parts at all of KHNP’s nuclear-fuel generation units. Upon completion of such investigation and inspections, Hanbit #5 and Hanbit #6 resumed operation in December 2012 and January 2013, respectively.

These incidents have had a material adverse effect, and may have a further material adverse effect, on our reputation, business, results of operation, financial condition as well as the general acceptance of nuclear power, especially if, as a result of these incidents or otherwise, there are findings of other criminal or other illegal or improper activities or if there are additional shutdowns that lead to greater social and political concerns over nuclear safety to the effect of impeding with our normal operation of nuclear generation units. See “Item 4B. Business—Recent Developments—Recent incidents involving certain of our nuclear units.”

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

From time to time, we encounter social and political opposition against construction and operation of our generation facilities (particularly nuclear units) and, to a lesser extent, our transmission and distribution facilities.

As a recent example, we are currently facing intense opposition from local residents and civic groups to the construction of transmission lines in the Milyang area despite having offered various compensatory and other support programs. Such opposition has delayed the schedule for completion of this project. Although we and the Government have undertaken various community programs to address concerns of residents in areas near our facilities, civic and community opposition could result in delayed construction or relocation of our planned facilities, which could have a material adverse impact on our business and results of 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 (“RPS”) program, under which each generation subsidiary is required to generate a specified percentage of total electricity to be generated by such generation subsidiary in a given year in the form of renewable energy, with the target percentage being 2.0% in 2012, 2.5% in 2013 and incrementally increasing to 10.0% by 2022. Fines are to be levied on any subsidiary that fails to do so in the prescribed timeline. In 2012, while one of our generation subsidiaries met 100% of its target, five others were unsuccessful to do so. Our six generation subsidiaries met, on average, 90.8% of the target for 2012 and accordingly were fined an aggregate amount of Won 23.7 billion. Compliance by our generation subsidiaries of the 2013 target is currently under evaluation, and if we are found to have failed to meet the target for 2013 or for subsequent years, our generation subsidiaries may become subject to additional fines or other penalties. There is no assurance that such fine or other penalty will not be substantial, and if substantial, such fine or other penalty may have a material adverse effect on our business, results of operations or financial condition. The budgeted amount of capital expenditure for implementation of the RPS as currently planned for the period from 2013 to 2022 is approximately Won 13.7 trillion. We expect that such additional capital expenditure to 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. See also Item 4B. “Business Overview—Renewable Energy.”

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.”

Newly adopted coal consumption tax may have a material adverse effect on our business, operations and profitability.

consumption tax will apply to bituminous coal, which previously was not subject to consumption tax unlike other fuel types such as LNG or bunker oil. The base tax rate (which is subject to certain adjustments) will be Won 24 per kilogram for bituminous coal; however, due to concerns on the potential adverse effect on industrial activities, the applicable tax rate will be Won 19 per kilogram for bituminous coal with net heat generation of 5,000 kilo calories or more per kilogram, and Won 17 per kilogram for bituminous coal with net heat generation of less than 5,000 kilo calories per kilogram. In contrast, the applicable tax rate for LNG will be reduced from Won 60 per kilogram to Won 42 per kilogram. Since bituminous coal currently represents the largest fuel type for electricity generation, accounting for approximately 43.0% of our entire fuel requirements in 2013 in terms of electricity output, we expect the newly adopted consumption tax thereon will result in an increase of our overall fuel costs, notwithstanding the decrease in the consumption tax rate for LNG, which accounted for approximately 19.7% of our entire fuel requirements in 2013 in terms of electricity output. While we expect that such additional fuel costs will be covered by a corresponding increase in electricity tariff, there is no assurance that the Government will in fact raise electricity tariff to a level sufficient to fully cover such additional costs in a timely manner or at all, and if the Government does not do so, the increase in our overall fuel costs arising from the newly adopted coal consumption tax will adversely affect our results of operation and financial condition.

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 thermal 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 thermal 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% of our issued capital stock. As of February 17, 2014 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.

Following from the recent decision of the Supreme Court of Korea, we may be exposed to potential claims made by current or previous employees for unpaid wages for the past three years under the expanded scope of ordinary wages and become subject to additional labor costs arising from the broader interpretation of ordinary wages under such decision.

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

In December 2013, the Supreme Court of Korea ruled that regular bonuses fall under the category of ordinary wages on the condition that those bonuses are paid regularly and uniformly, and that any agreement which excludes such regular bonuses from ordinary wage is invalid. The Supreme Court further ruled that in spite of invalidity of such agreements, employees shall not retroactively claim additional wages incurred due to such court decision, in case that such claims bring to employees unexpected benefits which substantially exceeds the wage level agreed by employers and employees and cause an unpredicted increase in expenditures for their company, which would lead the company to material managerial difficulty or would threat to the existence of the company. In that case, the claim is not acceptable since it is unjust and is in breach of the principle of good faith. Prior to such Supreme Court ruling, we determined wages in accordance with budget instructions from the Ministry of Strategy and Finance, which excluded bonuses from ordinary wages and which was determined with the consent of the relevant labor unions.

Following the Supreme Court decision, the Korea Power Plant Industry Union and others filed lawsuits in an aggregate amount of Won 44.6 billion against our six generation subsidiaries, based on claims that ordinary wage was paid without including certain items that should have been included as ordinary wage. Our management currently believes that we are not presently obligated to make any payments in relation to this matter and we accordingly had not made any provision in relation thereto as of December 31, 2013 since it is unclear how the Supreme Court ruling should be applied and it is not possible to reasonably estimate the amount of potential loss since such amount will depend on the nature of the future agreement between management and relevant labor unions and/or the outcome of the foregoing or related lawsuits. However, should the outcome of these or other lawsuits be finally determined against us, the resulting compensation we will be required to pay and any related increase in labor costs will have an adverse effect on our results of operation and cash flows.

Risks Relating to Korea and the Global Economy

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

We are incorporated in Korea, where most of our assets are located and most of our income is generated. As a result, we are subject to political, economic, legal and regulatory risks specific to Korea, and our business, results of 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.

While in the aftermath of the global financial crisis that started in the second half of 2008 there have been mixed signs of recovery for the global and Korean economy, substantial uncertainties remain in the form of anticipated tightening of the U.S. monetary policy, continued fiscal and financial challenges for the European, U.S. and global economies, fluctuations in oil and commodity prices, signs of cooling of the Chinese economy and a rise of military and political tension in the Crimean peninsula and former members of the Soviet Union. Accordingly, the overall prospects for the Korean and global economy in 2014 and beyond remain uncertain. While our aggregate financial exposure to the European countries that have been significantly 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. In addition, due to the ongoing volatility in the global financial markets, the value of the Won relative to the U.S. dollar has also fluctuated significantly in recent years, which in turn also may adversely affect our financial condition and results of operation.

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:

•

monetary tightening by the U.S. government known as “tapering,” further deterioration of the fiscal and financial difficulties in Europe, the slowdowns of the Chinese economy, as well as rising military and political tension in the Crimean peninsula and former members of the Soviet Union, which could have adverse effects on the global, and in turn Korean credit and financial markets as well as the exchange rates of Won to other major foreign currencies, particularly U.S. dollar;

•

increases in 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, stock market prices and inflows and outflows of foreign capital, either directly, into the stock markets, through derivatives or otherwise;

•

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

•

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;

•

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);

•

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

•

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

•

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;

•

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;

•

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;

•

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;

•

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

•

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

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.

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-un was named North Korea’s Supreme Commander of the Armed Forces. Whether Kim Jong-un 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. If the consolidation of power by Kim Jong-un is not successful or there exist any material conflicts among different political factions, there may be significant uncertainty regarding the policies, actions and initiatives that North Korea might pursue in the future. For example, in December 2013, Jang Sung-Taek, husband to Kim Jong-un’s aunt, who was widely speculated to be the second in command, was executed on charges of sedition, among others. Although the implications of such developments remain uncertain, it may cause further political and social instability in North Korea and/or adoption of more hostile policies that could enhance friction with Korea and the rest of the world.

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

North Korea has recently undertaken other hostile actions. For example, in March 2010, a Korean naval vessel was destroyed by an underwater explosion, killing many of the crewmen on board. The Government formally accused North Korea of causing the sinking, while North Korea denied responsibility. Moreover, in November 2010, North Korea fired more than one hundred artillery shells that hit Korea’s Yeonpyeong Island near the Northern Limit Line, which acts as the de facto maritime boundary between Korea and North Korea on the west coast of the Korean peninsula, causing casualties and significant property damage. The Government

condemned North Korea for the attack and vowed stern retaliation should there be further provocation. In March 2013, North Korea declared the 1953 armistice invalid, stated that it had entered “a state of war” with Korea, and put its artillery at the highest level of combat readiness to protest the Korea-United States allies’ military drills and additional sanctions imposed on North Korea for its missile and nuclear tests.

On April 3, 2013, North Korea blocked South Koreans from entering the Kaesong Industrial Complex, an economic cooperation zone within North Korea and on April 26, 2013 South Korea decided to withdraw its workers from the complex. In September 2013, however, Korea and North Korea reached an agreement and resumed operation of the Kaesong Industrial Complex, and have since made efforts to improve the business environment of the complex, including by building radio frequency identification data transfer systems and launching internet service, among others. In February 2014, the U.S. Congressional Research Service reported that the Government’s approach towards the expansion and internationalization of the Kaesong Industrial Complex could conflict with U.S. legislative efforts to expand its sanctions on North Korea, and there is no assurance that the Government will not reverse or reduce its such efforts at detente.

There can be no assurance that the level of tension on the Korean peninsula will not escalate in the future. Furthermore, North Korea’s economy also faces severe challenges, including severe inflation and food shortages, which may further aggravate social and political tensions within North Korea. In addition, reunification of Korea and North Korea could occur in the future, which would entail significant economic expenditure and commitment by Korea. Any further increase in economic or political difficulties within North Korea or escalation of military tension between Korea and North Korea could have a material adverse effect on the Company’s business, financial condition and results of operations as well as 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% ceiling on acquisitions of shares by foreigners in the aggregate. The Financial Services Commission may impose other restrictions as it deems necessary for the protection of investors and the stabilization of the Korean securities and derivatives market.

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

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

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

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

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 512 Yeongdongdaero, Gangnam-gu, Seoul, Korea, and our telephone number is 82-2-3456-4217. 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, Parker Plaza, 400 Kelby Street, Fort Lee, NJ 07024.

The Korean electric utility industry traces its origin to the establishment of the first electric utility company in Korea in 1898. On July 1, 1961, the industry was reorganized by the merger of Korea Electric Power Company, Seoul Electric Company and South Korea Electric Company, which resulted in the formation of Korea Electric Company. From 1976 to 1981, the Government acquired the private minority shareholdings in Korea Electric Company. After the Government acquired all the remaining shares of Korea Electric Company, Korea Electric Company was dissolved, and we were incorporated in 1981 and assumed the assets and liabilities of Korea Electric Company. We ceased to be wholly owned by the Government in 1989 when the Government sold 21% of our common stock. As of February 17, 2014, 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% 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 the substantial majority of electricity produced in Korea. As of December 31, 2013, we and our generation subsidiaries owned approximately 81.5% of the total electricity generation capacity in Korea (excluding plants generating electricity primarily for private or emergency use). In 2013, we sold to our customers approximately 474,849 gigawatt-hours of electricity. We purchase electricity principally from our generation subsidiaries and to a lesser extent from independent power producers. Of the 479,287 gigawatt-hours of electricity we purchased in 2013, 28.8% was generated by KHNP, our wholly-owned nuclear and hydroelectric power generation subsidiary, 60.6% was generated by our wholly-owned five thermal generation subsidiaries and 10.6% was generated by independent power producers. Our five thermal 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 2013, we had sales of Won 53,713 billion and net profit of Won 174 billion, compared to sales of Won 49,121 billion and net loss of Won 3,078 billion in 2012.

Our revenues are closely tied to demand for electricity in Korea. Demand for electricity in Korea increased at a compounded average growth rate of 4.3% per annum from 2009 to 2013, compared to the real gross domestic product, or GDP, which increased at a compounded average growth rate of 3.2% during the same period, according to the Bank of Korea. The GDP growth rate was 3.0% during 2013 while demand for electricity in Korea increased by 1.8% during 2013.

Strategy

In October 2013, we announced our corporate strategy titled “Global Top Green & Smart Energy Pioneer.” Under this strategy, we seek to become a leading global energy enterprise through enhanced global competitiveness 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. In addition, we are in the process of integrating a “creating shared value” platform to our business model and operating strategy so as to enhance our social contributions as well as financial profitability in the form of creating new business opportunities while promoting energy welfare for our consumers.

•

Strengthen reliability of our domestic operations. Our primary strategies in this connection are to enhance efficiency of our electricity generation, transmission and distribution networks and acceptability of the construction and operation of our related facilities. Toward this end, we will strategically focus on ensuring stable supply of electricity, making our electricity networks “smarter”

and more intelligent, creating customer-oriented marketing solutions, hiring outside agencies to assist with site selection for our facilities and improving the compensation system in relation to our facilities. We also aim to strengthen our marketing capabilities in anticipation of increasing competition, as well as bolster programs designed to encourage efficient energy use. We believe these measures will be instrumental to reinforcing our dominance in the Korean electricity market.

•

Expand overseas business. Our primary strategies in this connection are to develop tailored expansion plans specific to the target region, increase the level of our control over the proposed projects and procure secure supply of fuels. In this connection, we plan to expand our thermal and nuclear power projects as well as selectively explore renewable energy, smart transmission and distribution facilities and fuel procurement projects in the overseas markets.

•

Create a platform for new business growth opportunities. Our primary objectives in this connection are to gain “first mover” advantages in new businesses through technological development and to create opportunities for synergy through formation of an integrated energy network connecting Northeast Asia. Towards these goals, we plan to focus on development of high value-added electricity-related technology, commercialization of our strategic projects and establishment of “super grids” in Northeast Asia.

•

Fulfill social responsibilities as an electricity provider. In this connection, we will continue to seek a balance between our public policy mandate and profitability and develop sustainable products, including through leadership in low-carbon clean energy business, development of a sustainable energy business model and actualization of results-oriented social responsibility as a global corporate citizen.

Recent Developments

Increase in Electricity Tariff Rates

Effective November 21, 2013, the Government increased the electricity rates that we charge to the end-users by an average of 5.4% as further set forth in the following table:

Type of
Usage

Residential

Commercial

Industrial

Educational

Agricultural

Street
Lighting

Overnight
Usage

Less than
300 kW

300 kW or
more

Average

Less than
300 kW

300 kW or
more

Average

% increase

2.7

5.2

6.4

5.8

6.4

—

3.0

5.4

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 increases will be sufficient to fully offset the adverse impact on our results of operations from the current or future movements in fuel costs.

Proposed Second Basic National Energy Plan

On January 13, 2014, the Ministry of Trade, Industry and Energy adopted the Second Basic National Energy Plan following consultations with representatives from civic groups, the power industry and academia. The Second Basic National Energy Plan, which is a comprehensive plan that covers the entire spectrum of energy industries in Korea, will cover the period from 2013 to 2035 (compared to 2008 to 2030 under the First Basic National Energy Plan) and focuses on the following six key tasks: (i) shifting the focus of energy policy to demand management with a goal of reducing electricity demand by 15% by 2035, (ii) establishing a geographically decentralized electricity generation system so as to reduce transmission losses with a goal of

supplying at least 15% of total electricity through such system by 2035, (iii) applying latest greenhouse gas emission reduction technologies to newly constructed generation units in order to further promote safety and environmental friendliness, (iv) strengthening exploration and procurement capabilities to enhance Korea’s energy security and to ensure stable supply of energy and increasing the portion of electricity supplied from renewable sources to 11% by 2035, (v) reinforcing the system for stable supply of conventional energy, such as oil and gas, and (vi) introducing in 2015 an energy voucher system in lieu of a tariff discount system for the benefit of consumers in the low income group. In addition, the Second Basic National Energy Plan contemplates revising the target level of electricity generated by nuclear sources as a percentage of total electricity generated to 29%, compared to 41% under the First Basic National Energy Plan announced in 2008.

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

In connection with the Sixth Basic Plan announced in February 2013, the Ministry of Trade, Industry and Energy accepted additional applications from independent power producers for construction of coal-fired power plants. The Fifth Basic Plan announced in December 2010 included for the first time a plan for independent power producers to own and operate coal-fired power plants, namely two such generation units with aggregate capacity of 2,000 megawatts for completion in 2016. Prior to December 2010, private enterprises had not been permitted to own and operate coal-fired power plants in Korea. For the Sixth Basic Plan, 15 independent power producers applied for construction of a total of 40 additional coal-fired generation units with aggregate generation capacity of 37,100 megawatts, of which the Government approved applications for the construction of six generation units with aggregate generation capacity of 6,000 megawatts. The Government also approved applications from independent power producers for construction of two additional generation units with aggregate generation capacity of 2,000 megawatts to prepare for the contingency of failed or delayed construction of the foregoing generation units. Construction for the six generation units is scheduled to be completed between 2018 and 2021.

Coal Consumption Tax

On January 1, 2014, largely based on policy considerations of tax equity among different fuel types as well as environmental concerns, the Ministry of Strategy and Finance announced that, effective July 1, 2014, consumption tax will apply to bituminous coal, which previously was not subject to consumption tax unlike other fuel types such as LNG or bunker oil. The base tax rate (which is subject to certain adjustments) will be Won 24 per kilogram for bituminous coal; however, due to concerns on the potential adverse effect on industrial activities, the applicable tax rate will be Won 19 per kilogram for bituminous coal with net heat generation of 5,000 kilo calories or more per kilogram, and Won 17 per kilogram for bituminous coal with net heat generation of less than 5,000 kilo calories per kilogram. In contrast, the applicable tax rate for LNG will be reduced from Won 60 per kilogram to Won 42 per kilogram. Since bituminous coal currently represents the largest fuel type for electricity generation, accounting for approximately 43.0% of our entire fuel requirements in 2013 in terms of electricity output, we expect the newly adopted consumption tax thereon will result in an increase of our overall fuel costs, notwithstanding the decrease in the consumption tax rate for LNG, which accounted for approximately 19.7% of our entire fuel requirements in 2013 in terms of electricity output. While we expect that such additional fuel costs will be covered by a corresponding increase in electricity tariff, there is no assurance that the Government will in fact raise electricity tariff to a level sufficient to fully cover such additional costs in a timely manner or at all, and if the Government does not do so, the increase in our overall fuel costs arising from the newly adopted coal consumption tax will adversely affect our results of operation and financial condition.

Recent Incidents Involving Certain of Our Nuclear Generation Units

In May 2013, the NSSC announced that it discovered certain control cables used in three of our then-operating nuclear generation units, Shin-Kori #1 and #2, Shin-Wolsung #1, and three units under construction, Shin-Kori #3 and #4 and Shin-Wolsung #2, had been supplied based on forged testing results. These parts were custom-made and have critical functions in the case of emergency for activating certain safety signals. The forgery was made by a testing facility in charge of performance evaluation of the parts before delivery.

In response to the recent scandals, the Ministry of Trade, Industry and Energy has announced a number of measures to enhance the integrity, transparency and overall quality of the procurement, testing and verification processes with respect to parts used at our nuclear generation units, including: (i) encouraging open hiring (including outside experts) to reduce the chances of collusion, (ii) establishing a Government-supervised independent testing verification agency for nuclear generation parts, (iii) requiring KHNP to obtain testing results directly from testing facilities instead of indirectly from suppliers as has been the existing practice, (iv) increasing criminal and civil penalties for wrongdoings related to quality certifications, and (v) enhancing transparency in KHNP’s procurement process. We are actively and promptly implementing these measures. In addition, KHNP has filed a lawsuit seeking compensation for damages against the supplier and testing facility that were responsible for the forgery.

These incidents have had a material adverse effect, and may have a further material adverse effect, on our reputation, business, results of operation, financial condition as well as the general acceptance of nuclear power, especially if, as a result of these incidents or otherwise, there are findings of other criminal or other illegal or improper activities or if there are additional shutdowns that lead to greater social and political concerns over nuclear safety to the effect of impeding with our normal operation of nuclear generation units. See Item 3D. “Risk Factors—Recent findings of falsified testing results and bribery and the subsequent prolonged shutdowns of certain of our nuclear generation units may adversely hurt our reputation, business, results of operations and financial condition.”

Coal-Fired Power Plant Project in Vietnam

On March 19, 2013, a consortium consisting of us and Marubeni, a Japanese corporation, was selected by the Ministry of Industry and Trade of Vietnam for the construction and operation of a 1,200 megawatt coal-fired power plant in Thanh Hoa province, Vietnam. Construction will begin in December 2014 with target completion

by December 2018, after which we will operate the plant for 25 years. We have entered into a power purchase agreement with Electricity of Vietnam (EVN). Total project cost is expected to be US$2.3 billion, of which 25% will be funded by capital contribution and the remaining 75% by debt financing. The share capital of the special purpose entity that will be in charge of this project will be US$ 575 million, and KEPCO and Marubeni will each hold a 50% equity interest in such entity.

Electricity Storage System and Smart Grid Initiatives

We have recently been actively participating in the Government’s initiative for wider distribution and use of electricity storage systems (“ESS”). An ESS is a facility that stores electricity generated during times of low demand and transmits such electricity during times of high demand. Since our generation units currently set aside part of their capacity for frequency adjustment, replacing such parts with ESSs is expected to result in significant fuel cost savings and efficiency enhancement for the generation process. We plan to establish and operate ESSs with total capacity of 50 megawatts in 2014 and gradually increase the capacity to 500 megawatts by 2017, which we believe will result in fuel cost savings of approximately Won 300 billion per year.

We are also involved in a number of smart-grid related initiatives. For example, we are participating in the Government’s Smart Grid Expansion Business along with 47 other corporations and agencies. This initiative involves setting out a realistic business model for commercialization of smart grid technologies for general use and distribution. The consortium is currently working on the details of such model. In addition, after completing the experimentation stage at one of our office buildings, we plan to roll out “smart grid stations,” which include facilities that integrate renewable energy production, electricity storage, advanced metering and/or building automation, to our office buildings in 210 locations nationwide. We are also in the process of developing micro-grids, for which the experimentation stage was completed, as replacement for long-distance transmission grids. Furthermore, we are also upgrading our current facility management programs and office software to comprehensively integrate smart grid and advanced metering operating systems.

Government Ownership and Our Interactions with the Government

The KEPCO Act requires that the Government own at least 51% of our capital stock. Direct or indirect ownership of more than 50% of our outstanding common 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. We are currently not aware of any plans of the Government to cease to own, directly or indirectly, at least 51% of our outstanding common stock.

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

The Government, through its various policy initiatives for the Korean energy industry as well as direct and indirect supervision of us and our industry, plays an important role in our business and operations. Most importantly, the electricity tariff rates we charge to our customers are regulated by the Government taking into account, among others, our needs to recover the costs of operations, make capital investments and recoup a fair return on capital invested by us, as well as the Government’s overall policy considerations, such as inflation. See Item 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 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 wholly-owned thermal generation subsidiaries (namely, KOSEP, KOMIPO, 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 have substantial monopoly with respect to the transmission and distribution of electricity in Korea.

While our ownership percentage of the thermal generation subsidiaries will depend on the further adjustments to the Restructuring Plan to be adopted by the Government, we plan to retain 100% 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 Thermal 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% 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

In August 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 thermal 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.

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 10 (excluding renewable energy producers) as of December 31, 2013. We distribute electricity purchased through the Korea Power Exchange to the end users.

Our Relationship with the Korea Power Exchange

The key features of our relationships with the Korea Power Exchange include the following: (i) we and our six generation subsidiaries are member corporations of the Korea Power Exchange and collectively own 100% of its share capital, (ii) three of the 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 in 2005 that stated that we are not deemed to have significant influence or control over the decision-making process of the Korea Power Exchange relating to its business or financial affairs.

Pricing Factors

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

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

Marginal Price

The primary purpose of the marginal price is to compensate the generation companies for fuel costs, which represents the principal component of the variable costs of generating electricity. We currently refer such marginal price as the “system marginal price.”

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

Under the merit order system, the generation unit with the lowest variable cost of producing electricity among all the generation units that have submitted a bid for a given hour is first awarded a purchase order for electricity up to the available capacity of such unit as indicated in its bid. The generation unit with the next lowest variable cost is then awarded a purchase order up to its available capacity in its bid, and so forth, until the projected demand for electricity for such hour is met. We refer to the variable cost of the generation unit that is the last to receive the purchase order for such hour as the system marginal price, which also represents the highest price at which electricity can be supplied at a given hour based on the demand and supply for such hour. 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 two months prior to such determination. The purpose of the merit order system is to encourage generation units to reduce its electricity generation costs by making its generation process more efficient, sourcing fuels from most cost-effective sources or adopting other cost savings programs.

The final allocation of electricity supply is further adjusted on the basis of other factors, including the proximity of a generation unit to the geographical area to which power is being supplied, network and fuel constraints and the amount of power loss. This adjustment mechanism is designed to adjust for transmission losses in order to improve overall cost-efficiency in the transmission of electricity to end-users.

The price of electricity at which our generation subsidiaries sell electricity to us is determined using the following formula:

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

The adjusted coefficient is determined based on considerations of, among others, electricity tariff rates, the differential generation costs for different fuel types and the relative fair returns on investment in respect of us compared to our generation subsidiaries. The purpose of the adjusted coefficient is to prevent electricity trading from resulting in undue imbalances as to the relative financial results among generation subsidiaries as well as

between us (as the purchaser of electricity) and our generation subsidiaries (as sellers of electricity). Such imbalances may arise from excessive profit taking by base load generators (on account of their inherently cheaper fuel cost structure compared to non-base load generators) as well as from fluctuations in fuel prices (it being the case that during times of rapid and substantial rises in fuel costs which are not offset by corresponding rises in electricity tariff rates charged by us to end-users, on a non-consolidated basis our profitability will decline compared to that our generation subsidiaries since our generation subsidiaries are entitled to sell electricity to us at cost plus a guaranteed margin).

The adjusted coefficient applies in principle to all generation units that use the same type of fuel, except for independent power producers that use LNG or oil as fuel. Independent power producers that use coal as fuel will be entitled to the adjusted coefficient upon commencement of commercial operation beginning from 2016. The adjusted coefficient is currently set at the highest level for the marginal price of electricity generated using nuclear fuel, followed by coal, oil and LNG. The differentiated adjusted coefficients reflect the Government’s current energy policy objectives and have the effect of setting priorities in the fuel types to be used in electricity generation. 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 material developments in 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, subject to such capacity being actually available on the relevant day of 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/kW-h and is 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 exceeding 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 “on-peak” hour, a “mid-peak” hour or an “off-peak” hour (it being highest for the on-peak hours and lowest for the off-peak hours) and the capacity price paid is highest during the months of January, July and August when electricity usage is highest due to weather conditions. Other than subject to the aforementioned variations, the same capacity pricing mechanism applies to all generation units regardless of fuel types used.

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, 2013 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		137,948		28.8		6,289		14.9		45.59
	KOSEP		59,211		12.3		4,040		9.5		68.23
	KOMIPO		55,631		11.6		5,659		13.4		101.72
	KOWEPO		55,954		11.7		5,755		13.6		102.86
	KOSPO		65,685		13.7		7,136		16.9		108.64
	EWP		54,069		11.3		5,301		12.5		98.04
	Others⁽¹⁾		50,788		10.6		8,109		19.2		159.67

	Total		479,287		100.0		42,288		100.0		88.23

Energy Sources	Nuclear		132,396		27.6		5,179		12.2		39.12
	Bituminous coal		186,886		39.0		10,972		26.1		58.71
	Anthracite coal		7,367		1.5		676		1.6		91.73
	Oil		14,750		3.1		3,271		7.8		221.78
	LNG		4,462		0.9		1,040		2.5		215.31
	Combined-cycle		115,420		24.1		18,238		43.4		158.52
	Hydro		3,558		0.7		608		1.4		170.92
	Pumped-storage		4,086		0.9		835		2.0		204.42
	Others		10,361		2.2		1,469		3.0		120.62

	Total		479,287		100.0		42,288		100.0		88.23

Load	Base load		323,099		67.4		16,442		38.9		50.89
	Non-base load		156,188		32.6		25,846		61.1		165.48

	Total		479,287		100.0		42,288		100.0		88.23

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 2013, we purchased an aggregate of 16,892 gigawatt hours of electricity generated by independent power producers under existing power purchase agreements. These independent power producers had an aggregate generation capacity of 4,268 megawatts as of December 31, 2013.

Power Generation

As of December 31, 2013, we and our generation subsidiaries had a total of 598 generation units, including nuclear, thermal, hydroelectric and internal combustion units, representing total installed generation capacity of 70,845 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, 2013 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		75.5
Thermal:
Coal		51		24,534		93.6
Oil		16		3,950		40.3
LNG		4		888		45.4

Total thermal		71		29,372		85.0

Internal combustion		208		330		23.8
Combined-cycle		107		14,886		63.5
Hydro		71		5,334		12.2
Wind		40		94		17.1
Solar		70		70		13.6
Fuel cell		7		14		66.1
Biogas		1		30		45.0

Total		598		70,845		71.0

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; 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 generation capacity by fuel type. In the past, we relied principally upon oil-fired thermal generation units for electricity generation. Since the oil shock in 1974, however, Korea’s power development plans have emphasized the construction of nuclear generation units. While nuclear units are more expensive to construct than thermal generation units of comparable capacity, nuclear fuel is less expensive than fossil fuels in terms of electricity output per unit cost. However, efficient operation of nuclear units requires that such plants be run continuously at relatively constant energy output levels. As it is impractical to store large quantities of electrical energy, we seek to maintain nuclear power production capacity at approximately the level at which demand for electricity is continuously stable. During those times when actual demand exceeds the usual level of electricity supply from nuclear power, we rely on units fired by fossil fuels and hydroelectric units, which can be started and shut down more quickly and efficiently than nuclear units, to meet the excess demand. Bituminous coal 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.


	2009		2010		2011		2012		2013		% of 2013 Gross Generation⁽¹⁾
	(in gigawatt hours, except percentages)
Electricity generated by us and our generation subsidiaries:
Nuclear		147,771		148,596		154,723		150,327		138,784		26.8
Coal		193,803		198,287		199,516		199,329		201,119		38.8
Oil		11,970		10,874		9,456		13,553		13,941		2.7
LNG		762		2,288		2,233		3,453		2,950		0.6
Internal combustion		697		731		821		752		741		0.1
Combined-cycle		47,580		70,081		71,668		75,751		85,703		16.6
Hydro		4,091		4,393		4,815		5,140		5,679		1.1
Wind		82		91		117		127		155		0.03
Solar and fuel cells		24		44		60		83		251		0.05

Total generation by us and our generation subsidiaries		406,780		435,384		443,409		448,516		449,323		86.8

Electricity generated by IPPs:
Thermal		25,274		37,197		42,240		48,043		54,242		10.5
Hydro and other renewable		1,550		2,079		11,244		13,015		14,149		2.7

Total generation by IPPs		26,824		39,276		53,484		61,058		68,391		13.2

Gross generation		433,604		474,660		496,893		509,574		517,714		100
Auxiliary use⁽²⁾		18,258		19,372		19,689		20,154		21,303		4.1
Pumped-storage⁽³⁾		3,713		3,663		4,257		4,789		5,408		1.0

Total net generation⁽⁴⁾		411,631		451,625		472,947		484,631		491,003		94.8

Transmission and distribution losses⁽⁵⁾		16,770		18,034		17,430		17,292		18,311		3.73

IPPs = Independent power producers

Notes:

(1)	Unless otherwise indicated, percentages are based on gross generation.

(2)	Auxiliary use represents electricity consumed by generation units in the course of generation.

(3)	Pumped-storage represents electricity consumed during low demand periods in order to store water which is utilized to generate hydroelectric power during peak demand periods.

(4)	Total net generation 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.


	2009		2010		2011		2012		2013
	(Megawatts)
Total capacity		73,470		76,078		76,649		81,806		82,296
Peak load		66,797		71,308		73,137		75,987		76,522
Average load		49,498		54,185		56,723		58,012		58,615

Korea Hydro & Nuclear Power Co., Ltd.

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

KHNP owns and operates 23 nuclear generation units at four power plant complexes in Korea, located in Kori, Wolsong, Yonggwang (Hanbit) and Ulchin (Hanul), 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, 2013.

The table below sets forth the number of units and installed capacity as of December 31, 2013 and the average capacity factor by types of generation units in 2013.


	Number of Units		Installed Capacity⁽¹⁾		Average Capacity Factor⁽²⁾
			(Megawatts)		(Percent)
Nuclear		23		20,716		75.5
Hydroelectric		50		5,307		12.0
Solar		5		16		15.3
Wind		1		0.8		7.1

Total		79		26,040

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-Hanul sites, respectively. We expect to complete these units between 2014 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-Hanul 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, 2013.

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

Hanbit-1

PWR

W, D

1986

950

Hanbit-2

PWR

W, D

1987

950

Hanbit-3

PWR

H, CE, K

H, GE

1995

1,000

Hanbit-4

PWR

H, CE, K

H, GE

1996

1,000

Hanbit-5

PWR

D, CE, W, KOPEC

D, GE

2002

1,000

Hanbit-6

PWR

D, CE, W, KOPEC

D, GE

2002

1,000

Hanul-1

PWR

1988

950

Hanul-2

PWR

1989

950

Hanul-3

PWR

H, CE, K

H, GE

1998

1,000

Hanul-4

PWR

H, CE, K

H, GE

1999

1,000

Hanul-5

PWR

D, KOPEC, W

D, GE

2004

1,000

Hanul-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 (U.K.); “P” means Parsons (Canada and U.K.); “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 2013 with respect to each nuclear generation unit of KHNP.


Unit	Average Capacity Factor		Average Fuel Cost Per kWh
	(Percent)		(Won)
Kori-1		49.9		5.9
Kori-2		80.9		6.4
Kori-3		100.1		5.3
Kori-4		75.5		6.7
Shin-Kori-1		26.6		12.8
Shin-Kori-2		40.8		6.5
Wolsong-1		—		—
Wolsong-2		83.7		7.5
Wolsong-3		92.6		7.4
Wolsong-4		90.3		7.6
Shin-Wolsong-1		38.1		8.2
Hanbit-1		82.4		6.5
Hanbit -2		75.2		5.3
Hanbit -3		54.1		6.1
Hanbit -4		86.6		5.7
Hanbit -5		94.1		4.8
Hanbit -6		98.1		5.0
Hanul-1		85.8		5.7
Hanul-2		88.2		5.7
Hanul-3		100.0		5.3
Hanul-4		37.8		6.1
Hanul-5		85.5		5.6
Hanul-6		99.8		5.0

Total nuclear		75.5		6.1

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 duration of shutdown for fuel replacement and maintenance was 117.5 days per unit in 2013, which was higher than that for previous years due to the quality assurance-related incidents which led to a shutdown of a number of KHNP’s nuclear units from May 2013 until January 2014 (see Item 3D. “Risk Factors—Risks Relating to KEPCO—Recent findings of falsified testing results and bribery and the subsequent prolonged shutdowns of certain of our nuclear generation units may adversely hurt our reputation, business, results of operations and financial condition.”) as well as scheduled long-term overhauls. In addition, KHNP’s nuclear units experienced an average of 0.26 unplanned shutdowns per unit in 2013. In the ordinary course of operations, KHNP’s nuclear units routinely experience damage and wear and tear, which are repaired during routine shutdown periods or during unplanned temporary suspensions of operations. No significant damage has occurred in any of KHNP’s nuclear reactors, and no significant nuclear exposure or release incidents have occurred at any of KHNP’s nuclear facilities since the first nuclear plant commenced operation in 1978.

Hydroelectric

Effective January 1, 2011, pursuant to the Government’s Proposal for Improvements in the Structure of the Electric Power Industry announced in August 2010, our five thermal generation subsidiaries transferred all of the assets and liabilities relating to their pumped-storage and hydroelectric business units to KHNP. The table below sets forth certain information, including the installed capacity as of December 31, 2013 and the average capacity factor in 2013.


Location of Unit	Number of Units		Classification	Year Built		Installed Capacity		Average Capacity Factor
						(Megawatts)		(%)
Hwacheon		4	Dam waterway		1944		108.0		23.4
Chuncheon		2	Dam		1965		62.3		23.6
Euiam		2	Dam		1967		48.0		31.8
Cheongpyung		4	Dam		1943		140.1		43.4
Paldang		4	Dam		1973		120.0		44.1
Seomjingang		3	Basin deviation		1945		34.8		51.5
Boseonggang		2	Basin deviation		1937		4.5		58.3
Kwoesan		2	Dam		1957		2.6		58.2
Anheung		3	Dam waterway		1978		0.5		52.0
Kangreung		2	Basin deviation		1991		82.0		—
Topyeong		1	Dam		2011		0.05		44.1
Muju⁽¹⁾		1	Dam		2003		0.4		17.5
Sancheong⁽¹⁾		1	Dam		2001		1.0		42.4
Yangyang⁽¹⁾		2	Dam		2005		1.4		25.5
Yecheon⁽¹⁾		1	Dam		2011		1.0		19.4
Cheongpeoung⁽¹⁾		2	Pumped Storage		1980		400.0		6.5
Samrangjin⁽¹⁾		2	Pumped Storage		1985		600.0		9.5
Muju⁽¹⁾		2	Pumped Storage		1995		600.0		10.8
Sancheong⁽¹⁾		2	Pumped Storage		2001		700.0		10.1
Yangyang⁽¹⁾		4	Pumped Storage		2006		1,000.0		9.7
Cheongsong⁽¹⁾		2	Pumped Storage		2006		600.0		11.1
Yecheon⁽¹⁾		2	Pumped Storage		2011		800.0		10.7

Total		50					5,307		12.0

Note:

(1)	Indicates facilities that have been transferred from our five thermal 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, 2013 and the average capacity factor in 2013, 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 commercial operation began in November 2012.


Location of Unit	Classification	Year Built		Installed Capacity		Average Capacity Factor
				(Megawatts)		(Percent)
Yonggwang	Solar		2008		13.9		15.3
Yecheon	Solar		2012		2.0		15.9
Kori	Wind		2008		0.8		7.1

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 Korea available for commercially viable hydroelectric power generation. Consequently, we expect that no new major hydroelectric power plants will be built in the foreseeable future. Due to the ease of its start-up and shut-down mechanism, hydroelectric power generation is reserved for peak demand periods.

Korea South-East Power Co., Ltd.

The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2013 and the average capacity factor and average fuel cost per kilowatt in 2013 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		22.1		3,240		93.9		57.0
Yong Hung #1, 2, 3, 4		7.3		3,340		91.6		57.5
Yosu # 2		36.5		328.6		79.2		95.6
Anthracite:
Yongdong #1, 2		37.3		325		83.3		99.0
Combined cycle and internal Combustion:
Bundang gas turbine #1,2,3,4,5,6,7,8; steam turbine #1, 2		20.0		922		52.1		200.3
Hydro, Solar and other renewable energy		—		70.3		—		149.5

Total		21.3		8,226		86.8		70.4

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		18.9		4,000		95.0		41.8
Anthracite:
Seocheon #1, 2		30.5		400		83.4		82.1
Oil-fired:
Jeju #2, 3		13.5		150		72.4		208.8
LNG-fired:
Seoul #4, 5		44.1		388		39.5		209.3
Incheon #1, 2		41.4		500		36.8		195.5
Combined-cycle and internal combustion:
Boryeong gas turbine #1, 2, 3, 4, 5, 6 ; steam turbine #1, 2, 3		14.8		1,350		52.4		143.6
Incheon gas turbine #1, 2, 3, 4, 5, 6 ; steam turbine #1, 2, 3		8.8		1,462.4		84.1		138.2
Sejong gas turbine #1, 2 ; steam turbine #1		0.1		530.4		73.6		78.5
Jeju Gas Turbine #3		36.1		55		0.8		724.3
Jeju Internal Combustion Engine #1, 2		6.6		80		68.7		181.4
Wind-powered:
Yangyang #1, 2		7.5		3.0		19.9		10.8
Hydroelectric:
Boryeong		4.8		7.5		28.7		0.5
Photovoltaic (“PV”) power and fuel cell generation:
Boryeong (PV) site		5.6		0.6		10.8		14.3
Seocheon (PV) site		5.9		1.2		12.6		—
Jeju (PV) site		1.8		1.1		13.4		—
Seoul (PV) site		2.3		1.3		14.9		2.7
Yeosu (PV) site		1.8		2.2		17.1		—
Incheon (PV) site		2.0		0.3		13.8		—
Boryeong (fuel cell) site		5.3		0.3		90.6		182.4

Total		18.3		8,933		78.0		85.6

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		13.4		4,000		96.7		41.3
Oil-fired:
Pyeongtaek #1, 2, 3, 4		32.1		1,400		30.0		189.1
Combined cycle:
Pyeongtaek #1, 2		11.0		964		36.2		175.7
Gunsan		3.6		718.4		85.1		133.5
West Incheon		21.5		1,800		80.7		140.9
Hydroelectric:
Taean		6.3		2.2		21.7		—
Solar:
Taean		8.4		0.1		12.7		—
Taean 2		1.9		0.6		14.0		—
Gunsan		3.5		0.3		14.8		—
Samryangjin		6.1		3.0		14.7		—
Sejong City		1.5		4.9		14.8		—
Gyeonggi-do		0.7		2.5		13.5		—
Yeongam		0.8		13.3		16.4		—

Total		16.9		8,909		76.2		87.03

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		12.3		4,000		95.0		40.0
Oil-fired:
Youngnam #1, 2		41.9		400		33.2		214.7
Nam Jeju #3, 4		7.0		200		74.9		209.5
Combined cycle:
Shin Incheon #1, 2, 3, 4		17.2		1,800		83.4		139.3
Busan #1, 2, 3, 4		10.2		1,800		91.4		133.3
Yeongwol #1		3.6		848		60.9		139.0
Hallim		17.5		105		14.9		305.4
Wind power:
Hankyung		7.2		21		28.7		—
Seongsan		4.2		20		29.9		—
Solar		3.2		6		13.7		—

Total		13.2		9,200		84.5		92.8

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		78.3		39.5
Honam #1, 2		40.8		500		87.9		60.2
Anthracite:
Donghae #1, 2		14.8		400		78.3		61.7
Oil-fired:
Ulsan #1, 2, 3, 4, 5, 6		46.7		1,800		43.4		194.4
Combined cycle:
Ulsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3		16.9		1,686		49.0		153.4
Ilsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2		18.3		900		49.7		175.2
Mini hydro:
Dangjin		4.0		5.0		62.7		—
Photovoltaic:
Dangjin		3.0		1.0		14.6		—
Ulsan		2.0		0.5		13.3		1.8
Kwangyang		2.1		2.3		12.4		3.1
Dangjin Storage Facility		1.0		0.7		14.2		—
Dangjin Floating System		0.5		1.0		14.6		—
Dangjin Waste Treatment Facility		2.0		1.3		11.6		—
Donghae		7.0		1.0		12.6		1.0
Fuel cell:
Ilsan # 1		4.1		2.4		83.8		171.7
Ilsan # 2		2.1		2.8		73.6		189.7
Ilsan # 3		0.8		2.8		77.1		176.5
Ulsan		0.2		2.8		24.9		115.0
Wind Power:
YeongGwang Jisan		1.2		3.0		11.6		153.4
Biomass:
Donghae		0.5		30.0		82.4		175.2

Total		8.0		9,342.6		71.4		2.9

Power Plant Remodeling and Recommissioning

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


Power Plant	Capacity	Completed (Year)	Extension	Company
Taean #1-8	4,000 MW (500 MW×8)	EP⁽¹⁾ upgrade (#4, 2011) EP⁽¹⁾ upgrade (#1, 2012)	Anti-pollution	KOWEPO
Pyeongtaek #1-4	1,400 MW (350 MW ×4)	Steam turbine upgrade (#1, 4, 2013)	10-year performance- improvement	KOWEPO
Boryeong #1-8	4,000 MW (500 MW ×8)	Control System upgrade (#6, 2011, #3,5, 2012)	Performance- improvement	KOMIPO
Incheon CC #2	508.9 MW (gas turbines 164 MW ×2) (steam turbines 181 MW ×1)	SCR⁽²⁾ : 2012	Anti-pollution	KOMIPO
Yosu #1	350 MW	2016	30 years	KOSEP
Yosu #2	328.6 MW	2013	30 years	KOSEP
Yonghung #5-6	1,740 MW (870 MW ×2)	2014	30 years	KOSEP

Notes:

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

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

Transmission and Distribution

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

As of December 31, 2013, our transmission system consisted of 32,249 circuit kilometers of lines of 765 kilovolts and others including high-voltage direct current lines, and we had 790 substations with aggregate installed transformer capacity of 279,520 megavolt-amperes.

As of December 31, 2013, our distribution system consisted of 105,740 megavolt-amperes of transformer capacity and 8,698,776 units of support with a total line length of 449,683 circuit kilometers.

In recent years, we have made substantial investments in our transmission and distribution systems to increase geographic 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 3.73% of our gross generation in 2013. 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 automation of electricity transmission and development of new transmission technologies, among others.

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. We expect that

such technology will improve efficiency and reduce electricity loss over the course of electricity transmission and distribution. In July 2012, the Government implemented a master plan to build out a smart grid, which includes the Advanced Metering Infrastructure (“AMI”) roadmap. 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, 2013, we have installed 2.5 million smart meter units, and plan to install an additional 2.3 million units in 2014. The AMI project is expected to cost 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 34.9%, 33.5% and 30.9% of our fuel requirements for electricity generation in 2011, 2012 and 2013, 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 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 2013, KHNP purchased 100%, or approximately 4,238 tons, of its uranium concentrate requirement under both long-term and spot supply contracts with suppliers in the United Kingdom, Kazakhstan, France, Germany, Niger, Canada, Japan and Australia. 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, China, 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 43.1%, 42.5% and 43.0% of our fuel requirements for electricity generation in 2011, 2012 and 2013, respectively, and anthracite coal accounted for 1.9%, 2.0% and 1.8% of our fuel requirements for electricity generation in 2011, 2012 and 2013, respectively.

In 2013, our generation subsidiaries purchased approximately 79.5 million tons of bituminous coal, of which approximately 41.6%, 38.2%, 9.5%, 9.5% and 1.2% were imported from Indonesia, Australia, the United States, Russia, and others, respectively. Approximately 89.0% of the bituminous coal requirements of our generation

subsidiaries in 2013 were purchased under long-term contracts with the remaining 11.0% purchased in the spot market. Some of our long-term contracts relate to specific generating plants and extend through the end of the projected useful lives of such plants, subject in some cases to periodic renewal. Pursuant to the terms of our long-term supply contracts, prices are adjusted periodically based on market conditions. The average cost of bituminous coal per ton purchased under such contracts amounted to Won 116,073, Won 113,705 and Won 94,217 in 2011, 2012 and 2013, respectively.

In 2013, our generation subsidiaries purchased approximately 0.8 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 136,471, Won 141,669 and Won 126,425 in 2011, 2012 and 2013, respectively.

Oil

Oil accounted for 2.4%, 3.2% and 3.3% of our fuel requirements for electricity generation in 2011, 2012 and 2013, respectively.

In 2013, our generation subsidiaries purchased approximately 21.7 million barrels of fuel oil, substantially all of which was purchased from domestic refiners through competitive open bidding. Purchase prices are based on the spot market price in Singapore. The average cost per barrel was Won 128,395, Won 139,204 and Won 123,402 in 2011, 2012 and 2013, respectively.

LNG

LNG accounted for 16.7%, 17.7% and 19.7% of our fuel requirements for electricity generation in 2011, 2012 and 2013, respectively. In 2013, for use in electricity generation we purchased approximately 12.3 million tons of LNG from Korea Gas Corporation, a Government-controlled entity in which we currently own a 24.5% equity interest. In 2013, we purchased all of our LNG requirements for use in power generation from Korea Gas Corporation. Under the terms of the LNG contract with Korea Gas Corporation, all of our five thermal generation subsidiaries jointly and severally agreed to purchase a total of 11.4 million tons of LNG in 2013, subject to an automatic price adjustment annually based on a pre-determined formula if the actual purchased amount exceeds or falls short of the contracted amount. We believe the quantities of LNG provided under such contract will be adequate to meet the needs of our generation subsidiaries for LNG for the next several years. The LNG supply contracts between our generation subsidiaries and Korea Gas Corporation generally have a term of 20 years and provide for minimum purchase requirements for our generation subsidiaries, the specific terms of which are subject to negotiation between Korea Gas Corporation and our generation subsidiaries and approval by the Government. The average cost per ton of LNG under our contract with Korea Gas Corporation was Won 888,808, Won 1,020,528 and Won 1,002,323 in 2011, 2012 and 2013, respectively.

Hydroelectric

Hydroelectric power generation accounted for 1.1%, 1.1% and 1.3% of our fuel requirements for electricity generation in 2011, 2012 and 2013, respectively. The availability of water for hydroelectric power depends on rainfall and competing uses for available water supplies, including residential, commercial, industrial and agricultural consumption. Pumped storage enables us to increase the available supply of water for use during periods of peak electricity demand.

As of January 1, 2011, assets and liabilities relating to the pumped storage units of the five thermal generation subsidiaries were 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 4.3% per annum for the five years ended December 31, 2013. According to the Bank of Korea, the compounded growth rate for real gross domestic product, or GDP, was approximately 3.2% for the same period. The GDP growth rate was approximately 3.7%, 2.3% and 3.0% during 2011, 2012 and 2013, respectively.

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.


	2009			2010			2011			2012			2013
Growth in GDP		0.7	%		6.5	%		3.7	%		2.3	%		3.0	%
Growth in electricity consumption		2.4	%		10.1	%		4.8	%		2.5	%		1.8	%

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

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

Demand by the Type of Usage

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


	2009 (GWh)		YoY growth (%)			2010 (GWh)		YoY growth (%)		2011 (GWh)		YoY growth (%)			2012 (GWh)		YoY growth (%)			2013 (GWh)		YoY growth (%)			% of Total 2013
Residential		59,426		2.7			63,200		6.3		63,524		0.5			65,484		3.1			65,815		0.5			13.9
Commercial		89,619		3.2			97,410		8.7		99,504		2.1			101,593		2.1			102,196		0.6			21.5
Educational		6,465		11.8			7,453		15.3		7,568		1.5			7,860		3.9			7,947		1.1			1.7
Industrial		207,216		1.8			232,672		12.3		251,491		8.1			258,102		2.6			265,373		2.8			55.9
Agricultural		9,671		9.0			10,654		10.2		11,232		5.4			12,776		13.8			13,866		8.5			2.9
Street lighting		2,954		3.8			3,081		4.3		3,145		2.1			3,158		0.4			3,156		(0.1	)		0.7
Overnight Power		19,122		(1.4	)		19,690		3.0		18,606		(5.5	)		17,620		(5.3	)		16,496		(6.4	)		3.4

Total		394,475		2.4			434,160		10.1		455,070		4.8			466,593		2.5			474,849		1.8			100.0

The industrial sector represents the largest segment of electricity consumption in Korea. Demand for electricity from the industrial sector was 265,373 gigawatt hours in 2013, representing a 2.8% increase from 2012, largely due to continued export-led growth of the Korean economy. Demand for electricity 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. Demand for electricity from the commercial sector, however, remained largely stable at 102,196 gigawatt hours in 2013, representing a 0.6% increase from 2012.

In 2013, we distributed electricity to approximately 22 million households, which represent substantially all of the households in Korea. Demand for electricity from the residential sector is largely dependent on population growth and use of heaters, air conditioners and other electronic appliances. Demand for electricity from the residential sector remained relatively stable at 65,815 gigawatt hours in 2013, representing a 0.5% increase compared to 2012.

Demand Management

Our ability to provide 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.


	2009			2010			2011			2012			2013
Facility reserve margin		10.0	%		6.7	%		4.8	%		7.7	%		7.5	%
Supply reserve margin		7.9	%		6.2	%		5.5	%		5.2	%		5.5	%

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

Electricity Rates

The Electricity Business Law and the Price Stabilization Act of 1975, each as amended from time to time, prescribe the procedures for the approval and establishment of rates charged for the electricity we sell. We submit our proposals for revisions of rates or changes in the rate structure to the Ministry of Trade, Industry and Energy. The Ministry of Trade, Industry and Energy then reviews these proposals and, following consultation with the 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 2012, the approved rate of return on the debt component of the rate base was 3.2% while the approved rate of return on the equity component of the rate base was 6.6%. As a result of such approved rates of returns, the fair rate of return in 2012 was determined to be 4.8%. The fair rate of return for 2013 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 fair rate of return on invested capital assumed for the purposes of electricity tariff approvals, for reasons, among others, related to movements in fuel prices, exchange rates and demand for electricity that differ from what is assumed for determining our fair rate of return. For example, between 1987 and 1990, the actual rate of return was above the fair rate of return due to declining fuel costs and rising demand for electricity at a rate not anticipated for purposes of determining our fair rate of return. Similarly, depreciation of the Won against the U.S. dollar accounted for our actual rates of return being lower than the fair rate of return for the period from 1996 to 2000. For the period 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 increases the electricity tariff rates, but there typically is a significant time lag for the tariff increases as such increases 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.

Recent increases 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, 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, industrial, educational, agricultural, street lighting and overnight power usage tariff rates by 2.0%, 4.6%, 4.4%, 3.5%, 3.0%, 5.0% and 5.0%, respectively.

•

effective November 21, 2013, a 5.4% overall increase in our average tariff rate, consisting of increases in the residential, commercial, industrial, agricultural, street lighting and overnight power usage tariff rates by 2.7%, 5.8%, 6.4%, 3.0%, 5.4% and 5.4%, respectively, while making no change to the educational tariff.

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

Our current tariff schedule, which became effective as of November 21, 2013, is summarized below by the type of usage:

•

Industrial. The basic charge varies from Won 5,550 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from Won 53.7 per kilowatt hour to Won 196.6 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

•

Commercial. The basic charge varies from Won 6,160 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy usage charge varies from Won 53.7 per kilowatt hour to Won 196.6 per kilowatt hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.

•

Residential. Residential tariff includes a basic charge ranging from Won 410 for electricity usage of less than 100 kilowatt hours to Won 12,940 for electricity usage in excess of 500 kilowatt hours. Residential tariff also includes an energy usage charge ranging from Won 60.7 to Won 709.5 per kilowatt hour for electricity usage depending on the amount of usage and voltage.

•

Educational. The basic charge varies from Won 5,230 per kilowatt to Won 6,980 per kilowatt depending on the voltage used and the rate option. The energy usage charge varies from Won 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 360 per kilowatt to Won 1,210 per kilowatt depending on the type of usage. The energy usage charge varies from Won 21.6 per kilowatt-hour to Won 41.9 per kilowatt hour depending on the type of contract, the voltage used and the season.

•

Street-lighting. The basic charge is Won 6,290 per kilowatt and the energy usage charge is Won 85.9 per kilowatt hour. For electricity capacity of less than 1 kilowatt or for places where the installation of the electricity meter is difficult, a fixed rate of Won 37.5 per watt applies, with the minimum charge per month of Won 1,220.

In 2001, as part of implementing the Restructuring Plan, the Ministry of Trade, Industry and Energy established the Electric Power Industry Basis Fund to enable the Government to take over certain public services previously performed by us. In 2013, 3.7% of the tariff we collected from our customers was transferred to this fund prior to recognizing our sales revenue.

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 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. 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 pass-through 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 5B. “Operating and Financial Review and Prospects—Critical Accounting Policy—Fuel Cost Pass-through Adjustment.”

Power Development Strategy

from renewable sources to 11% by 2035, (v) reinforcing the system for stable supply of conventional energy, such as oil and gas, and (vi) introducing in 2015 an energy voucher system in lieu of a tariff discount system for the benefit of consumers in the low income group. In addition, the Second Basic National Energy Plan contemplates revising the target level of electricity generated by nuclear sources as a percentage of total electricity generated to 29%, compared to 41% under the First Basic National Energy Plan.

Capital Investment Program

The table below sets forth, for each of the years ended December 31, 2011, 2012 and 2013, the amounts of capital expenditures for the construction of generation, transmission and distribution facilities.


2011	2012		2013
(In billions of Won)
￦11,984	￦	12,751	￦	15,831

The table below sets forth the currently estimated installed capacity for new or expanded generation units to be completed by our generation subsidiaries in each year from 2014 to 2017.


Year	Number of Units		Type of Units	Total Installed Capacity⁽¹⁾
				(Megawatts)
2014		1	Nuclear power		1,400
		2	Coal-fired		1,740
		3	LNG-combined		1,007
2015		2	Coal-fired		2,020
2016		6	Coal-fired		5,470
		3	LNG-combined		1,200
2017		1	Nuclear power		1,400
		1	Coal-fired		1,000
		1	LNG-combined		900

Note:

(1)	Does not include installed capacity for two nuclear units with an aggregate installed capacity of 2,400 megawatts that were expected to be completed in 2013 but for which construction has been delayed.

For the period from 2018 to 2027, our generation subsidiaries currently plan to complete seven additional nuclear units with an aggregate installed capacity of 10,000 megawatts (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 Basic Plan) and four additional coal-fired units with an aggregate installed capacity of 2,740 megawatts.

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

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

The table below sets forth, for the period from 2014 to 2017, the budgeted amounts of capital expenditures for the construction of generation, transmission and distribution facilities pursuant to our capital investment program. The budgeted amounts may vary from the actual amounts of capital expenditures for a variety of reasons, including, among others, the implementation of the Sixth Basic Plan, changes in the number of units to be constructed, the actual timing of such construction, changes in rates of exchange between the Won and foreign currencies and changes in interest rates.


	2014		2015		2016		2017		Total
	(in billions of Won)
Generation⁽¹⁾:
Nuclear		4,844		5,231		6,137		6,423		22,634
Thermal		7,963		5,673		2,895		3,009		19,539

Sub-total		12,807		10,903		9,032		9,431		42,173

Transmission and Distribution:
Transmission		2,492		2,441		2,982		2,324		10,240
Distribution		2,509		2,773		2,553		2,414		10,249

Sub-total		5,001		5,214		5,535		4,739		20,489

Others⁽²⁾		2,090		2,361		1,772		1,422		7,646

Total		19,898		18,479		16,339		15,592		70,307

Notes:

(1)	The budgeted amounts for our generation facilities are based on the Sixth Basic Plan.

(2)	Principally consists of investments in renewable energy generation, among others.

We have financed, and plan to finance in the future, our capital investment programs primarily through net cash provided by our operating activities and financing in the form of debt securities and loans from domestic financial institutions, and to a lesser extent, borrowings from overseas financial institutions. In addition, in order to prepare for potential liquidity shortage, we and our generation subsidiaries maintain several credit facilities with domestic financial institutions in the aggregate amounts of Won 2,550 billion and US$4,549 million, the full amount of which was available as of December 31, 2013. We, KHNP and KOWEPO also maintain global medium-term note programs in the aggregate amount of US$10 billion, of which approximately US$4 billion remains currently available for future drawdown. See also Item 5B. “Liquidity and Capital Resources—Capital Resources.”

Environmental Programs

The Environmental Policy Basic Act, the Air Quality Preservation Act, the Water Quality Preservation Act, the Marine Pollution Prevention Act and the Waste Management Act, collectively referred in this annual report as the Environmental Acts, are the major laws of Korea that regulate atmospheric emissions, waste water, noise and other emissions from our facilities, including power generators and transmission and distribution units. Our existing facilities are currently in material compliance with the requirements of these environmental laws and international agreements, such as the United Nations Framework Convention on Climate Change, the Montreal Protocol on Substances that Deplete the Ozone Layer, the Stockholm Convention on Persistent Organic Pollutants and the Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and

Their Disposal. In order to foster coordination among us and our generation subsidiaries in respect of climate change and development of renewable energy sources, we formed the Committee on Climate Change and the Committee on Renewable Energy in 2005. In 2011 the Ministry of Security and Public Administration issued guidelines for the reduction of nationwide greenhouse gas emissions and energy conservation, pursuant to which we are intensifying our efforts to reduce the levels of carbon emission in order to help meet the national target for greenhouse gas emission reduction.

In 2005, we became the first public company in Korea to join the United Nations Global Compact, an international voluntary initiative designed to hold a forum for corporations, United Nations agencies, labor and civic groups to promote reforms in economic, environmental and social policies. As part of our involvement with such initiative, since September 2005, we have issued an annual report named the “Sustainability Report” to disclose our activities from the perspectives of economy, environment and society, in accordance with the reporting guidelines of the Global Reporting Initiative, the official collaborating center of the United Nations Environment Program that works in cooperation with United Nations Secretary General. In November 2010, our report on the Communication on Progress was reviewed favorably by the United Nations Global Compact and was subsequently posted on its website in recognition of our strong commitment to compliance with the principles of United Nations Global Compact. In May 2013, we obtained the Carbon Trust Standard, a certificate issued by Carbon Trust, an agency of the British government for excellence in demonstrated efforts to reduce carbon footprint. We are also a participant of the Carbon Disclosure Project, an international organization that promotes transparency in informational disclosure of carbon management process. We aim to become a global leader in carbon management and reduction.

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

The table below sets forth the number of emission control equipment installed at coal-fired power plants by our generation subsidiaries as of December 31, 2013.


	KOSEP		KOMIPO		KOWEPO		KOSPO		EWP
Flue Gas Desulphurization System		11		12		12		12		13
Selective Non-catalytic Reduction System		—		2		—		—		3
Selective Catalytic Reduction System		9		18		12		12		13
Electrostatic Precipitation System		13		20		12		12		18
Low NO2 Combustion System		16		28		26		29		30

Total		49		80		62		65		77

The table below sets forth the amount of annual emission from all generating facilities of our generation subsidiaries for the periods indicated. The amount of CO2 emissions may increase in the near future due to the construction of additional coal thermal power plants but is expected to decrease in the long-term, principally due to an increased use of nuclear power and renewable energy.


Year	Sox (g/MWh)		NOx (g/MWh)		Dust (g/MWh)		CO2 (kg/MWh)
2011		148		284		8		464
2012		165		297		8		471
2013		155		283		7		487

In order to comply with the current and expected environmental standards and address related legal and social concerns, we intend to continue to install additional equipment, make related capital expenditures and

undertake several environment-friendly measures to foster community goodwill. For example, in October 2004, we and our generation subsidiaries reached an agreement with the Ministry of Environment and civic organizations to completely remove polychlorinated biphenyl, or PCB, a toxin, from the insulating oil of our transformers by 2015. In addition, when constructing certain large new transmission and distribution facilities, we assess and disclose their environmental impact at the planning stage of such construction, as well as consult with local residents, environmental groups and technical experts to generate community support for such projects. We exercise additional caution in cases where such facilities are constructed near ecologically sensitive areas such as wetlands or preservation areas. We also make reasonable efforts to minimize any negative environmental impact, for example, by using more environment-friendly technology and hardware. In addition, we also undertake measures to minimize losses during the transmission and distribution process by making our power distribution network more energy-efficient in terms of loss of power, as well as to lower consumption of energy, water and other natural resources. In addition, we and our subsidiaries have acquired the ISO 14000 certification which is an environmental management system widely adopted internationally and have made it a high priority to make our electricity generation and distribution more environmentally friendly. In 2013, we further reinforced our environmental management system by acquiring the ISO 14001 certification as well as a domestic certification of the “green management system” that relates to the management of resources, energy, green house effects and social responsibilities.

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

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

Some of our generation facilities are powered by renewable energy sources, such as solar energy, wind power and hydraulic power. While such facilities are currently insignificant as a proportion of our total generation capacity or generation volume of our generation subsidiaries, we expect that the portion will increase in the future, especially since we are required to comply with the Renewable Portfolio Standard policy as described below.

The following table sets forth the generation capacity and generation volume in 2013 of our generation facilities that are powered by renewable energy sources.


	Generation Capacity (megawatts)			Generation Volume (gigawatt-hours)
Hydraulic Power		5,334			5,679
Wind Power		94			155
Solar Energy, Fuel Cells and Biogas		114			251

Subtotal		5,542			6,086
As percentage of total⁽¹⁾		7.8	%		1.4	%

Note:

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

In order to deal with shortage of fuel and other resources and also to comply with various environmental standards, in 2012 the Government adopted the Renewable Portfolio Standard (“RPS”) program, which replaced the Renewable Portfolio Agreement which had been in effect from 2006 to 2011. Under the RPS program, each generation subsidiary is required to generate a specified percentage of total electricity to be generated by such

generation subsidiary in a given year in the form of renewable energy, with the target percentage being 2.0% in 2012, 2.5% in 2013 and in