General Information
Our legal and corporate name is Korea Electric Power Corporation. We were established by the Government on December 31, 1981 as a statutory juridical corporation in Korea under the Korea Electric Power Corporation Act (the “KEPCO Act”) as the successor to Korea Electric Company. Our registered office is located at 55 Jeollyeok-ro, Naju-si, Jeollanam-do, 58322, Korea, and our telephone number is 82-61-345-4218. Our website address is www.kepco.co.kr.
Our agent in the United States is Korea Electric Power Corporation, North America Office, located at 7th Floor, Parker Plaza, 400 Kelby Street, Fort Lee, NJ 07024.
The Korean electric utility industry traces its origin to the establishment of the first electric utility company in Korea in 1898. On July 1, 1961, the industry was reorganized by the merger of Korea Electric Power Company, Seoul Electric Company and South Korea Electric Company, which resulted in the formation of Korea Electric Company. From 1976 to 1981, the Government acquired the private minority shareholdings in Korea Electric Company. After the Government acquired all the remaining shares of Korea Electric Company, Korea Electric Company was dissolved, and we were incorporated in 1981 and assumed the assets and liabilities of Korea Electric Company. We ceased to be wholly owned by the Government in 1989 when the Government sold 21% of our common stock. As of December 31, 2025, the Government maintained 51.1% ownership in aggregate of our common shares by direct holdings and indirect holdings through Korea Development Bank, a statutory banking institution wholly owned by the Government.
Under relevant laws of Korea, the Government is required to own, directly or indirectly, at least 51% of our capital. Direct or indirect ownership of more than 50% of our outstanding common voting stock enables the Government to control the approval of certain corporate matters relating to us that require a shareholders’ resolution, including approval of dividends. The rights of the Government and Korea Development Bank as holders of our common stock are exercised by the Ministry of Climate, Energy and Environment, based on the Government’s ownership of our common stock and a proxy received from Korea Development Bank, in consultation with the Ministry of Finance and Economy.
We operate under the general supervision of the Ministry of Climate, Energy and Environment. The Ministry of Climate, Energy and Environment, in consultation with the Ministry of Finance and Economy, is responsible for approving, subject to review by the Korea Electricity Commission, the electricity rates we charge our customers. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.” We furnish reports to officials of the Ministry of Climate, Energy and Environment, the Ministry of Finance and Economy and other Government agencies and regularly consult with such officials on matters relating to our business and affairs. See Item 4.B. “Business Overview—Regulation.” Our non-standing directors, who comprise a majority of our board
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of directors, must be appointed by the Ministry of Finance and Economy following the review and resolution of the Committee for Management of Public Institutions (which is established by law and chaired by the Minister of the Ministry of Finance and Economy and whose members consist of Government officials and others appointed by the President of Korea based on recommendation by the Minister of the Ministry of Finance and Economy) from a pool of candidates recommended by the director nomination committee. Our president and standing directors who concurrently serve as members of our audit committee must be appointed by the President of Korea upon the motion of the Minister of the Ministry of Climate, Energy and Environment (in the case of our president) and the Minister of the Ministry of Finance and Economy (in the case of our standing director who concurrently serves as a member of the audit committee) and following the nomination by our director nomination committee, the review and resolution of the Committee for Management of Public Institutions and an approval at the general meeting of shareholders. See Item 6.A. “Directors and Senior Management—Board of Directors” and Item 16.G. “Corporate Governance—The Act on the Management of Public Institutions.”
Item 4.B. Business Overview
Introduction
We are an integrated electric utility company engaged in the transmission and distribution of substantially all of the electricity in Korea. Through our six wholly-owned generation subsidiaries, we also generate the substantial majority of electricity produced in Korea. As of December 31, 2025, we and our generation subsidiaries owned approximately 53.4% of the total electricity generation capacity in Korea (excluding plants generating electricity primarily for private or emergency use). In 2025, we sold to our customers 549,417 gigawatt-hours of electricity. We purchase electricity principally from our generation subsidiaries and, to a lesser extent, from independent power producers. Of the 545,192 gigawatt-hours of electricity we purchased in 2025, 33.2% was generated by KHNP, our wholly-owned nuclear and hydroelectric power generation subsidiary, 32.7% was generated by our wholly-owned five non-nuclear generation subsidiaries and 34.1% was generated by independent power producers that trade electricity to us through the cost-based pool system of power trading (excluding independent power producers that supply electricity under power purchase agreements with us). Our five non-nuclear generation subsidiaries are KOSEP, KOMIPO, KOWEPO, KOSPO and EWP, each of which is wholly owned by us and is incorporated in Korea. We derive substantially all of our revenues and profit from Korea, and substantially all of our assets are located in Korea.
Our revenues are closely tied to demand for electricity in Korea. In 2025, the gross domestic product, or GDP, increased by 1.0% compared to 2024, whereas the demand for electricity in Korea decreased by 0.07% compared to 2024. In 2025, we realized sales of Won 96,568 billion and net profit of Won 8,667 billion, compared to sales of Won 92,578 billion and net profit of Won 3,622 billion in 2024.
Strategy
We established our 2035 medium to long-term strategy to realize our vision of becoming a “Global Energy & Solution Leader”, driving transformation in the energy industry ecosystem. We plan to achieve this by pursuing the following eight strategic initiatives. Through these initiatives, we aim to provide better value to various stakeholders, including our country, customers and society. More specifically, our target for the country is to contribute to the achievement of national policy targets for energy transition such as establishing the foundation for carbon neutrality and to support sustainable growth by building a reliable and resilient national power grid. Our target for customers is to expand clean energy supply by enhancing digital-based customer interaction and renewable energy transactions. Our target for society is to create a future-oriented energy market by developing and commercializing carbon-neutral technology through collaboration with major stakeholders. Our eight strategic initiatives to achieve such targets are:
• Establish a power grid system that can further contribute to achieving carbon neutrality. We plan to contribute to achieving carbon neutrality in 2050 with power grid innovation. We aim to secure grid capability for connecting renewable energy units by proactively constructing power facilities based on forecast and further enhance grid stability with intelligent and advanced grid system.
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• Expand clean energy and promote strategic demand response. We plan to establish a foundation for expanding renewable energy by cooperating with our subsidiaries and independent power producers. Also, we aim to improve demand-side energy efficiency by collaborating with demand management business operators.
• Lead future energy market and improve sales competitiveness. We plan to create reliable and resilient electricity system to achieve competency in future electricity market. We will also strive to expand our customized services through digital technologies and power data and establish reasonable and sustainable cost-based tariff system.
• Lead platform-based new businesses. We plan to expand charging infrastructure and foster transition into electric vehicles. We also aim to improve energy efficiency by boosting operation of dispersed energy resources in a form of energy platform business.
• Transform overseas business portfolio to focus on eco-friendly projects and core competencies. We plan to end our overseas coal-fired generation projects and switch substantial amount of our overseas business portfolio into eco-friendly projects. We aim to improve our competency and profitability by strengthening our overseas business capacity.
• Secure future technologies and build a research and development (“R&D”) ecosystem. We plan to secure core technologies necessary for achieving carbon neutrality with aggressive R&D investment. In addition, we aim to introduce an R&D system based on collaboration among industries, universities and research institutes to establish a foundation for technological innovation and enhance our R&D capability.
• Promote digitalization in overall supply chain. We aim to improve work efficiency and strengthen stability by introducing the latest digital technology and infrastructure to our business environment and developing a business model with new customer services based on data platforms.
• Establish a highly reliable and highly efficient management system with respect to human beings and environment. We plan to establish a comprehensive ESG management system that promotes environment, safety and coexistence. Also, we aim to enhance our financial stability by pursuing management efficiency and stable profit structure.
Government Ownership and Our Interactions with the Government
The KEPCO Act requires that the Government own at least 51% of our capital stock. Direct or indirect ownership of more than 50% of our outstanding common voting stock enables the Government to control the approval of certain corporate matters which require a shareholders’ resolution, including approval of dividends. The rights of the Government and Korea Development Bank as holders of our common stock are exercised by the Ministry of Trade, Industry and Resources in consultation with the Ministry of Finance and Economy. 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 fair operating costs, make capital investments and recoup a fair return on capital invested by us, as well as the Government’s overall policy considerations, such as inflation. See Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.”
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In addition, pursuant to the Basic Plan determined by the Government, we and our generation subsidiaries have made, and plan to make, substantial expenditures for the construction of generation plants and other facilities to meet demand for electric power. See Item 5.B. “Liquidity and Capital Resources—Capital Requirements.”
Restructuring of the Electric Power Industry in Korea
On January 21, 1999, the Ministry of Trade, Industry and Resources published the Restructuring Plan. The overall objectives of the Restructuring Plan consist of: (i) introducing competition and thereby increasing efficiency in the Korean electric power industry, (ii) ensuring a long-term, inexpensive and stable electricity supply, and (iii) promoting consumer convenience through the expansion of consumer choice.
The following provides further details relating to the Restructuring Plan.
Phase I
During Phase I, which served as a preparatory stage for Phase II and lasted from the announcement of the Restructuring Plan in January 1999 until April 2001, we undertook steps to split our generation business units off into one wholly-owned nuclear generation subsidiary (namely, KHNP) and five wholly-owned non-nuclear generation subsidiaries (namely, KOSEP, KOMIPO, KOWEPO, KOSPO and EWP), each with its own management structure, assets and liabilities. These steps were completed upon approval at our shareholders’ meeting in April 2001. 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.
Since the implementation of Phase I, we have had a substantial monopoly over electricity transmission and distribution in Korea. Although our ownership percentage of our generation subsidiaries will depend on further adjustments to the Restructuring Plan to be adopted by the Government, we plan to retain 100% ownership of our transmission and distribution business.
Phase II
At the outset of Phase II in April 2001, the Government introduced a cost-based competitive bidding pool system under which we purchase power from our generation subsidiaries and other independent power producers for transmission and distribution to customers. For a further description of this system, see “—Purchase of Electricity—Cost-based Pool System” below.
Pursuant to the Electric Utility Act amended in December 2000, the Government established the Korea Power Exchange in April 2001. The primary function of the Korea Power Exchange is to deal with the sale of electricity and implement regulations governing the electricity market to allow for electricity distribution through a competitive bidding process. The Government also established the Korea Electricity Commission in April 2001 to regulate the Korean electric power industry and ensure fair competition among industry participants. To facilitate this goal, the Korea Power Exchange established the Electricity Market Rules relating to the operation of the bidding pool system. To amend the Electricity Market Rules, the Korea Power Exchange must have the proposed amendment reviewed by the Korea Electricity Commission and then obtain the approval of the Ministry of Climate, Energy and Environment.
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.
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Privatization of Generation Subsidiaries
In April 2002, the Ministry of Trade, Industry and Resources released the basic privatization plan for five of our generation subsidiaries other than KHNP. Pursuant to this plan, we commenced the process of selling our equity interest in KOSEP in 2002. According to the original plan, this process was, in principle, to take the form of a sale of management control, potentially supplemented by an initial public offering as a way of broadening the investor base. In November 2003, KOSEP submitted its application to the Korea Exchange for a preliminary screening review, which was approved in December 2003. However, in June 2004, KOSEP made a request to the Korea Exchange to delay its stock listing due to unfavorable stock market conditions at that time.
In accordance with the Proposal for Adjustment of Functions of Public Institutions (Energy Sector) announced by the Government in June 2016, we considered a sale in the public market of a minority of our shares in our five non-nuclear generation subsidiaries, KEPCO KDN and KHNP gradually. However, the planned sales have been put on hold, primarily due to prevailing market conditions. In any event, we plan to maintain a controlling stake in each of these subsidiaries.
Suspension of the Plan to Form and Privatize Distribution Subsidiaries
In 2003, the Government established a Tripartite Commission consisting of representatives of the Government, leading businesses and labor unions in Korea to deliberate on ways to introduce competition in electricity distribution, such as by forming and privatizing new distribution subsidiaries. In 2004, the Tripartite Commission recommended against pursuing such privatization initiatives but instead creating independent business divisions within us to improve operational efficiency through internal competition. Following the adoption of such recommendation by the Government in 2004 and further studies by Korea Development Institute, in 2006 we created nine “strategic business units” (which, together with our other business units, were subsequently restructured into 14 such units in February 2012) that have a greater degree of autonomy with respect to management, financial accounting and performance evaluation while having a common focus on increasing profitability.
Initiatives to Improve the Structure of Electricity Generation
In August 2010, the Ministry of Trade, Industry and Resources announced the Proposal for Improvement in the Structure of the Electric Power Industry in order to resolve uncertainty related to restructuring plans for the electric power industry and maintain competitiveness of the electric power industry. Key initiatives of the proposal included the following: (i) maintain the current structure of having six generation subsidiaries and designate the six generation subsidiaries as market-oriented public enterprises, pursuant to the Act on the Management of Public Institutions in order to foster competition among the generation subsidiaries and promote efficiency in their operations, (ii) clarify the scope of the business of us and the six generation subsidiaries (namely, that we shall manage the financial structure and governance of the six generation subsidiaries and nuclear power plant and overseas resources development projects, while the six generation subsidiaries will have greater autonomy with respect to construction and management of generation units and procurement of fuel), (iii) create a nuclear power export business unit to systematically enhance our capabilities to win projects involving the construction and operation of nuclear power plants overseas, (iv) further rationalize the electricity tariff by adopting a fuel-cost based tariff system in 2011 and a voltage-based tariff system in a subsequent year, and (v) create separate accounting systems for electricity generation, transmission, distribution and sales with the aim of introducing competition in electricity sales in the intermediate future. The fuel-cost based tariff system went into effect on July 1, 2011 but the Ministry of Trade, Industry and Resources issued a hold order on July 29, 2011 and subsequently informed us it needs to be reassessed in light of the circumstances.
In January 2011, the Ministry of Finance and Economy created a “joint cooperation unit” consisting of officers and employees selected from the five thermal power generation subsidiaries in order to reduce inefficiencies in areas such as fuel transportation, inventories, materials and equipment and construction, etc. and
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allow the thermal power generation subsidiaries to continue utilizing the benefits of economy of scale after split off of our generation business units into separate subsidiaries. The purpose of the joint cooperation unit was to give greater autonomy to the generation subsidiaries with regard to power plant construction and management and fuel procurements, and thereby enhance efficiency in operating power plants. The main functions of the joint cooperation unit are as follows: (i) maintain inventories of bituminous coal through volume exchanges and joint purchases, (ii) reduce shipping and demurrage expenses through joint operation and distribution of dedicated vessels, (iii) reduce costs by sharing information on generation material inventories and (iv) sharing human resources among the five thermal power generation subsidiaries for construction projects, among other things.
Furthermore, in January 2011 the six generation subsidiaries were officially designated as “market-oriented public enterprises,” whereupon the President of Korea appoints the president and the statutory auditor of each such subsidiary; the selection of non-standing directors of each such subsidiary is subject to approval by the Minister of the Ministry of Finance and Economy; the president of each such subsidiary is required to enter into a management contract directly with the Minister of the Ministry of Climate, Energy and Environment; and the Public Enterprise Management Evaluation Team which is established by the Committee for Management of Public Institutions conducts performance evaluation of such subsidiaries. Previously, our president appointed the president and the statutory auditor of each such subsidiary; the selection of non-standing directors of each such subsidiary was subject to approval by our president; the president of each such subsidiary entered into a management contract with our president; and our evaluation committee conducted performance evaluation of such subsidiaries. For further details of the impact of the designation of our generation subsidiaries as “market-oriented public enterprises,” see Item 16.G. “Corporate Governance – The Act on the Management of Public Institutions.”
Proposal for Adjustment of Functions of Public Institutions (Energy Sector)
In June 2016, the Government announced the Proposal for Adjustment of Functions of Public Institutions (Energy Sector) for the purpose of streamlining the operations of Government-affiliated energy companies by discouraging them from engaging in overlapping or similar businesses with each other, reducing non-core assets and activities and improving management and operational efficiency. The initiatives contemplated in this proposal that would affect us and our generation subsidiaries include the following: (i) the generation companies should take on greater responsibilities in overseas resource exploration and production projects as these involve procurement of fuels necessary for electricity generation while fostering cooperation among each other through closer coordination, (ii) KHNP should take a greater role in export of nuclear technology, and (iii) the current system of retail sale of electricity to end-users should be liberalized to encourage more competition. In accordance therewith, we transferred a substantial portion of our assets and liabilities in our overseas resource business to our generation subsidiaries as of December 31, 2016. In addition, this Proposal contemplated selling a minority stake in our generation subsidiaries and KEPCO KDN, but the planned sales have been put on hold, as discussed above in “ –Privatization of Generation Subsidiaries.”
Purchase of Electricity
Cost-based Pool System
Since April 2001, the purchase and sale of electricity in Korea is required to be made through the Korea Power Exchange, which is a statutory not-for-profit organization established under the Electric Utility Act responsible for setting the price of electricity, handling the trading and collecting relevant data for the electricity market in Korea. The suppliers of electricity in the Korean electricity market consist of our six generation subsidiaries, which were split-off from us in April 2001, and independent power producers, which numbered 44 (excluding 7,355 renewable energy producers) as of December 31, 2025. We distribute electricity purchased through the Korea Power Exchange to end users.
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Our Relationship with the Korea Power Exchange
The key features of our relationship with the Korea Power Exchange include the following: (i) we and our six generation subsidiaries are member corporations of the Korea Power Exchange and collectively own 100% of its share capital, (ii) three of the 11 members of the board of directors of the Korea Power Exchange are currently our or our subsidiaries’ employees, and (iii) one of our employees is currently a member in three of the key committees of the Korea Power Exchange that are responsible for evaluating the costs of producing electricity, making rules for the Korea Power Exchange and gathering and disclosing information relating to the Korean electricity market.
Notwithstanding the foregoing relationships, however, we do not have control over the Korea Power Exchange or its policies since, among others, (i) the Korea Power Exchange, its personnel, policies, operations and finances are closely supervised and controlled by the Government, namely through the Ministry of Climate, Energy and Environment, and are subject to a host of laws and regulations, including, among others, the Electric Utility Act and the Act on the Management of Public Institutions, as well as the Articles of Incorporation of the Korea Power Exchange, (ii) we are entitled to elect no more than one-third of the Korea Power Exchange directors, and our representatives represent only a minority of its board of directors and committees (with the other members being comprised of representatives of the Ministry of Climate, Energy and Environment, 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 within our company or our generation subsidiaries. Consistent with this view, the Finance Supervisory Service issued a ruling in 2005 that stated that we can exercise significant influence by virtue of right to nominate directors to the board of directors of the entity though the Government regulates the Company’s ability to make operating and financial decisions over the entity.
Pricing Factors
The price of electricity in the Korean electricity market is determined principally based on the cost of generating electricity using a system known as the “cost-based pool” system. Under the cost-based pool system, the price of electricity has two principal components, namely the marginal price (representing the variable cost of generating electricity) and the capacity price (representing the fixed cost of generating electricity).
Under the merit order system, the electricity purchase allocation, the system marginal price (as described below) and the final allocation adjustment are automatically determined based on an objective formula. The variable cost (including the adjusted coefficient as described below) and the capacity price are determined in advance of trading by the Cost Evaluation Committee, which is comprised of representatives from the Ministry of Climate, Energy and Environment, the Korea Power Exchange, us, generation companies, scholars and researchers (the “Cost Evaluation Committee”). Accordingly, a supplier of electricity cannot exercise control over the merit order system or its operations to such supplier’s strategic advantage.
Marginal Price
The primary purpose of the marginal price is to compensate the generation companies for fuel costs, which represents the principal component of the variable costs of generating electricity. We currently refer such marginal price as the “system marginal price.”
The system marginal price represents, in effect, the marginal price of electricity at a given hour at which the projected demand for electricity and the projected supply of electricity for such hour intersect, as determined by the merit order system, which is a system used by the Korea Power Exchange to allocate which generation units will supply electricity for which hour and at what price. To elaborate, the projected demand for electricity for a given hour is determined by the Korea Power Exchange based on a forecast made one day prior to trading, and such forecast takes into account, among others, historical statistics relating to demand for electricity nationwide
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by day and by hour, season 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. On September 1, 2022, the trading system was further developed to facilitate optimal decisions on market prices and allow plans for generating power to be made with more sophistication, by taking into account thermal constraints, power transmission constraints and reserving power from the stage of making the generation plan.
Under the merit order system, the generation unit with the lowest variable cost of generating 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 on a monthly basis and reflected in the following month based on the fuel costs two months prior to such determination. The purpose of the merit order system is to encourage generation units to reduce its electricity generation costs by making its generation process more efficient, sourcing fuels from most cost-effective sources or adopting other cost savings programs.
The final allocation of electricity supply is further adjusted on the basis of other factors, including the proximity of a generation unit to the geographical area to which power is being supplied, network and fuel constraints and the amount of power loss. This adjustment mechanism is designed to adjust for transmission losses in order to improve overall cost-efficiency in the transmission of electricity to end-users.
The price of electricity at which our generation subsidiaries sell electricity to us is determined using the following formula:
Variable cost + [System marginal price – Variable cost] * Adjusted coefficient
An adjusted coefficient applies in principle to all generation units operated by our generation subsidiaries and the coal-fired generation units operated by independent power producers. The adjusted coefficient applicable to the generation units operated by our generation subsidiaries is determined based on considerations of, among others, electricity tariff rates and the relative fair returns on investment in respect of us compared to our generation subsidiaries. The purpose of the adjusted coefficient here is to prevent electricity trading from resulting in undue imbalances as to the relative financial results among generation subsidiaries as well as between us (as the purchaser of electricity) and our generation subsidiaries (as sellers of electricity). Such imbalances may arise from excessive profit taking by base load generators (on account of their inherently cheaper fuel cost structure compared to non-base load generators) as well as from fluctuations in fuel prices (it being the case that during times of rapid and substantial rises in fuel costs which are not offset by corresponding rises in electricity tariff rates charged by us to end-users, on a non-consolidated basis our profitability will decline compared to that our generation subsidiaries since our generation subsidiaries are entitled to sell electricity to us at cost plus a guaranteed margin). In comparison, the adjusted coefficient applicable to the coal-fired generation units operated by independent power producers is determined to enable such independent power producers to recover the total costs of building and operating such units.
The adjusted coefficient is determined by the Cost Evaluation Committee in principle on an annual basis, although in exceptional cases driven by external or structural factors such as rapid and substantial changes in fuel costs, adjustments to electricity tariff rates or changes in the electricity pricing structure, the adjusted coefficient may be adjusted on a quarterly basis.
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Capacity Price
In addition to payment in respect of the variable cost of generating electricity, generation units receive payment in the form of capacity price, the purpose of which is to compensate them for the fixed costs of constructing generation facilities, provide incentives for construction of new generation units and maintain reliability of the nationwide electricity transmission network.
The capacity price is determined by the Cost Evaluation Committee as a function of the following factors: (i) reference capacity price, (ii) reserve capacity factor, (iii) time-of-the-day capacity coefficient and (iv) performance capacity factor introduced since June 2022 instead of fuel switching factor which was effective since October 2016. The time-of-the-day capacity coefficient are determined annually before the end of December for the subsequent twelve-month period. The reference capacity price, reserve capacity factor and the fuel switching factor are determined annually before the end of June for the subsequent twelve-month period.
The reference capacity price refers to the Won amount per kilowatt-hour payable annually for annualized available capacity indicated in the bids submitted the day before trading (provided that such capacity is actually available on the relevant day of trading), and is determined based on the construction costs and maintenance costs of a standard generation unit and related transmission access facilities, and a base rate for loading electricity. Prior to October 2016, the same reference capacity price applied uniformly to all generation units. Since October 2016, the reference capacity price applies differentially to each generation unit depending on the start year of its commercial operation. Also, since December 2022, we have reduced margins from the reference capacity price applied to all generation units reflecting the reserve capacity. Accordingly, the reference capacity price currently ranges from Won 10.68 to 13.71 per kilowatt-hour.
The reserve capacity factor relates to the requirement to maintain a standard capacity reserve margin around 12% in order to prevent excessive capacity build-up as well as induce optimal capacity investment at the regional level. The capacity reserve margin is the ratio of peak demand to the total available capacity. Under this system, generation units in a region where available capacity is insufficient to meet demand for electricity as evidenced by failing to meet the standard capacity reserve margin receive increased capacity price. Conversely, generation units in a region where available capacity exceeds demand for electricity as evidenced by exceeding the standard capacity reserve margin receive reduced capacity price. Since October 2016, the reserve capacity factor also factors in the transmission loss per generation unit in order to favor transmission of electricity from a nearby generation unit.
The time-of-the-day capacity coefficient allows hourly and seasonal adjustments in order to incentivize our generation subsidiaries to operate their generation facilities at full capacity during periods of highest demand. For example, the capacity price paid differs depending on whether the relevant hour is an “on-peak” hour, a “mid-peak” hour or an “off-peak” hour (the capacity price being highest for the on-peak hours and lowest for the off-peak hours) and the capacity price paid is highest during the months of January, July and August when electricity usage is highest due to weather conditions.
The fuel switching factor, which was introduced in October 2016 to promote environmental sensitivities to climate change, has been changed into the performance capacity factor since June 2022 to comply with the market trend that differentially compensates the capacity price for the contribution to electricity system and operational flexibility of generation units. In addition, in January 2022, the environmental contribution factor was excluded from the fuel switching factor and instead reflected in the unit thermal cost of each generation unit in order to effectively respond to the greenhouse gas reduction.
Other than subject to the aforementioned variations, the same capacity pricing mechanism applies to all generation units regardless of fuel types used.
In the Ninth Basic Plan, the Government announced its plans to introduce real-time electricity trading market and supplementary service market, which have been upgraded to ensure appropriate valuation and
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compensation for supplementary energy sources and responses to volatility of renewable energy. Supplementary energy sources refer to power generators independent of us. The reorganization of the market system has been gradually implemented, starting with the implementation of a trading system reflecting constraints and reserves of electricity system in September 2022. In August 2023, we presented the design of the trading system, which would introduce real-time electricity trading market through which supplementary services can be traded. The new trading system was implemented in Jeju Province since June 2024. Under the new trading system, renewable energy generators exceeding one megawatt (mandatory for three megawatts) would be able to participate in market bidding.
Vesting Contract System
In May 2014, the Electric Utility Act was amended to introduce a “vesting contract” system in determining the price and quantity of electricity to be sold and purchased between the purchaser of electricity (namely, us) and the sellers of electricity (namely, our generation subsidiaries and independent power producers). Under the vesting contract system, electricity generators using base load fuels (such as nuclear, coal, hydro and by-product gas) at a particular generation unit were to be required to enter into a contract with the purchaser of electricity, which specifies, among other things, the quantity of electricity to be generated and sold at a particular generation unit and the price at which such electricity is sold, subject to certain adjustments.
The vesting contract system was introduced principally to prevent excessive profit-taking by low-cost producers of electricity using base load fuels (such as nuclear, coal, hydro and by-product gas) by replacing the adjusted coefficient as the basis for determining the guaranteed return to generation companies, as well as to enhance the stability of electricity supply by requiring long-term contractual arrangements for the purchase and sale of electricity and promote cost savings, productivity enhancements and operational efficiency by providing incentives and penalties depending on the degree to which the generation companies could supply electricity at costs below the contracted electricity prices.
In order to minimize undue shock to the electricity trading market in Korea, the vesting contract system was to be implemented in phases starting with by-product gas-based electricity in 2015. The vesting contract system for by-product gas-based electricity ended in 2020, and there are no active contracts remaining as of the end of 2025. However, we are in discussion with the Government to potentially extend the vesting contract system to wider base load fuels, including nuclear.
Power Trading Results
The results of power trading, as effected through the Korea Power Exchange, for us and our generation subsidiaries and independent power producers in 2025 are as follows:
Items Volume (Gigawatt hours) Percentage of Total Volume (%) Sales to KEPCO(2) (in billions of Won) Percentage of Total Sales (%) Unit Price (Won/kWh)
Generation Companies KHNP 181,051 33.2 14,924 22.0 82.43
KOSEP 36,791 6.7 4,927 7.3 133.93
KOMIPO 36,468 6.7 5,476 8.1 150.15
KOWEPO 35,885 6.6 5,167 7.6 143.99
KOSPO 36,306 6.7 5,861 8.6 161.43
EWP 32,569 6.0 4,752 7.0 145.90
Others (1) 186,121 34.1 26,839 39.5 144.20
Total 545,192 100.0 67,945 100.0 124.63
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Items Volume (Gigawatt hours) Percentage of Total Volume (%) Sales to KEPCO(2) (in billions of Won) Percentage of Total Sales (%) Unit Price (Won/kWh)
Energy Sources Nuclear 174,938 32.1 13,836 20.4 79.09
Bituminous coal 162,931 29.9 22,495 33.1 138.06
Anthracite coal 1,199 0.2 143 0.2 119.60
Oil 159 0.0 61 0.1 384.00
LNG/Combined-cycle 159,437 29.2 25,213 37.1 158.14
Renewables 36,486 6.7 4,623 6.8 126.70
Hydro 3,078 0.6 405 0.6 131.64
Pumped storage 4,399 0.8 871 1.3 197.91
Others 2,565 0.5 298 0.4 116.26
Total 545,192 100.0 67,945 100.0 124.63
Load Base load 339,068 62.2 36,474 53.7 107.57
Non-base load 206,124 37.8 31,471 46.3 152.68
Total 545,192 100.0 67,945 100.0 124.63
Notes:
(1) Others represent independent power producers that trade electricity through the cost-based pool system of power trading (excluding independent power producers that supply electricity under power purchase agreements with us).
(2) Based on the payment made by us through Korea Power Exchange.
Power Purchased from Independent Power Producers under Power Purchase Agreements
In 2025, we purchased an aggregate of 26,358 gigawatt hours of electricity generated by independent power producers under existing power purchase agreements. These independent power producers had an aggregate generation capacity of 21,300 megawatts as of December 31, 2025.
Power Generation
As of December 31, 2025, we and our generation subsidiaries had a total of 860 generation units, including nuclear, thermal, hydroelectric and internal combustion units, representing total installed generation capacity of 83,555 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.
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The table below sets forth as of and for the year ended December 31, 2025 the number of units, installed capacity and the average capacity factor for each type of generating facilities owned by us and our generation subsidiaries.
Number of Units Installed Capacity (1) Average Capacity Factor (2)
(Megawatts) (%)
Nuclear 26 26,050 84.6
Thermal:
Coal 52 32,059 50.4
LNG — — —
Total thermal 52 32,059 (7) 50.4
Internal combustion 209 97 39.0
Combined-cycle(3) 121 17,612 24.4
Integrated gasification combined cycle(4) 2 346 49.6
Hydroelectric(5) 61 5,350 12.5
Wind 17 189 4.7
Solar 324 537 13.4
Fuel cell 38 520 76.4
Bio 9 785 46.0
Others(6) 1 10 70.2
Total 860 83,555 51.7
Notes:
(1) Installed capacity represents the level of output that may be sustained continuously without significant risk of damage to plant and equipment.
(2) Average capacity factor represents the total number of kilowatt-hours of electricity generated in the indicated period divided by the total number of kilowatt-hours that would have been generated if the generation units were continuously operated at installed capacity, expressed as a percentage.
(3) Involves generation through gas and oil.
(4) Involves generation through coal and gasified coal.
(5) Includes generation through pumped storage.
(6) Includes waste-to-energy.
(7) Installed Capacity for Coal excludes the 500 megawatts of installed capacity of Taean #1 which was decommissioned as of January 1, 2026.
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. 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.
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
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power production capacity at approximately the level at which demand for electricity is continuously stable. During those times when actual demand exceeds the usual level of electricity supply from nuclear power, we rely on units fired by fossil fuels and hydroelectric units, which can be started and shut down more quickly and efficiently than nuclear units, to meet the excess demand. Bituminous coal has been the least expensive thermal fuel per kilowatt-hour of electricity produced, and therefore our use of bituminous coal for generation takes the largest portion in excess of the stable demand level, except for meeting short-term surges in demand which require rapid start-up and shutdown. Thermal units fired by LNG, hydroelectric units and internal combustion units are the most efficient types of units for rapid start-ups and shutdowns, and therefore we use such units principally to meet short-term surges in demand. Anthracite coal is a less efficient fuel source than bituminous coal in terms of electricity output per unit cost.
Our generation subsidiaries have constructed and operated thermal and internal combustion units in order to help meet power demand. Subject to market conditions, our generation subsidiaries plan to continue to add additional thermal (other than coal-fired) and internal combustion units. These units generally take less time to complete construction than nuclear units.
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.
2021 2022 2023 2024 2025 % of 2025 Gross Generation (1)
(in gigawatt hours, except percentages)
Electricity generated by us and our generation subsidiaries:
Nuclear 158,015 176,054 180,494 188,754 184,693 31.0
Coal 172,419 164,271 150,855 140,805 141,898 23.8
Oil 1,494 352 — — — —
LNG 1,177 1,377 878 586 — —
Internal combustion 491 570 390 329 331 0.1
Combined-cycle 53,609 52,243 45,949 45,960 37,671 6.3
Hydro 4,762 5,043 5,089 6,200 5,888 1.0
Wind 195 219 190 147 77 0.0
Solar 493 354 373 526 630 0.1
Fuel cells 1,993 2,470 2,932 3,596 3,491 0.6
Others(2) 5,725 5,488 4,420 5,531 4,914 0.8
Total generation by us and our generation subsidiaries 400,373 408,441 391,570 392,436 379,593 63.7
Electricity generated by IPPs:
Thermal 140,983 142,992 149,092 150,889 158,036 26.5
Hydro, other renewable and others 35,453 42,967 47,384 52,276 58,020 9.7
Total generation by IPPs 176,436 185,959 196,476 203,165 216,056 36.3
Gross generation 576,809 594,400 588,046 595,601 595,649 100.0
Auxiliary use(3) 21,254 22,081 20,976 21,900 21,138 3.5
Pumped-storage(4) 4,856 4,912 4,924 6,091 5,798 1.0
Total net generation(5) 550,699 567,407 562,146 567,610 568,713 95.5
Transmission and distribution losses(6) 19,424 20,020 19,813 19,966 19,969 3.52
IPPs = Independent power producers
Notes:
(1) Unless otherwise indicated, percentages are based on gross generation.
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(2) From June 2024, dispatchable renewable energy in Jeju is categorized as others.
(3) Auxiliary use represents electricity consumed by generation units in the course of generation.
(4) 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.
(5) Total net generation represents gross generation minus auxiliary and pumped-storage use.
(6) Transmission and distribution losses rate represents total transmission and distribution losses divided by total net generation.
The table below sets forth our total capacity at the time of peak usage, and peak and average loads during, the indicated periods.
2021 2022 2023 2024 2025
(Megawatts)
Total capacity 131,330 137,938 142,567 149,179 155,385
Peak load 91,141 94,509 93,615 97,115 95,951
Average load 65,789 67,853 67,129 67,805 67,996
Korea Hydro & Nuclear Power Co., Ltd.
We commenced nuclear power generation activities in 1978 when our first nuclear generation unit, Kori #1, began commercial operation. On April 2, 2001, all of our nuclear and hydroelectric power generation assets and liabilities were transferred to KHNP.
At KHNP’s five power plant complexes, Kori, Saeul, Wolsong, Hanbit and Hanul (each complex located in Busan, Ulsan, Gyeongju, Yonggwang and Ulchin, respectively), it operates 26 nuclear generation units, among which Kori #2,3,4 and Hanbit #1 have been shut down since April 2023, September 2024, August 2025, and December 2025 respectively. KHNP submitted a safety evaluation report to the NSSC in April 2022 to seek approval for an extension of the life of Kori #2, whose life extension was finally approved in November 2025. KHNP also operates 47 hydroelectric generation units including 16 pumped storage hydro generation units as well as 69 solar generation units and one wind generation unit as of December 31, 2025.
The table below sets forth the number of units and installed capacity as of December 31, 2025 and the average capacity factor by types of generation units in 2025 including Kori #2,3,4 and Hanbit #1.
Number of Units Installed Capacity (1) Average Capacity Factor (2)
(Megawatts) (%)
Nuclear 26 26,050 84.61
Hydroelectric 47 5,307.48 12.50
Solar 69 87.68 14.09
Wind 1 0.75 0
Total 143 31,445.91 71.79
Notes:
(1) Installed capacity represents the level of output that may be sustained continuously without significant risk of damage to plant and equipment.
(2) Average capacity factor represents the total number of kilowatt-hours of electricity generated in the indicated period divided by the total number of kilowatt-hours that would have been generated if the generation units were continuously operated at installed capacity, expressed as a percentage.
KHNP commenced commercial operation of Saeul #1 (formerly named as Shin-Kori #3), with a 1,400 megawatt capacity, in December 2016, and Saeul #2 (formerly named as Shin-Kori #4) began commercial operations on August 2019. KHNP commenced commercial operation of Shin-Hanul #1 and Shin-Hanul #2 in
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December 2022 and April 2024, respectively. KHNP is currently building two additional nuclear generation units at Saeul complexes, each with a 1,400 megawatts capacity. KHNP expects to complete these units by 2026 and 2027. In June 2018, the board of directors of KHNP decided to retire Wolsong #1 unit earlier than planned due to comprehensive evaluation of the unit’s economic viability and regional sentiment of its continuing operation. The initial phase of the decommissioning of Kori #1, which primarily involves safety inspections and the removal of spent nuclear fuels, has begun after its permanent shutdown in June 2017. In April 2022, KHNP submitted a safety evaluation report to the NSSC to seek approval for an extension of the life of Kori #2, which has been shut down since April 8, 2023. Life extension of Kori #2 was approved in November 2025, after which operation resumed in April 2026.
Nuclear
The table below sets forth certain information with respect to the nuclear generation units of KHNP as of December 31, 2025.
Unit(4) Reactor Type (1) Reactor Design (2) Turbine and Generation (3) Commencement of Operations Installed Capacity Average Capacity Factor
(Megawatts) (%)
Kori #2 PWR W GEC 1983 650 0
Kori #3 PWR W GEC, Hitachi 1985 950 0
Kori #4 PWR W GEC, Hitachi 1986 950 101.5
Shin-Kori #1 PWR D, KEPCO E&C, W D, GE 2011 1,000 86.2
Shin-Kori #2 PWR D, KEPCO E&C, W D, GE 2012 1,000 90.3
Saeul #1 PWR D, KEPCO E&C, W D, GE 2016 1,400 84.7
Saeul #2 PWR D, KEPCO E&C, W D, GE 2019 1,400 85.9
Wolsong #2 PHWR AECL, H, K H, GE 1997 700 67.5
Wolsong #3 PHWR AECL, H H, GE 1998 700 74.2
Wolsong #4 PHWR AECL, H H, GE 1999 700 54.9
Shin-Wolsong #1 PWR D, KEPCO E&C, W D, GE 2012 1,000 101.7
Shin-Wolsong #2 PWR D, KEPCO E&C, W D, GE 2015 1,000 89.7
Hanbit #1 PWR W W, D 1986 950 108.3
Hanbit #2 PWR W W, D 1987 950 84.0
Hanbit #3 PWR H, CE, K H, GE 1995 1,000 83.6
Hanbit #4 PWR H, CE, K H, GE 1996 1,000 81.6
Hanbit #5 PWR D, CE, W, KEPCO E&C D, GE 2002 1,000 57.4
Hanbit #6 PWR D, CE, W, KEPCO E&C D, GE 2002 1,000 101.0
Hanul #1 PWR F A 1988 950 89.0
Hanul #2 PWR F A 1989 950 100.9
Hanul #3 PWR H, CE, K H, GE 1998 1,000 100.3
Hanul #4 PWR H, CE, K H, GE 1999 1,000 99.9
Hanul #5 PWR D, KEPCO E&C, W D, GE 2004 1,000 100.1
Hanul #6 PWR D, KEPCO E&C, W D, GE 2005 1,000 81.8
Shin-Hanul #1 PWR D, KEPCO E&C, W D, GE 2022 1,400 75.7
Shin-Hanul #2 PWR D, KEPCO E&C, W D, GE 2024 1,400 56.2
Total nuclear 26,050 84.6
Notes:
(1) “PWR” means pressurized light water reactor; “PHWR” means pressurized heavy water reactor.
(2) “W” means Westinghouse Electric Corporation (U.S.A.); “D” means Doosan Heavy Industries & Construction Co., Ltd.; “KEPCO E&C” means KEPCO Engineering & Construction Co., Inc.; “AECL” means Atomic Energy of Canada Limited (Canada); “H” means Hanjung; “K” means Korea Atomic Energy Research Institute; “CE” means Combustion Engineering (U.S.A.); “F” means Framatome (France).
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(3) “GEC” means General Electric Company (U.K.); “W” means Westinghouse Electric Corporation (U.S.A.); “A” means Alstom (France); “H” means Hanjung; “GE” means General Electric (U.S.A.); “D” means Doosan Heavy Industries & Construction Co., Ltd.; “Hitachi” means Hitachi Ltd. (Japan).
(4) Kori #1 was permanently shut down on June 18, 2017. On December 24, 2019, the NSSC approved the permanent shutdown of Wolsong #1. Saeul #1 and 2 were formerly named as Shin-Kori #3 and 4. Shin-Hanul #1 and #2 commenced operation on December 7, 2022 and April 5, 2024, respectively. Kori #2 has been shut down since April 8, 2023, and KHNP submitted a safety evaluation report to the NSSC in April 2022 to seek approval for an extension of its life. Life extension of Kori #2 was approved in November 2025. Kori #3 and #4 as well as Hanbit #1 have been shut down since September 2024, August 2025 and December 2025 respectively. Safety evaluation reports for life extension approval of these three units have also been submitted.
Under extended-cycle operations, nuclear units can be run continuously for periods longer than the conventional twelve-month period between scheduled shutdowns for refueling and maintenance. Since 1987, we have adopted the mode of extended-cycle operations for all of our pressurized light water reactor units and plan to use it for our newly constructed units. The duration of shutdown for fuel replacement, maintenance and the evaluation period for approval to start after maintenance was 1,291.7 days in the aggregate in 2025. In addition, KHNP’s nuclear units experienced an average of 0.08 unplanned shutdowns per unit in 2025. In the ordinary course of operations, KHNP’s nuclear units routinely experience damage and wear and tear, which are repaired during routine shutdown periods or during unplanned temporary suspensions of operations. No significant damage has occurred in any of KHNP’s nuclear reactors, and no significant nuclear exposure or release incidents have occurred at any of KHNP’s nuclear facilities since the first nuclear plant commenced operation in 1978.
Hydroelectric
The table below sets forth certain information relating to KHNP’s pumped-storage and hydroelectric business units, including the installed capacity as of December 31, 2025 and the average capacity factor in 2025.
Location of Unit Number of Units Classification Year Built Installed Capacity Average Capacity Factor
(Megawatts) (%)
Hwacheon 4 Dam waterway 1944 108.0 23.2
Chuncheon 2 Dam 1965 62.28 24.5
Euiam 2 Dam 1967 48.0 37.2
Cheongpyung 4 Dam 1943 140.1 27.3
Paldang 4 Dam 1973 120.0 39.4
Chilbo (Seomjingang) 3 Basin deviation 1945 35.4 31.0
Boseonggang 1 Basin deviation 1937 4.5 48.1
Kwoesan 1 Dam 1957 2.8 24.9
Anheung (GangLim) 1 Dam waterway 1978 0.48 24.9
Kangreung 2 Basin deviation 1991 82.0 0.0
Topyeong 1 Dam 2011 0.045 15.5
Muju 1 Dam 2003 0.4 16.4
Sancheong 1 Dam 2001 0.995 40.1
Yangyang 1 Dam 2005 1.4 22.7
Yangyang 1 Dam 2020 0.15 82.0
Yecheon 1 Dam 2011 0.9 14.8
Yecheon (Mini) 1 Dam 2018 0.025 77.5
Cheongpeoung 2 Pumped Storage 1980 400.0 7.2
Samrangjin 2 Pumped Storage 1985 600.0 9.8
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Location of Unit Number of Units Classification Year Built Installed Capacity Average Capacity Factor
(Megawatts) (%)
Muju 2 Pumped Storage 1995 600.0 11.0
Sancheong 2 Pumped Storage 2001 700.0 13.4
Yangyang 4 Pumped Storage 2006 1,000.0 10.7
Cheongsong 2 Pumped Storage 2006 600.0 5.6
Yecheon 2 Pumped Storage 2011 800.0 14.7
Total 47 5,307.48 12.5
Solar/Wind
The table below sets forth certain information, including the installed capacity as of December 31, 2025 and the average capacity factor in 2025, of the solar and wind power units of KHNP.
Location of Unit Classification Year Built Installed Capacity Average Capacity Factor
(Megawatts) (%)
Yonggwang Solar 2008-2021 21.56 14.65
Yecheon Solar 2012 2.01 13.88
Kori Wind 2008 0.75 0
Busan Solar 2017-2022 7.69 16.74
Gapyeong Solar 2017-2022 0.96 12.07
Chuncheon Solar 2021 0.10 12.99
Cheongsong Solar 2018-2024 5.28 8.45
Kwoesan Solar 2018 0.25 14.25
Boseonggang Solar 2018 1.99 11.94
Samrangjin Solar 2019 2.77 15.25
Yeoncheon Solar 2020 1.00 12.78
Jeju Solar 2020-2021 14.08 13.03
Gyeongju Solar 2020-2022 12.60 14.64
Ulsan Solar 2023 3.99 15.66
Sancheong Solar 2023 3.02 13.23
Asan Solar 2023-2025 3.00 14.34
Haman Solar 2024-2025 2.41 14.54
Hwaseong Solar 2024 1.62 14.93
Yeongcheon Solar 2024 0.71 16.06
Gyeongsan Solar 2024 0.25 13.98
Gumi Solar 2024 0.39 16.03
Changwon Solar 2024 2.00 14.95
Total 88.43 13.96
There has been a growing supply of renewable energy such as solar and wind power. However, as such sources of power are susceptible to weather, there has been a growing demand for more stable renewable energy such as pumped storage hydro generation, which allows for prompt on-and-off transition. Since the last construction in 2011 of Yecheon pumped storage unit, KHNP is currently in the process of building five new pumped storage units which are expected to have an aggregate generation capacity of 3.7 gigawatts. KHNP is expecting to complete construction of the new pumped storage units before 2036.
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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, 2025 and the average capacity factor and average fuel cost per kilowatt in 2025 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) (%) (Won)
Bituminous:
Samcheonpo #3, 4, 5, 6 30.2 2,120.0 52.12 79.58
Yeongheung #1, 2, 3, 4, 5, 6 16.7 5,080.0 49.20 73.42
Yeosu # 1, 2 11.8 668.6 51.42 97.73
Combined cycle and internal Combustion:
Bundang gas turbine #1,2,3,4,5,6,7,8; steam turbine #1, 2 32 922.1 30.32 174.65
Hydro, Solar and other renewable energy — 573.0 44.05 165.04
Total 25.7 9,363.7 47.84 146.74
Korea Midland Power Co., Ltd.
The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2025 and the average capacity factor and average fuel cost per kilowatt in 2025 based upon the net amount of electricity generated, of KOMIPO.
Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Bituminous:
Boryeong #3, 4, 5, 6, 7, 8 27.4 3,050.0 58.92 75.05
Shin Boryeong #1, 2 8.5 2,038.1 57.4 70.75
Shin Seocheon #1 4.6 1,018.0 41.6 88.58
Combined-cycle and internal combustion:
Boryeong gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3 26.8 1,350.0 5.3 182.09
Incheon gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2, 3 16.9 1,462.5 21.0 152.58
Seoul gas turbine #1, 2; steam turbine #1, 2 6.4 738.3 39.2 149.74
Jeju gas turbine #1, 2; steam turbine #1, 2 7.5 228.7 39.7 147.48
Sejong gas turbine #1, 2; steam turbine #1 12.2 530.4 27.3 172.77
Jeju Internal Combustion Engine #1,2 18.6 80.0 1.7 301.51
Bio Oil:
Jeju #2, 3 25.5 150.0 35.4 356.42
Wind:
Yangyang #1, 2 19.6 3.0 0.0 —
Sejong Maebongsan 19.5 8.8 0.0 —
Jeju Sangmyung 9.4 21.0 17.2 3.33
Combined heat and power:
Wonju #1 10.7 10.0 70.4 81.81
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Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Hydroelectric:
Boryeong 16.9 7.5 17.6 —
Shin Boryeong 9.3 5.0 33.9 —
Shin Seocheon 4.6 2.6 8.3 —
Photovoltaic (“PV”) power and fuel cell generation:
Boryeong (PV) site 10.4 6.3 15.1 4.56
Shin Boryeong (PV) site 7.9 4.0 13.8 —
Seocheon (PV) site 7.9 3.8 12.9 —
Jeju (PV) site 8.8 4.3 11.1 —
Seoul (PV) site 14.4 1.3 14.2 —
Sejong (PV) site 14.2 1.3 7.5 —
Yeosu (PV) site 13.8 2.2 15.2 —
Incheon (PV) site 8.2 1.6 11.7 34.20
Incheon Asiad Sports(PV) site 1.6 2.7 11.4 —
Shin Boryeong (fuel cell) site Incheon (fuel cell) site 8.2 5.9 7.5 31.7 75.3 82.4 196.76 193.73
Seoul (fuel cell) site 5.3 6.0 91.9 135.59
Sejong (fuel cell) site 5.9 5.3 76.6 225.85
Total 17.23 10,781.9 40.88 96.57
Korea Western Power Co., Ltd.
The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2025 and the average capacity factor and average fuel cost per kilowatt in 2025 based upon the net amount of electricity generated, of KOWEPO.
Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Bituminous:
Taean #1, 2, 3, 4, 5, 6, 7, 8, 9, 10 22.0 6,100.0 48.9 107.56
LNG-fired:
Combined cycle:
Pyeongtaek #2 12.0 868.5 59.2 162.92
Gunsan 15.6 718.4 9.6 317.85
West Incheon 33.4 1,800.0 18.6 199.22
Combined heat:
Gimpo 2.4 350.4 24.5 236.97
Hydroelectric:
Taean 11.5 7.2 8.7 300.83
Solar:
Taean 9.4 17.2 6.5 401.65
Pyeongtaek 8.7 3.9 12.5 255.38
West Incheon 8.3 1.2 12.7 30.82
Gunsan 11.8 1.0 11.6 249.11
Samryangjin 17.7 3.0 13.1 134.80
Sejong City 13.6 5.0 11.7 417.24
Gyeonggi-do 12.8 2.5 12.7 303.76
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Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Yeongam 13.0 13.3 14.3 276.97
Goheung 6.7 1.0 14.5 388.10
Iwon-ho 1.6 43.0 13.1 190.50
Mando 1.4 3.6 14.2 175.57
Fuel Cell:
West Incheon 1 10.5 16.6 12.5 725.21
West Incheon 2 5.6 60.3 71.2 291.10
Cheonan Cheongsu 6.1 5.3 68.4 308.81
Hwaseong Namyang 4.6 20.2 83.5 281.60
Gyeonggi Uiwang 4.4 9.9 91.1 250.38
Daejeon Hakha 4.1 6.2 69.7 325.60
Icheon Gwango 3.1 9.6 90.1 249.11
Iksan 9.7 15.0 74.5 279.77
Gwangju Gwangsan 3.1 8.4 84.7 253.16
Hwaseong Namyang 2 2.9 19.8 91.2 250.78
Gyeonggi Gwangju 2.9 9.6 93.6 245.05
Mungyeong 1 2.1 15.0 92.7 242.63
Daegu Suseong 2.1 3.0 84.3 251.50
Wind Power:
Hwasun 10.1 16.0 11.6 251.46
Jangheung 4.3 18.0 11.7 435.87
Integrated gasification combined cycle:
Taean 10.7 346.3 49.7 225.35
Total 21.2 10,518.4 41.1 139.81
Korea Southern Power Co., Ltd.
The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2025 and the average capacity factor and average fuel cost per kilowatt in 2025 based upon the net amount of electricity generated, of KOSPO.
Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Bituminous:
Hadong #1, 2, 3, 4, 5, 6, 7, 8 24.6 4,000 52.5 75.8
Samcheok #1, 2 8.8 2,044 22.3 96.7
Combined cycle:
Shin Incheon #1, 2, 3, 4 28.4 1,800 25.4 145.2
Busan #1, 2, 3, 4 22.2 1,800 30.2 142.7
Yeongwol #1 15.2 848 1.1 208.6
Hallim 28.5 105 6.4 202.4
Andong #1 11.8 362 25.0 140.6
Nam Jeju #1 5.1 159 47.1 141.7
Shin Sejong #1 1.5 597 65.9 130.3
Bio Oil:
Nam Jeju #1, 2 19.0 200 50.5 327.6
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Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Wind power:
Hankyung 19.2 21 13.5 —
Seongsan 16.1 20 18.6 —
Solar 6.5 45 14.0 0.74
Small Hydropower 8.4 3 24.1 —
Fuel Cell 5.0 127 80.2 162.5
Total 19.3 12,129 35.8 109.5
Korea East-West Power Co., Ltd.
The table below sets forth, by fuel type, the weighted average age and installed capacity as of December 31, 2025 and the average capacity factor and average fuel cost per kilowatt in 2025 based upon the net amount of electricity generated, of EWP.
Weighted Average Age of Units Installed Capacity Average Capacity Factor Average Fuel Cost per kWh
(Years) (Megawatts) (%) (Won)
Bituminous:
Dangjin #1, 2, 3, 4, 5, 6, 7, 8, 9, 10 18.0 6,040 52.5 72.5
Anthracite:
Donghae #1, 2 26.8 400 38.5 125.2
Combined cycle:
Ulsan gas turbine #1, 2, 3, 4, 5, 6, 7, 8; steam turbine #1, 2, 3, 4 22.0 2,072 17.7 152.9
Ilsan gas turbine #1, 2, 3, 4, 5, 6; steam turbine #1, 2 31.8 900 16.8 194.6
Mini hydro, Photovoltaic, Fuel Cell, Wind-Power, Biomass: 4.6 280 33.0 92.2
Total 20.1 9,692 40.6 87.4
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Power Plant Remodeling and Recommissioning
Our generation subsidiaries supplement power generation capacity through remodeling or recommissioning of thermal units. Recommissioning includes installation of anti-pollution devices, modification of control systems and overall rehabilitation of existing equipment. The following table shows recent remodeling and recommissioning initiatives by our generation subsidiaries.
Power Plant Capacity Completed (Year) Extension Company
Taean #1 - 10 6,100 MW (500 MW×8, 1,050 MW×2) EP (1) upgrade (#5, 2009) EP upgrade (#6, 2010) EP upgrade (#2, 2016) EP upgrade (#1, 2017) EP upgrade (#3, 4, 2018) SCR (2) upgrade (#2, 4, 7, 2016) SCR upgrade (#1, 8, 2017) SCR upgrade (#3, 5, 6, 2018) FGD (5) upgrade (#1, 2017) FGD upgrade (#2, 3, 4, 2018) SCR upgrade(#7, 2022) SCR upgrade(#8, 2023) Anti-pollution KOWEPO
Boryeong #3 - 6 2,050 MW (#3: 550 , #4~6: 500×3) Retrofit (#3, 2019) Retrofit (#4, 2023) Conversion into LNG-fired plant (#5, 6, scheduled to be completed in 2026 and 2027) Lifetime extension Conversion into LNG-fired Plant KOMIPO
Boryeong #7, 8 1,000 MW (500 MW×2) EP upgrade (#7, 2025) EP upgrade (#8, 2026) Performance- improvement KOMIPO
Yeosu #1, 2 668.6MW (#1:340, #2:328.6MW) Boiler Type Change (CFBC (3):#1:2016, #2:2011) 30 years KOSEP
Samcheonpo #5, 6 1,000 MW (500 MW ×2) EP upgrade (2016 ~ 2017), FGD, SCR, WESP(6) installation (2019~2021) Anti-pollution KOSEP
Yeongheung #1, 2 1,600 MW (800 MW ×2) EP, FGD, SCR Upgrade (2022~2026) Anti-pollution KOSEP
Yeongdong #1. 2 325 MW (#1:125, #2:200 MW) Boiler, Hybrid SCR & EP, Draft System Retrofit (Biomass (4) #1: 2017, #2: 2020) Renewable energy KOSEP
Dangjin #1 - 4 2,000MW (500MW×4) FGD, EP, SCR upgrade (2022~2025) Performance- improvement EWP
Dangjin #5 - 8 2,000MW (500MW×4) FGD, EP, SCR upgrade (2024) Performance- improvement EWP
Dangjin #9 - 10 2,040MW (1,020MW×2) FGD, EP, SCR upgrade (2026) Performance- improvement EWP
Donghae #1, 2 400 MW (200 MW×2) FGD upgrade (2025) Anti-pollution & modification of control systems EWP
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Power Plant Capacity Completed (Year) Extension Company
Hadong #1 - 8 4,000 MW (500 MW×8) SCR Upgrade (#5. 2016) SCR Upgrade (#2,3,5. 2017) SCR Upgrade (#1,4,6,7. 2018) SCR Upgrade (#8. 2019) FGD Upgrade (#6, 2018) FGD Upgrade (#2, 3, 2019) FGD Upgrade (#4 2020) FGD Upgrade (#5 2021) Anti-pollution KOSPO
Samcheok #1 - 2 2,044 MW (1,022 MW×2) SCR Upgrade (#2 2023) SCR Upgrade (#1 2024) SCR Upgrade (#2 2025) SCR Upgrade (#1 2026) Anti-pollution KOSPO
Notes:
(1) “EP” means an electrostatic precipitation system.
(2) “SCR” means a selective catalytic reduction system.
(3) “CFBC” means a circulating fluidized bed combustion system.
(4) “Biomass” means wood pallet powered plant.
(5) “FGD” means flue-gas desulfurization designed to remove sulfur oxides.
(6) “WESP” means wet electrostatic precipitator.
Transmission and Distribution
We currently transmit and distribute substantially all of the electricity in Korea.
As of December 31, 2025, our transmission system consisted of 36,183 circuit kilometers of lines of 765 kilovolts and others including high-voltage direct current lines, and we had 939 substations with aggregate installed transformer capacity of 379,998 megavolt-amperes.
As of December 31, 2025, our distribution system consisted of 152,266 megavolt-amperes of transformer capacity and 10,347,266 units of support with a total line length of 556,356 circuit kilometers.
We make substantial investments in our transmission and distribution systems to minimize power interruptions and improve efficiency. Our current projects principally focus on increasing the capabilities of our existing power networks and reducing transmission and distribution loss, which was 3.52% of our gross generation in 2025. To cope with increasing damages 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 also continue to invest in automation of electricity transmission and development of new transmission technologies, among others.
New Energy Industry Projects
Certain of our new energy industry projects are described below.
Advanced Metering Infrastructure
In July 2012, the Government implemented a master plan to build out a smart grid, which includes the Advanced Metering Infrastructure (“AMI”) roadmap. In August 2018 and February 2023, the Government
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updated the master plan to focus on building electricity market ecosystem and constructing smart energy consuming structure focused on energy efficiency. In accordance with such plan, we are in the process of installing “smart meters” and related communication networks and operating systems as part of the “smart grid” initiative in an effort to enhance efficiency in the power electricity industry and alleviate growing energy shortage concerns. Our goal is to complete such installation for all of the households in Korea. Smart meters refer to digital meters that record, on a real-time basis, electricity consumption within a household so that consumers will have a price-based incentive to enhance efficiency in their electricity usage. As of December 31, 2025, we have established a data communication network that enables smart meters for 20.5 million households, and we plan to establish it for remaining 1.1 million households from 2026. We have spent Won 1,800 billion on the AMI project as of the end of 2025 and expect to spend an additional Won 54 billion, bringing the total cost to approximately Won 1.9 trillion.
Smart Grids
Smart grids refer to next-generation networks for electricity distribution that integrate information technology into existing power grids with the aim of enabling two-way real time exchange of information between electricity suppliers and consumers for optimal efficiency in electricity use. As part of our overall business strategy, we are currently developing and implementing smart grids based on advanced information technology in order to promote more efficient allocation and use of electricity by consumers. We expect that such technology will improve efficiency and reduce electricity loss over the course of electricity transmission and distribution. We also expect that the smart grid initiative will significantly increase efficient energy consumption by providing real-time data to customers, which would in turn help to reduce greenhouse gas emission and decrease Korea’s reliance on foreign energy sources.
In alignment with the Government’s energy policy aimed at the production and consumption of environmentally sustainable electricity within the region, we undertook a grid-connected microgrid initiative tailored for energy-intensive industrial complexes. Beginning with the award of the Gumi National Industrial Complex microgrid project in 2022, we secured additional contracts for the Yeosu National Industrial Complex in 2023 and the Gwangyang National Industrial Complex in 2025. Through customized strategies tailored to each industrial complex, we are establishing a self-sufficient renewable energy ecosystem and developing sustainable, environmentally friendly industrial complexes.
Energy Storage Systems
In October 2013, as part of an endeavor to create new markets for energy demand management applications using information and communication technology, we established a business plan to roll out energy storage systems for frequency regulation nationwide. These systems involve the establishment and operation of batteries and transformers with large-sized charge and discharge capabilities adjacent to substations to transmit electricity stably with regulated frequencies and optimize the efficiency of the substation operation. This system allows full conversion of reserve capacity for frequency regulation at existing low-cost generators into electricity storage and, if operated in sizable scale, offers opportunities for substantial cost savings in the purchase of electricity.
In December 2014, we conducted a pilot project for this initiative by installing a total of 52 megawatt energy storage systems at the Seo-Anseong substation and the Shin-Yongin substation, which commenced commercial operations in July 2015. With the commencement of an energy storage system at Yeong-Ju substation in December 2023 and energy storage systems at five other substations, including Bu-buk, in September 2024, the total capacity of our energy storage systems reached 1,404 megawatts.
AI-based Substation Equipment Diagnostic & Analysis system (SEDA)
We have developed and deployed an AI-based Substation Equipment Diagnostic & Analysis system (“SEDA”), which utilizes advanced digital technologies, including IoT sensors and artificial intelligence, to assist
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in real-time monitoring and analysis of the condition of our power equipment. This system fosters early detection of potential failures and allows proactive maintenance, allowing us to improve the reliability and operational efficiency of our transmission and distribution assets.
SEDA has allowed to transition from a traditional time-based maintenance to a reliability-based maintenance system, allowing us to allocate maintenance activities based on equipment condition and risk levels rather than simple passage of time. From 2021 to 2025, we believe the application of SEDA has contributed to preventing an average of approximately 15 equipment failures per year, including 17 in 2025, resulting in improved system reliability and cost savings.
In addition, we are expanding the commercialization of its diagnostic technologies through collaboration with domestic and international partners. This includes joint development of integrated solutions with major equipment manufacturers and pilot projects with overseas utilities, such as demonstration projects completed in Malaysia, as well as ongoing initiatives to enter global markets in cooperation with European energy companies.
Fuel Sources and Requirements
Nuclear
Uranium, the principal fuel source for nuclear power, accounted for 46.1% and 48.1% and 48.7% of the fuel requirements for electricity generation by us and our generation subsidiaries in terms of electricity generated in 2023, 2024 and 2025, respectively.
All uranium ore concentrates used by KHNP are imported from, and conversion and enrichment of such concentrates are provided by, sources outside Korea and are paid for with currencies other than Won, primarily U.S. dollars.
In order to ensure a stable supply, KHNP enters into medium and long-term contracts with various suppliers and supplements such supplies with purchases in spot markets. In 2025, KHNP purchased approximately 4,412 tons of its uranium concentrate requirement under both long-term and spot supply contracts with suppliers in Canada, France, Australia, Switzerland, Kazakhstan and Uzbekistan. Under the long-term supply contracts, the purchase prices of uranium concentrates are adjusted annually based on base prices and spot market prices prevailing at the time of delivery. The conversion and enrichment services of uranium concentrates are provided by suppliers in France, Canada, Japan, the United Kingdom, the United States, and Switzerland. The uranium concentrates will then be further processed by a Korean company before they are ready for use. 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 38.0%, 35.4% and 37.0% of the fuel requirements for electricity generation by us and our generation subsidiaries in 2023, 2024 and 2025, respectively, and anthracite coal accounted for 0.5%, 0.5% and 0.4% of our fuel requirements for electricity generation in terms of electricity generated in 2023, 2024 and 2025, respectively.
In 2025, our generation subsidiaries purchased approximately 56.0 million tons of bituminous coal, of which approximately 31.7%, 23.1%, 20.1%, 6.2% and 18.9% were imported from Indonesia, Australia, Russia, South Africa and others, respectively. Approximately 93.1% of the bituminous coal requirements of our generation subsidiaries in 2025 were purchased under long-term contracts with the remaining 6.9% 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-
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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 177,376, Won 137,342 and Won 124,900 in 2023, 2024 and 2025, respectively.
In 2025, our generation subsidiaries purchased approximately 0.6 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 182,527, Won 180,031 and Won 182,327 in 2023, 2024 and 2025, respectively.
Oil
Oil accounted for 0.02%, 0.0% and 0.1% of the fuel requirements for electricity generation by us and our generation subsidiaries in terms of electricity generated in 2023, 2024 and 2025, respectively.
In 2025, our generation subsidiaries purchased approximately 3.78 million barrels of fuel oil, substantial portion of which was purchased from domestic refiners through competitive open bidding. Purchase prices are based on the spot market price in Singapore. The average cost of oil per barrel was Won 191,452, Won 153,660 and Won 166,239 in 2023, 2024 and 2025, respectively.
LNG
LNG accounted for 12.0%, 11.9% and 9.9% of the fuel requirements for electricity generation by us and our generation subsidiaries in terms of electricity generated in 2023, 2024 and 2025, respectively. In 2025, for use in electricity generation we purchased approximately 4.87 million tons of LNG from Korea Gas Corporation, a Government-controlled entity in which we currently own a 20.47% equity interest (excluding treasury shares). In 2025, we purchased a substantial portion of our LNG requirements for use in power generation from Korea Gas Corporation. Under the terms of the LNG contract with Korea Gas Corporation, all of our five non-nuclear generation subsidiaries jointly and severally agreed to purchase a total of 5.18 million tons of LNG in 2025, subject to an automatic price adjustment annually based on a pre-determined formula if the actual purchased amount exceeds or falls short of the contracted amount. We believe the quantities of LNG provided under such contract will be adequate to meet the needs of our generation subsidiaries for LNG for the next several years. The LNG supply contracts between our generation subsidiaries and Korea Gas Corporation generally have a term of 20 years and provide for minimum purchase requirements for our generation subsidiaries, the specific terms of which are subject to negotiation between Korea Gas Corporation and our generation subsidiaries and approval by the Government. The average cost per ton of LNG was Won 1,391,146, Won 1,093,407 and Won 985,951, in 2023, 2024 and 2025, respectively. Korea Gas Corporation implemented a new individual tariffs formula, whereby the domestic power plants can negotiate lower prices directly with Korea Gas Corporation. The new formula applies to domestic power plants whose current contracts with Korea Gas Corporation expire after January 2022 and also to new power plants commencing operations from January 2022.
Meanwhile, KOMIPO procures LNG directly through a contract with a brokerage firm, in addition to the amount supplied by Korea Gas Corporation and Incheon City Gas Co., Ltd. In 2025, the total amount of KOMIPO’s direct LNG procurement was 0.26 million tons, with 69.57%, 6.69% and 23.74% of the total imported from Russia, Malaysia and other countries, respectively. KOWEPO procures LNG directly through contracts with brokerage firms, in addition to the amount supplied by Korea Gas Corporation. In 2025, the total amount of KOWEPO’s direct LNG procurement was 0.24 million tons, with 24%, 49%, and 27% of the total imported from the UAE, the United States, and Australia, respectively. KOSPO procures LNG through contracts with global major LNG suppliers such as IOCs, LNG producers, major traders, as well as Korea Gas Corporation. In 2025, the total amount of KOSPO’s direct LNG procurement was 0.4 million tons, sourced from the United States, Malaysia, and other countries. EWP procures LNG directly through contracts with brokerage firms, in addition to the volume supplied by Korea Gas Corporation. In 2025, the total amount of EWP’s direct LNG procurement was 0.126 million tons, with 48.12% imported from Malaysia and 51.88% from the Australia
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Hydroelectric
Hydroelectric power generation, including pumped storage, accounted for 1.3%, 1.6% and 1.6%, of the fuel requirements for electricity generation by us and our generation subsidiaries in terms of electricity generated in 2023, 2024 and 2025, 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.
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.
The table below sets forth, for the periods indicated, the annual rate of growth in Korea’s GDP and the annual rate of growth in electricity demand (measured by total annual electricity consumption) on a year-on-year basis. In 2025, the GDP increased by 1.0% compared to 2024, whereas the demand for electricity in Korea decreased by 0.1% compared to 2024.
2021 2022 2023 2024 2025
Growth in GDP 4.6 % 2.7 % 1.4 % 2.0 % 1.0 %
Growth in electricity consumption 4.7 % 2.7 % (0.4 )% 0.7 % (0.1 )%
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 sell electricity to our customers by installing electricity meters on-site and taking 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.
2021 (GWh) YoY growth (%) 2022 (GWh) YoY growth (%) 2023 (GWh) YoY growth (%) 2024 (GWh) YoY growth (%) 2025 (GWh) YoY growth (%) % of Total 2025
Residential 79,915 4.7 80,996 1.4 82,348 1.7 86,989 5.6 88,474 1.7 16.1
Commercial 119,550 5.2 127,193 6.4 130,844 2.9 134,807 3.0 138,315 2.6 25.2
Educational 8,423 12.1 9,074 7.7 9,232 1.7 9,433 2.2 9,811 4.0 1.8
Industrial 291,333 4.5 296,036 1.6 290,555 (1.9 ) 286,212 (1.5 ) 280,221 (2.1 ) 51.0
Agricultural 20,603 8.3 21,420 4.0 20,763 (3.1 ) 21,088 1.6 21,523 2.1 3.9
Street lighting 3,445 (1.8 ) 3,424 (0.6 ) 3,399 (0.7 ) 3,402 0.1 3,416 0.4 0.6
Overnight Power 10,162 (4.3 ) 9,790 (3.7 ) 8,825 (9.9 ) 7,890 (10.6 ) 7,656 (3.0 ) 1.4
Total 533,431 4.7 547,933 2.7 545,966 (0.4 ) 549,821 0.7 549,417 (0.1 ) 100.0
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The industrial sector represents the largest segment of electricity consumption in Korea. Demand for electricity from the industrial sector was 280,221 gigawatt hours in 2025, representing a 2.1% decrease from 2024, due to economic slowdown in power-intensive industries such as petrochemicals and steel. Demand for electricity from the commercial sector depends largely on the level and scope of commercial activities in Korea. Demand for electricity from the commercial sector increased to 138,315 gigawatt hours in 2025, representing a 2.6% increase from 2024, due to the effects of a gradual recovery in consumption and an increase in demand for cooling and heating. Demand for electricity from the residential sector is largely dependent on population growth and use of heaters, air conditioners and other electronic appliances. Demand for electricity from the residential sector increased to 88,474 gigawatt hours in 2025, representing a 1.7% increase compared to 2024, due to the effects of increased demand for heating and cooling during the winter and summer seasons.
Demand Management
Our ability to provide adequate supply of electricity is principally measured by the facility reserve margin and the supply reserve margin. The facility reserve margin represents the difference between the peak usage during a year and the installed capacity at the time of such peak usage, expressed as a percentage of such peak usage. The supply reserve margin represents the difference between the peak usage in a year and the 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.
2021 2022 2023 2024 2025
Facility reserve margin 44.1 % 46.0 % 52.3 % 53.6 % 61.9 %
Supply reserve margin 10.5 % 11.8 % 11.4 % 8.5 % 9.4 %
In addition, in accordance with the delegating regulations of the Energy Use Rationalization Act, the Ministry of Trade, Industry and Resources designated us as a pilot operator for the Energy Efficiency Resource Standards (“EERS”) in 2018. To promote the development of energy-efficient technologies and practices, EERS sets energy savings targets for energy suppliers to pursue in proportion to their energy sales, requiring that, in 2026, we save as much as 0.3% of our 2024 electricity sales by reducing our customers’ consumption. In accordance with the EERS regulations, we plan to increase our savings target to 1% of annual electricity sales by 2031. The EERS pilot project is expected to be converted into an actual project in 2027 pursuant to the revision of the Energy Use Rationalization Act in 2026.
Electricity Rates
The Electric Utility Act and the Price Stabilization Act of 1975, each as amended from time to time, prescribe the procedures for the approval and establishment of rates charged for the electricity we sell. We submit our proposals for revisions of rates or changes in the rate structure to the Ministry of Climate, Energy and Environment. The Ministry of Climate, Energy and Environment then reviews these proposals and, following consultation with the Ministry of Finance and Economy and review by the Korea Electricity Commission, makes the final decision.
Under the Electric Utility Act and the Price Stabilization Act, electricity rates are established at the same level as the Total Comprehensive Cost that would enable us to recover our fair operating costs as well as receive a fair investment return on capital used in our operations. The fair operating costs are defined as the sum of our operating expenses attributable to our electricity supply, our adjusted income taxes and some of non-operational profit or loss.
The fair investment return on capital used in our operations represents an amount equal to the rate base multiplied by the rate of return.
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The rate base is currently equal to the sum of:
• net utility plant in service (which is equal to utility plant minus accumulated depreciation minus revaluation reserve);
• the portion of working capital which is equal to the appropriate level of operating costs minus depreciation and other non-cash charges while taking into account the actual time of cost recovery; and
• the portion of construction-in-progress which is charged from our retained earnings.
The amounts used for the variables in the rates are those projected by us for the periods to be covered by the rate approval.
For the purpose of determining the fair rate of return, the rate base is divided into two components in proportion to our total equity and our total debt. The rate of return permitted in relation to the debt component of the rate base is set at a level designed to approximate the weighted average interest cost on all types of borrowing for the periods covered by the rate approval. The rate of return permitted in relation to the equity component of the rate base is set by applying the capital asset pricing model which takes account of the risk-free rate, the return on the Korea Stock Price Index, KOSPI, and the correlation of the stock price of our company with KOSPI. The fair rate of return needs to be approved by the Government in accordance with the Public Notice on Detailed Licensing Standards for Power Generation Business, Electricity Rates Calculation Standards, Permissible Error Range for Electric Meters, and Electric Power System Operation Guidelines. In 2024, the approved rate of return on the debt component of the rate base was 2.790% while the approved rate of return on the equity component of the rate base was 6.847%. As a result of such approved rates of returns, the fair rate of return in 2024 was determined to be 3.18%. The rate of return for 2025 has not yet been determined.
The Electric Utility Act and the Price Stabilization Act do not specify a basis for determining the reasonableness of our operating expenses or any other items (other than the level of the fair investment return) for the purposes of the rate calculation. However, the Government exercises substantial control over our budgeting and other financial and operating decisions.
In addition to the calculations described above, a variety of other factors are considered in setting overall tariff levels. These other factors include consumer welfare, our projected capital requirements, the effect of electricity tariff on inflation in Korea and the effect of tariff on demand for electricity.
From time to time, our actual rate of return on invested capital may differ significantly from the fair rate of return on invested capital assumed for the purposes of electricity tariff approvals, for reasons, among others, related to movements in fuel prices, exchange rates and demand for electricity that differ from what is assumed for determining our fair rate of return. For example, between 1987 and 1990, the actual rate of return was above the fair rate of return due to declining fuel costs and rising demand for electricity at a rate not anticipated for purposes of determining our fair rate of return. Similarly, depreciation of the Won against the U.S. dollar accounted for our actual rates of return being lower than the fair rate of return for the period from 1996 to 2000. For the period between 2006 and 2013, our actual rates of return were lower than the fair rate of return largely due to a general increase in fuel costs and additional facility investment costs incurred, the effects of which were not offset by timely increases in our tariff rates. Between 2014 and 2016, however, largely due to a decrease in fuel costs reflective of the drop in oil prices, our actual rate of return has surpassed the fair rate of return; however, substantially all of the resulting excess has been used to fund capital expenditure and repair and maintenance, and make investments in renewable energy and other environmental programs.
Partly in response to the variance between our actual rates of return and the fair rates of return, the Government from time to time increases the electricity tariff rates, but there typically is a significant time lag for the tariff increases as such increases requires a series of deliberation processes and administrative procedures and the Government also has to consider other policy considerations, such as the inflationary effect of overall tariff increases and the efficiency of energy use from sector-specific tariff increases.
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As of January 1, 2021, we implemented a new tariff system to reinforce the correlation between the costs we incur and the tariff we charge to our customers, among other changes. The new tariff system consists of three main changes.
First, we implemented a new cost pass-through tariff system to reinforce the correlation between the costs we incur and the tariff we charge to our customers and to enhance transparency by separately billing fuel costs and climate/environment related costs. Previously, the electricity tariff consisted of two main components: (i) the base charge (the “Base Charge”) and (ii) the usage charge (the “Usage Charge”) based on the amount of electricity consumed by end-users. Under the new tariff system, there are new components to the tariff called the fuel cost adjusted charge (the “Fuel Cost Adjusted Charge”) and the climate/environment related charge (the “Climate/Environment Related Charge”). In principle, the Fuel Cost Adjusted Charge is calculated on a quarterly basis, and the formula for calculating the amount of the Fuel Cost Adjusted Charge is multiplying (i) the unit price of the Fuel Cost Adjusted Charge (the “Unit Price of the Fuel Cost Adjusted Charge”), which is the difference between a base fuel cost (the “Base Fuel Cost”) and an actual fuel cost (the “Actual Fuel Cost”) and (ii) the amount of electricity consumed. The Base Fuel Cost is the past twelve-month average fuel price of bituminous coal, LNG and Bunker C oil as posted by the Korea Customs Service. The twelve-month average fuel price is measured by taking the average of monthly fuel prices from twelve months in between thirteen and one month prior to the time a new Base Fuel Cost becomes effective. To illustrate, the Base Fuel Cost effective from 2023 is the average of the fuel prices from December 2021 to November 2022. The Base Fuel Cost can be adjusted upon the revision of the electricity tariff as a whole. On the other hand, the Actual Fuel Cost is the past three-month average fuel price of the same fuels we use to measure the Base Fuel Cost. The past three-month average fuel price is measured by taking the average of monthly fuel prices from three months in between four and one month prior to the time the Fuel Cost Adjusted Charge is updated. To illustrate, for the second quarter of 2026, we used the fuel costs for September, October and November 2025 to calculate the three-month average fuel price.
The quarterly-adjusted Fuel Cost Adjusted Charge has built-in limits in view of price stability and other public policy considerations. First, there is a limit on any change in the Unit Price of the Fuel Cost Adjusted Charge to be no less than Won ±1 per kilowatt-hour. In other words, any change less than Won ±1 per kilowatt-hour will not be reflected. However, such limit does not apply if it is the first quarter during which the Base Fuel Cost has been newly updated. Second, the Unit Price of the Fuel Cost Adjusted Charge that exceeds Won ±5 per kilowatt-hour will not be reflected. In other words, the maximum adjustment that can be incorporated to the Unit Price of the Fuel Cost Adjusted Charge is equal to Won ±5 per kilowatt-hour from the Base Fuel Cost that is in effect. For example, in the third quarter of 2023, the Unit Price of the Fuel Cost Adjusted Charge was Won 10.2 per kilowatt-hour, meaning the Actual Fuel Cost was higher than the Base Fuel Cost by Won 10.2 per kilowatt-hour, but after being subjected to the limit of Won ±5 per kilowatt-hour, the Unit Price of the Fuel Cost Adjusted Charge came out to be Won 5.0 per kilowatt-hour.
However, our ability to pass on fuel and other cost increases to our customers may be limited due to Government regulations on the rates charged for the electricity we supply to our customers. In addition to the built-in limits described in the preceding paragraph, the new tariff system gives discretion to the Government to not wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances, as determined by the Government. For example, in the second and third quarter of 2021, although the Unit Price of the Fuel Cost Adjusted Charge was Won –0.2 and Won +1.7 per kilowatt-hour respectively, the Government notified us to keep it at the same Won –3.0 per kilowatt-hour as the first quarter of 2021. In the fourth quarter of 2021, we increased the Unit Price of the Fuel Cost Adjusted Charge to Won 0.0 per kilowatt-hour. In the first and second quarters of 2022, although the Unit Price of the Fuel Cost Adjusted Charge as calculated should have been Won 3.0 per kilowatt-hour as the quarterly limit of Won ±3 per kilowatt-hour had existed back then, the Government notified us to keep it at the same Won 0.0 per kilowatt-hour as the fourth quarter of 2021. The Government cited different policy reasons for withholding the application of the quarterly Fuel Cost Adjusted Charge in the past, but one of the more consistent reasons has been alleviating the hardship caused by the prolonged economic effects of COVID-19 pandemic. As the quarterly limit of Won ±3 per kilowatt-hour was
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repealed in the third quarter of 2022 and with the approval by the Government, we ultimately increased the Unit Price of the Fuel Cost Adjusted Charge to Won 5.0 per kilowatt-hour in the third quarter of 2022, which represented the maximum permissible increase for 2022 under the regulatory cap. From the third quarter of 2022 to the second quarter of 2026, the same Won 5.0 per kilowatt-hour increment has been applied to the Unit Price of the Fuel Cost Adjusted Charge. Even though the quarterly adjustment amounts calculated under our formula were Won -1.8, Won -4.0, Won -2.5, Won -6.4, Won -6.4, Won -5.1, Won -4.2, Won -6.4, Won -12.1, Won -13.3 and Won -11.2 per kilowatt-hour per each quarter from the fourth quarter of 2023, to the second quarter of 2026, respectively, the Government notified us to maintain the Unit Price at Won 5.0 per kilowatt-hour, taking into consideration our financial conditions and the fact that a substantial amount of the Fuel Cost Adjusted Charge that should have been reflected in previous years has not previously been reflected in the electricity tariff.
Also, because the Fuel Cost Adjusted Charge takes into account the fuel prices posted by Korea Customs Service, there may still be a mismatch in value between the actual prices the domestic generation companies pay for their fuels in the open market and the adjustment that can be made through the Fuel Cost Adjusted Charge. The domestic generation companies include not only our generation subsidiaries but also independent power producers that are not affiliated with us and we do not have access to fuel costs incurred by the independent power producers. As such, we use fuel prices posted by Korea Customs Service, which are easily accessible to our customers, for calculating the Fuel Cost Adjusted Charge.
Due to the likelihood of the Actual Fuel Cost being substantially over the adjustment limits imposed by the new tariff system and the Government’s discretion not to wholly or partially adjust the quarterly Fuel Cost Adjusted Charge in case of extenuating circumstances, there may be certain portions of the fuel costs that cannot be charged to our customers, even though those portions should have been included in the Fuel Cost Adjusted Charge. In such cases, we may accumulate such portions and reflect them in what is called the Total Comprehensive Cost, which is a variable we use to calculate the Base Charge and the Usage Charge of the tariff. The Total Comprehensive Cost, which we submit each year to the Government for review, is calculated using the relevant costs according to our settled accounts from the previous year and the proposed budget for the upcoming year. Under the Total Comprehensive Cost approach, the Base Charge and the Usage Charge are established at levels that would enable us to recover fair operating costs as well as fair investment return on the capital used in our operations. For further information on fair operating costs and fair investment return, please see Item 4.B. “Business Overview—Sales and Customers—Electricity Rates.” The Base Charge and the Usage Charge that are derived from the Total Comprehensive Cost need to be approved by the Government before they can be revised. The Government may, from time to time, consider different policy objectives to regulate the time and magnitude of such revision of the Base Charge and the Usage Charge of the electricity tariff. Therefore, changes in the fuel costs may not be timely or fully reflected even through the Usage Charge of the tariff where they would typically be reflected. In December 2021, there was a need to increase the Usage Charge by Won 9.8 per kilowatt-hour from January 2022 to reflect the rise in the Base Fuel Cost. With approval by the Government, we increased the Usage Charge by Won 4.9 per kilowatt-hour on April 1, 2022 and October 1, 2022 respectively, which resulted in a total increase of Won 9.8 per kilowatt-hour. Such increases were spread out into two rounds to relieve people’s hardship including the prolonged effects of COVID-19 pandemic. In addition, in October 2022, we increased the Usage Charge of the tariff by Won 7.0 to Won 11.7 per kilowatt-hour on industrial and commercial consumers and by Won 2.5 per kilowatt-hour on all other consumers, reflecting additional accumulated increases in fuel costs. In 2023, with the approval of the Government, we increased the Usage Charge by Won 11.4 and Won 8.0 per kilowatt-hour in January and May 2023, respectively, to reflect a portion of the increase in the Base Fuel Cost. Also, we increased the Usage Charge of the tariff by Won 6.7 to Won 13.5 per kilowatt-hour for large-scale industrial consumers in November 2023 to reflect additional accumulated increases in fuel costs. In its economic policy direction statement for 2023, the Government announced its plans to gradually increase the tariff in order to address our cumulative deficit by 2027. However, there is no assurance on whether such plans will be realized. On October 23, 2024, in coordination with the Government, we announced that, starting from October 24, 2024, we will increase electricity tariff on industrial consumers by an average of Won 16.1 per kilowatt-hour, representing an average increase of 9.7% from the previous tariff, while maintaining the same electricity tariff on the rest of the consumers.
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Also, the new tariff system introduced an additional component to the tariff called a climate/environment related charge (the “Climate/Environment Related Charge”). Previously, our climate and environment costs were embedded in the Usage Charge component of the tariff and our consumers could not discern the exact magnitude of such costs. By separating it out as an independent component, we intend to provide more information and transparency to our customers while having the flexibility to adjust it in alignment with the underlying costs. The Climate/Environment Related Charge for the coming year is calculated by multiplying (i) our total estimated costs of (A) complying with the Renewable Portfolio Standard program, the greenhouse gas emission trading system and the coal-fired generation reduction program for the current year and (B) amounts paid back to customers under the Energy Cashback program, a program offering discounts (in the form of cashbacks) to participating customers who reduce electricity consumption beyond certain thresholds in order to promote energy conservation, and then dividing it by the electricity sales projected for the coming year (the “Climate/Environment Related Base Rate”), and (ii) the amount of electricity consumed. The value of the Climate/Environment Related Base Rate for 2025 was Won 9.0 per kilowatt-hour, which has been maintained up to the date of this annual report. Even though the Climate/Environment Related Charge is planned to be adjusted every year by reflecting the change in climate and environment-related costs but the Government may change the date of adjustment in consideration of different policy objectives. If there are discrepancies between our costs and the Climate/Environment Related Charge, we may accumulate such discrepancies and reflect them in our Total Comprehensive Cost. However, the electricity rate based on the Total Comprehensive Cost needs to be approved by the Government to be revised.
The tariff rates we charge for electricity vary among the different classes of consumers, which principally consist of industrial, commercial, residential, educational and agricultural consumers. The tariff also varies depending upon the voltage used, the season, the time of usage, the rate option selected by the user and, in the residential sector, the amount of electricity used per household, as well as other factors. For example, we adjust for seasonal tariff variations by applying higher rates when demand tends to rise such as during the months of June, July and August (when the demand tends to rise due to increased use of air conditioning) and November, December, January and February (when demand tends to rise due to increased use of heating), which reflects the policy of the Korean government to cope with the rise in electricity demand during peak seasons by encouraging a more efficient use of electricity by customers. In addition, we provide discounts on tariff rates to certain users such as low income households.
Our current tariff schedule reflecting the adjustments outlined above and effective from April 16, 2026 is summarized below by the type of usage:
• Industrial. The monthly Base Charge varies from Won 5,550 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy Usage Charge varies from Won 88.0 per kilowatt-hour to Won 242.9 per kilowatt-hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.
• Commercial. The monthly Base Charge varies from Won 6,160 per kilowatt to Won 9,810 per kilowatt depending on the type of contract, the voltage used and the rate option. The energy Usage Charge varies from Won 83.5 per kilowatt-hour to Won 229.4 per kilowatt-hour depending on the type of contract, the voltage used, the season, the time of day and the rate option.
• Residential. The monthly Base Charge varies from Won 730 for electricity usage of less than 200 kilowatt-hours to Won 7,300 for electricity usage in excess of 400 kilowatt-hours. During the months of July and August each year, the usage ceiling for the first two tiers of rates increased from 200 kilowatts to 300 kilowatts for the first tier and from 400 kilowatts to 450 kilowatts for the second tier. Residential tariff also includes an energy Usage Charge ranging from Won 105.0 to Won 307.3 per kilowatt-hour for electricity usage depending on the amount of usage and voltage. During the peak usage periods during summer and winter, namely the months of July and August and December to February, a higher energy Usage Charge of Won 736.2 per kilowatt-hour applies to residential consumers whose monthly electricity consumption exceeds 1,000 kilowatts hour. Also, in
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the case of Jeju Island, in accordance with the new tariff system, residents may also opt for our new seasonal and hourly tariff schedule as an alternative. Under the new schedule, the monthly Base Charge is Won 4,310 per kilowatt. The Usage Charge varies from Won 125.8 per kilowatt-hour to Won 220.5 per kilowatt-hour depending on season and time of the day.
• Educational. The monthly Base Charge varies from Won 5,230 per kilowatt to Won 6,980 per kilowatt depending on the voltage used and the rate option. The energy Usage Charge varies from Won 70.5 per kilowatt-hour to Won 187.1 per kilowatt-hour depending on the voltage used, the season and the rate option.
• Agricultural. The monthly Base Charge varies from Won 360 per kilowatt to Won 1,210 per kilowatt depending on the type of usage. The energy Usage Charge varies from Won 48.3 per kilowatt-hour to Won 68.6 per kilowatt-hour depending on the type of contract, the voltage used and the season.
• Street-lighting. The monthly Base Charge is Won 6,290 per kilowatt and the energy Usage Charge is Won 112.6 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 47.2 per watt applies, with the minimum monthly charge of Won 1,220.
In 2001, as part of implementing the Restructuring Plan, the Ministry of Trade, Industry and Resources established the Electric Power Industry Basis Fund to enable the Government to take over certain public services previously performed by us. 3.7% of the tariff collected from our customers from December 28, 2005 through June 30, 2024, 3.2% of the tariff collected from our customers from July 1, 2024 through June 30, 2025, and 2.7% of the tariff collected from our customers from July 1, 2025 has been or will be transferred to the Electric Power Industry Basis Fund prior to us recognizing sales revenue.
On March 16, 2026, we announced a comprehensive restructuring of our time-of-use (TOU) electricity tariff system. This reform is designed to align price incentives with the expansion of and increased focus on renewable energy generation. The primary objective is to incentivize a shift in power demand toward daytime hours, when renewable energy generation, particularly solar power, is most abundant. Furthermore, the reform aims to mitigate curtailment issues, where excess generation occurs during daytime hours on weekends and holidays in spring and autumn seasons due to insufficient demand.
Key features of the reform include the following:
• Adjustment of Time-of-Use Classification: During spring, summer and autumn seasons (March to October), the daytime periods (11:00 to 12:00 and 13:00 to 15:00) previously classified as peak-load have been reclassified as mid-load. Conversely, the evening period (18:00 to 21:00) has been shifted from mid-load to peak-load to reflect shifting demand patterns. These revised time-of-use standards apply to weekdays across all contract categories that are subject to TOU tariffs, including certain Industrial, Commercial, Educational, Electric Vehicle charging customers.
• Tariff Rate Restructuring: We increased the off-peak (night time) rate by Won 5.1/kWh, while peak-load rates were reduced by an average of Won 15.4/kWh (Won 16.9/kWh for summer/winter and won 13.2/kWh for spring/autumn) across all seasons. These specific rate adjustments are applicable solely to Industrial(B).
• Weekend and Holiday Incentives: A 50% discount on usage charges has been introduced for usage from 11:00 to 14:00 on weekends and holidays during spring (March to May) and autumn (September to October). This incentive is applicable only to Industrial(B) and Electric Vehicle charging.
The revised tariff system for Industrial(B) and Electric Vehicle charging is scheduled to take effect on April 16, 2026. Other applicable categories, such as Industrial(A)II, Commercial(A)II, Commercial(B), Educational(B), will adopt the adjusted TOU classifications beginning June 1, 2026.
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Direct Power Purchase
Pursuant to the Electric Utility Act and the Enforcement Decree of the Electric Utility Act, purchasers of power capacity in excess of 30,000 Kilovolt-amps (kVA) (the threshold was previously 50,000 kVA prior to an amendment to the Enforcement Decree of the Electric Utility Act in June 2007) have been allowed to purchase electricity directly through the Korea Power Exchange. As market interest increased, the Korea Power Exchange amended the Rules on Operating Electricity Market in 2025, such as extending the mandatory retention period for switching to direct purchase from one year to three years, which is expected to make customers more careful in deciding to switch to direct purchases as they will be subject to a longer retention period. As at the end of 2025, there have been some instances of direct power purchase by electricity consumers. Although direct purchases will still utilize KEPCO’s transmission network, an increase in direct purchases of electricity may adversely affect our market share in electricity sales and, particularly if it were to gain widespread acceptance, may negatively affect our business, financial condition, results of operations and cash flows.
Power Development Strategy
We and our generation subsidiaries make plans for expanding or upgrading our generation capacity based on the Basic Plan, which is generally revised and announced every two years by the Government. In February 2025, the Government announced the Eleventh Basic Plan and subsequently amended it in March 2025 which covers the period from 2024 to 2038. The Eleventh Basic Plan focuses on (a) establishing an energy mix and equipment plan that comprehensively considers policy principles such as supply stability, efficiency and carbon neutrality and (b) proactively strengthening the power grid and advancing market sophistication to expand carbon-free power sources, and includes the following specific measures: (i) following the continued use of nuclear power as a carbon-free source, the Eleventh Basic Plan includes the construction of two new large nuclear power plants with an aggregate generation capacity of 2.8 gigawatts by 2038 and commercial operation of a small modular reactor with generation capacity of 0.7 gigawatts by 2035, which together with other previously planned facilities, is expected to increase nuclear power capacity from 24.7 gigawatts in 2023 to 35.2 gigawatts in 2038; (ii) aging coal-fired power plants to be gradually replaced with carbon-free power sources and LNG plants, with a principle of simultaneous replacement with the same capacity—accordingly, coal power capacity is expected to decrease from 39.2 gigawatts in 2023 to 22.2 gigawatts in 2038, while LNG power capacity is expected to increase from 43.2 gigawatts in 2023 to 69.2 gigawatts in 2038; (iii) renewable energy will be systematically expanded, including expansion of solar and wind power generation capacities and market system reforms, which is expected to increase renewable energy generation capacity from 30.0 gigawatts in 2023 to 121.9 gigawatts in 2038; (iv) through the expansion of nuclear power, renewable energy, clean hydrogen and ammonia, reaching carbon-free share of 53.0% by 2030 and 70.7% by 2038, and ultimately achieving carbon neutrality; and (v) building a power grid with sufficient capacity to accommodate carbon-free energy sources. The Eleventh Basic Plan also aims to ensure a sufficient and timely electricity supply to advanced industries such as semiconductor clusters, as well as establishing an integrated supply-demand management system and an auction market in order to further stability and power source diversification.
Accordingly, we established the Eleventh Transmission and Substation Facilities Plan in accordance with the Eleventh Basic Plan in May, 2025. The Eleventh Transmission and Substation Facilities is covering the period from 2024 to 2038 and focuses on initiatives such as the timely construction of transmission and substation facilities to meet increasing demand, integration of the management system for power plants including nuclear and renewable energy, and reinforcement of the national infrastructure grid to achieve carbon neutrality.
In March 2022, the Government enacted the Framework Act on Carbon Neutrality with the goal of transitioning to a carbon neutral society by 2050 through sustainable green growth. Carbon neutrality initiatives set forth in the Framework Act on Carbon Neutrality includes setting medium to long-term greenhouse gas reduction targets and implementing measures to combat the climate crisis. Accordingly, it will be important for us to cooperate with Government initiatives and minimize the environmental impact we have on the climate crisis through our operations.
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Pursuant to the Special Act on the Activation of Distributed Energy enacted in June 2023, a power grid impact assessment system has been implemented since June 2024 which manages the production and consumption of electricity at regional levels, trying to prevent concentrated demand from specific areas that would require excessive expansion of the broader power grid. Additionally, in November 2024, we entered into an agreement with advanced industry companies for the construction of infrastructure facilities, which is expected to allow us to collaborate with customers and generation companies to reduce investment costs, utilize land more efficiently, and promote the timely completion of power facilities, thereby fostering new businesses.
We cannot assure that the Framework Act on Carbon Neutrality, the Special Act on the Activation of Distributed Energy, the Twelfth Basic Plan, the Twelfth Long-Term Transmission and Substation Facilities Plan or the respective plans to be subsequently adopted will successfully achieve their intended goals. If there is significant variance between the projected electricity supply and demand considered in planning our capacity expansions and the actual electricity supply and demand or if these plans otherwise fail to meet their intended goals or have other unintended consequences, this may result in inefficient use of our working capital, mispricing of electricity and undue financing costs on the part of us and our generation subsidiaries, among others, which may have a material adverse effect on our results of operations, financial condition and cash flows.
Capital Investment Program
The table below sets forth, for each of the years ended December 31, 2023, 2024 and 2025, the amounts of capital expenditures for the construction of generation, transmission and distribution facilities.
2023 2024 2025
(In billions of Won)
W 15,518 W 16,720 W 18,701
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 2026 to 2029 based on the Eleventh Basic Plan, as amended.
Year Number of Units Type of Units Total Installed Capacity
(Megawatts)
2026 1 Nuclear power 1,400
3 LNG-combined 1,562
23 Renewables 59
2027 1 Nuclear power 1,400
3 LNG-combined 2,120
32 Renewables 38
2028 3 LNG-combined 1,508
40 Renewables 40
2029 9 LNG-combined 4,749
7 Renewables 36
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.
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The table below sets forth, for the period from 2026 to 2028, the budgeted amounts of capital expenditures pursuant to our capital investment program, which primarily consist of budgets for the construction of generation, transmission and distribution facilities and, to a lesser extent, renewable energy generation and new energy industry projects. The budgeted amounts may vary from the actual amounts of capital expenditures for a variety of reasons, including, among others, the implementation of the Tenth Basic Plan currently in place, changes in the number of units to be constructed, the actual timing of such construction, changes in rates of exchange between the Won and foreign currencies and changes in interest rates.
2026 2027 2028 Total
(in billions of Won)
Generation (1):
Nuclear W5,568 W6,663 W6,538 W18,769
Thermal 5,410 6,806 6,867 19,083
Renewables and others 961 1,635 1,808 4,404
Sub-total 11,939 15,103 15,213 42,255
Transmission and Distribution:
Transmission 5,442 6,613 6,625 18,680
Distribution 4,175 4,323 4,347 12,846
Sub-total 9,617 10,936 10,973 31,526
Others (2) 1,543 1,352 1,440 4,334
Total W23,099 W27,391 W27,625 W78,115
Notes:
(1) The budgeted amounts for our generation facilities are based on the Ninth Basic Plan, as amended.
(2) Principally consists of investments in telecommunications and new energy industry projects, among others.
In January 2016, the Ministry of Trade, Industry and Resources announced an initiative to promote the new energy industry by creating the New Energy Industry Fund, which is made up of funds sponsored by Government-affiliated energy companies. We contributed Won 500 billion to the funds in 2016. The purpose of these funds is to invest in substantially all frontiers of the new energy industry, including renewable energy, energy storage systems, electric vehicles, small-sized self-sustaining electricity generation grids known as “micro-grids”, among others, as well as invest in start-up companies, ventures, small to medium-sized enterprise and project businesses that engage in these businesses but have not previously attracted sufficient capital from the private sector.
Furthermore, as a measure to address the high level of particulate matter pollution, in October 2018, the Government introduced a pilot regulation to lower the output of 35 coal-fired generation units to approximately 80% of their capacity that emit more than a certain amount of particulate matter. The regulation was formally implemented in January 2019, targeting 40 coal-fired power plants with high emissions of particulate matter. From March to June 2019, the scope expanded to cover 60 units in total. In addition, coal-fired generation units originally scheduled for preventive maintenance during the second half of 2019 were required to undertake such maintenance earlier in the spring of 2019. In November 2019, the Government pursued a reduction of coal-fired generation units in order to implement the Special Measures to Respond to the High Concentration Period (December to March) of Particulate Matter. We plan to continue to participate in the effort to reduce the particulate matter emissions from coal-fired generation units, not only during the winter but also during the spring. For example, as of March 31, 2026, 52 coal-fired generation units were subject to a cap of 80% of their capacity. On March 24, 2026, the Government announced that it would ease the restrictions on coal-fired generation units in response to an energy crisis caused by the conflict in Iran. Additionally, the Government adjusted the schedule to close down two decrepit coal-fired generation units (Boryeong #1 and #2), which were shut down in December 2020. Also, other coal-fired generation units, Samcheonpo #1 and #2, were shut down in
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May 2021 and Honam #1 and #2 units in December 2021. According to the Tenth Basic Plan announced in December 2022, the total coal-fired power plant capacity in 2036 will decrease to 27.1 gigawatts from 40.2 gigawatts in 2023, and its percentage of total power generation capacity will decrease to 11.3% in 2036 from 27.1% in 2023. While such measures may be subject to change, we expect to incur significant costs of complying with such measures, including in connection with more stringent particulate matter pollution regulations, retrofitting and overall replacement of environmental facilities.
We have financed, and plan to finance in the future, our capital investment programs primarily through net cash provided by our operating activities and financing in the form of debt securities and loans from domestic financial institutions, and to a lesser extent, borrowings from overseas financial institutions. In addition, in order to prepare for potential liquidity shortage, we maintain several credit facilities with financial institutions in the aggregate amounts of Won 15,828 billion and US$ 1,760 million on a consolidated basis, the full amount of which was available as of December 31, 2025. We, KHNP and KOMIPO also maintain global medium-term note programs in the aggregate amounts of US$ 19 billion, of which approximately US$ 9 billion remains currently available for future drawdown. See also Item 5.B. “Liquidity and Capital Resources—Capital Resources.”
Environmental, Social and Governance Programs
With the ESG Promotion Strategy established in 2022, we set the direction and strategic goals to advance the sectoral strategies in each of environment, social, governance to reflect environmental changes and strengthen infrastructure for the achievement of the strategies. To reach the ESG vision and strategic goals, we have identified strategic tasks for each sector of environment, social, governance and will continue to work on them in the future.
Environmental Programs
The Environmental Policy Basic Act, the Air Quality Preservation Act, the Water Environment Conservation Act, the Marine Environment Management 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, wastewater, 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. Additionally, we are endeavoring to develop and implement greenhouse gas reduction strategy in line with the new climate regime set forth by the Paris Climate Agreement.
We continuously endeavor to contribute to sustainable growth (whether as an economy, a society or an ecosystem) by actively taking actions that befit our social responsibility as a corporate citizen in the energy industry. For example, in 2005, we became the first public company in Korea to join the United Nations Global Compact, an international voluntary initiative designed to hold a forum for corporations, United Nations agencies, labor and civic groups to promote reforms in economic, environmental and social policies. As part of our involvement with such initiative, we issue an annual report named the “Sustainability Report” to disclose our activities from the perspectives of economy, environment and society, in accordance with the reporting guidelines of the Global Reporting Initiative, the official collaborating center of the United Nations Environment Program that works in cooperation with United Nations Secretary General. We recognize the interest in ESG within the investors’ community and are continuously pursuing safe and clean energy supply and distribution by reducing greenhouse gas emissions and enhancing our ability to respond to climate change, the details of such efforts provided through periodic sustainability reports. In addition, we made detailed disclosures on our sustainability reports in accordance with the global sustainability frameworks such as the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) and the standards of the Sustainability
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Accounting Standards Board from 2020. In 2024, as TCFD was merged with the International Sustainability Standards Board, we applied the IFRS S1 and S2 in “2024 Sustainability Report” instead of the TCFD recommendations, and we also applied a domestic sustainability framework, “K-ESG Guidelines,” to improve our reporting of sustainability achievements. Since 2022, we have published an integrated report covering us and our six generation subsidiaries for reporting domestic and international sustainability achievements such as energy transition, response to climate change, sustainable supply chain and safety management. In 2025, we have expanded the reporting boundary to encompass the entire energy value chain including KEPCO E&C, KEPCO Nuclear Fuel, KEPCO KPS, and KEPCO KDN. In each year since 2014, we have been selected as one of the notable companies in the Asia Pacific region in the global electricity utility sector by the Dow Jones Best-in-Class (DJBIC) Indices (formerly DJSI), which measures management performance in terms of contribution to sustainability.
In recognition of our efforts and achievements to reduce greenhouse gas emissions in response to global climate change, in May 2013, we obtained the Carbon Trust Standard certification issued by Carbon Trust, a British nonprofit organization with the goal of establishing a sustainable, low carbon economy. In 2015, we obtained recertification from Carbon Trust by satisfying even more rigorous evaluation criteria. We are also a participant of the Carbon Disclosure Project, an international organization that promotes transparency in informational disclosure of carbon management process. From 2016 to 2021 and again in 2023, we were recognized by the Carbon Disclosure Project and received honors in the energy and utility sector.
In October 2020, we stated that we intend to focus on low-carbon and eco-friendly overseas projects, such as new and renewable energy and combined-cycle gas power generation and not pursue new projects in coal-fired power plants. For our overseas coal-fired power plant projects, we intend to sell them in multiple stages by analyzing the conditions of the sale, including the valuation of projects, identification of potential buyers, consultation with stakeholders and prioritization of better deals. We also aim to carry out our combined-cycle gas power generation projects on the condition that they adopt new technologies, such as ammonia or hydrogen co-firing and CCUS, which can reduce carbon emissions. In the long run, we aim to achieve carbon neutrality by reorganizing our business portfolio to focus on decarbonization, renewable energy and new businesses.
In December 2020, we established an Environment, Social and Governance (“ESG”) Committee within our board of directors to reinforce ESG-based management system and to ensure continuous performance in this area. Our ESG Committee is charged with resolving major management issues related to ESG, establishing ESG management strategies and business plans and checking on the overall direction of sustainable management. From 2021, we established an ESG Advisory Committee to support the ESG Committee. By operating the ESG Committee and the ESG Advisory Committee, we closely monitor the risks and opportunities related to ESG. Furthermore, our generation subsidiaries have established ESG Committees composed of non-standing directors to closely monitor ESG issues and manage ESG opportunities and risks.
We and our generation subsidiaries declared the carbon-neutrality vision called “ZERO for Green” in November 2021. The slogans for the vision include (i) “Zero Emission” of carbon in the power generation sector through bold transition to carbon-free power sources such as renewable energy and hydrogen; (ii) “Reliable Energy” to ensure stable supply to clean electricity to consumers through preemptive measures and optimal operation of the power grid; and (iii) “On Time” to secure core technology for carbon neutrality in a timely manner by dramatically expanding research and development investment. Also, in December 2021, we and our generation subsidiaries established the Carbon Neutrality Promotion Committee composed of our management and external experts to establish Company-wide strategies for carbon neutrality and to strengthen internal and external communication.
To achieve carbon neutrality by 2050 as announced by the Government, the electric power sector, which includes us and accounts for 33.5% (as of 2024) of total national greenhouse gas emissions, needs to play a leading role. The electric power sector, in particular, needs to not only increase the proportion of renewable energy such as wind and solar power, but also support carbon reduction in other sectors such as industry,
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transportation, and buildings by electrifying energy consumption. As we are on the top of the value chain for the power industry as a whole, we established our role and strategy to achieve carbon-neutrality. We plan to accelerate the timely connection of planned nuclear power plants, expand renewable energy through proactive system development, lead the development of core carbon-neutral technologies, and contribute to the achievement of a carbon-neutrality in the Transformation sector by improving energy efficiency.
Furthermore, we and our generation subsidiaries have issued green bonds since 2021, with an aggregate principal amount of US$5,350 million as of December 31, 2025, to expand domestic and overseas renewable energy businesses and renewable energy related facilities.
The table below sets forth the number of emission control equipment installed at thermal power plants by our generation subsidiaries as of December 31, 2025.
KOSEP KOMIPO KOWEPO KOSPO EWP
Flue Gas Desulfurization System 12 9 9 12 10
Selective Non-catalytic Reduction System 2 — — — 2
Selective Catalytic Reduction System 22 28 20 37 24
Electrostatic Precipitation System 14 18 9 14 12
Low NO2 Combustion System 20 27 14 35 24
Total 70 82 52 98 72
In accordance with the Act on Allocation and Trading of Greenhouse Gas Emission Allowances, enacted in May 2012, the Government implemented a greenhouse gas emission trading system under which the Government will allocate the amount of permitted greenhouse gas emission to companies by industry and a company whose business emits more carbon than the permitted amount is required to purchase the right to emit more carbon through the Korea Exchange. The categories of allowances traded include the Korean Allowance Unit (KAU), which is the emissions allowance allocated to applicable companies by the Government; Korean Credit Unit (KCU), which is a tradable unit converted from external carbon offset certifications including the Korean Offset Credit; and Korean Offset Credit (KOC), which is the verified carbon offset credit obtained by companies for reducing carbon emissions through absorption or otherwise. The greenhouse gas emission trading system has been implemented in three stages. During the first phase (2015 to 2017), the Government gradually set up and conducted test runs of the trading system to ensure its smooth operation, allocating the greenhouse gas emission allowances free of charge. During the second phase (2018 to 2020), 97% of the greenhouse gas emission allowances were allocated free of charge, with 3% allocated through an auction. During the third phase (2021 to 2025), the Government has expanded the scale of the system with aggressive greenhouse gas emission reduction targets and allocating 10% of the greenhouse gas emission allowances through an auction. In November 2025, the Government announced an increase in the paid allocation ratio to 15% for non-power generation industries and up to 50% for power generation industries during the fourth phase (2026 to 2030).
In connection with the Climate Change Response Initiatives and the 2030 National Greenhouse Gas Reduction Roadmap announced by the Government in December 2016, the Government subsequently announced the Long-term Low Greenhouse Gas Emission Development Strategies, which presents a long-term vision and national strategy for achieving carbon neutrality in 2050, and the Nationally Determined Contributions (“NDC”), which sets forth the greenhouse gas reduction targets by 2030. According to the Enforcement Decree of the Framework Act on Carbon Neutrality and Green Growth to Cope with Climate Crisis established in March 2022 and the latest figures of NDC announced by the Government in March 2023, the national target level in 2030 was 436.6 million tons and represents 40% reduction as compared to 2018 and the target emission level for the Transformation sector (electricity and heating) as a whole which we are the part of was 145.9 million tons and represents 45.9% reduction as compared to 2018. In October 2021, in accordance with the Government’s goal of achieving carbon neutrality by 2050, the carbon neutrality committee has proposed two scenarios, both of them
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which aim to achieve net-zero domestic carbon dioxide emissions by 2050. Scenario A will completely suspend thermal power generation by 2050, while scenario B will actively utilize technologies such as CCUS while allowing some thermal power generation to continue beyond 2050. Following the National Basic Plan for Carbon Neutrality & Green Growth enacted in April 2023, the Government has mandated annual sector-specific greenhouse gas reduction targets for the next 20 years from 2023 to 2042 and measures to achieve such targets to be formulated and implemented every five years. In terms of the NDC, the national target emission level remained unchanged, but the target emission level in 2030 increased to 145.9 million tons, which represents a reduction rate of 45.9% compared to 2018 emission levels. The Government confirmed the 2035 NDC in November 2025, raising the country’s target emissions to up to 289.5 million tons by 2035, raising the reduction rate to 61% compared to 2018.
Adhering to such emission and greenhouse gas reduction requirement may result in significant additional compliance costs. For example, the daily market price of the KAUs traded through the Korea Exchange was Won 8,640 per ton in early 2015, and the price has increased continuously thereafter, reaching its peak price at Won 42,500 per ton on April 2, 2020. Since then, the price dropped to a record low of Won 7,200 in August 2023, with the price of KAU at Won 14,900 per ton as of March 24, 2026.
The table below sets forth the amount of annual emission from all generating facilities of our generation subsidiaries for the periods indicated. According to the Eleventh Basic Plan, the amount of CO2 emissions is expected to decrease due to the Government’s carbon-free energy conversion policy. We expect to abolish a total of 40 decrepit coal-fired power plants by 2038 and replace them with LNG power plants or carbon-free plants.
Year (1) SOx (g/MWh) NOx (g/MWh) TSP (2) (g/MWh) CO2 (kg/MWh)
2021 57 68 4 437
2022 47 58 4 406
2023 43 49 3 383
2024 44 46 3 366
Notes:
(1) The amounts of annual SOx, NOx and TSP emission for 2023 and 2024 are expected to be determined once the national statistics are confirmed.
(2) “TSP” means Total Suspended Particles.
For additional information, see Item 3.D. “Risk Factors—Risks Relating to KEPCO—We are subject to various environmental legislations, regulations and related Government initiatives, including in relation to climate change and carbon neutrality, which could cause significant compliance costs and operational liabilities.”
In order to comply with the current and expected environmental standards and address related legal and social concerns, we intend to continue to install additional equipment, make related capital expenditures and undertake several environment-friendly measures to foster community goodwill. For example, under the Persistent Organic Pollutants Management Act enacted in 2007, we are required to remove polychlorinated biphenyl, or PCBs, a toxin, from the insulating oil of our transformers by 2027. In addition, when constructing certain large new transmission and distribution facilities, we assess and disclose their environmental impact at the planning stage of such construction, and we consult with local residents, environmental groups and technical experts to generate community support for such projects. We exercise additional caution in cases where such facilities are constructed near ecologically sensitive areas such as wetlands or preservation areas. We also make reasonable efforts to minimize any negative environmental impact, for example, by using more environment-friendly technology and hardware. Additionally, 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. Furthermore, we and our subsidiaries acquired the ISO 14001 certification, an environmental management system widely adopted internationally, in 2007 and have made it a high priority to make our electricity generation and distribution more
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environment-friendly. In 2014, we were awarded the presidential award for environmental contributions as a corporate citizen, after scoring the highest among 102 corporations that competed for the award. In order to encourage the implementation of environment-friendly measures by other corporations and enhance environmental awareness at a social level, we have been disclosing our environment-related activities and achievements to the public through the Environment Information System managed by the Ministry of Environment since 2012.
Our environmental measures, including the use of environment-friendly but more expensive parts and equipment and allocation of capital expenditures for the installation of such facilities, may result in increased operating costs and liquidity requirement. The actual cost of installation and operation of such equipment and related liquidity requirement will depend on a variety of factors which may be beyond our control. There is no assurance that we will continue to be in material compliance with legal or social standards or requirements in the future in relation to the environment.
As part of our medium to long-term strategic initiatives, we plan to take other measures designed to promote the generation and use of environment-friendly or green energy. See Item 4.B. “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 program as described below.
The following table sets forth the generation capacity and generation volume in 2025 of our generation facilities that are powered by renewable energy sources.
Generation Capacity (megawatts) Generation Volume (gigawatt-hours)
Hydraulic Power(1) 650 1,464
Wind Power 190 77
Solar Energy 537 630
Fuel Cells 520 3,491
Others(2) 1,131 4,852
Subtotal 3,028 10,514
As percentage of total(3) 3.62 % 2.77 %
Notes:
(1) Excluding generation capacity and volume of pumped storage, which is generally not classified as renewable energy.
(2) From June 2024, dispatchable renewable energy was categorized as others.
(3) As a percentage of the total generation capacity or total generation volume, as applicable, of us and our generation subsidiaries.
In order to deal with shortage of fuel and other resources and also to comply with various environmental standards, in 2012 the Government adopted the Renewable Portfolio Standard program, which replaced the Renewable Portfolio Agreement which had been in effect from 2006 to 2011. Under this program, each of our generation subsidiaries is required to generate a specified percentage of total electricity to be generated by such generation subsidiary in a given year in the form of renewable energy or, in case of a shortfall, purchase a corresponding amount of a Renewable Energy Certificate (a form of renewable energy credit) from other generation companies whose renewable energy generation surpass such percentage. Pursuant to the Act on the Promotion of the Development, Use, and Diffusion of New and Renewable Energy and its Enforcement Decree, the target percentage was 13.0% in 2023, 13.5% in 2024 and 14% in 2025. This Act and its Enforcement Decree aim to raise target percentage to 25% by 2030, and the target percentage for each year from 2026 through 2030 as
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of the date of this annual report is as specified in the table below. In 2024, all six of our generation subsidiaries met the target through renewable energy generation and/or the purchase of a Renewable Energy Certificate. Our generation subsidiaries’ compliance with the 2025 target is currently under evaluation, and if any generation subsidiary is found to have failed to meet the target for 2025 or fails to meet the target for subsequent years, such generation subsidiary may become subject to fines. Accordingly, the proposed target percentages may result in additional expenses for our generation subsidiaries.
2025 2026 2027 2028 2029 2030
Target Percentage under Renewable Portfolio Standard 14.0 % 15.0 % 17.0 % 19.0 % 22.5 % 25.0 %
As to how we plan to finance our capital expenditures related to our environmental programs, see “—Capital Investment Program.”
In March 2017, the Electric Utility Act was amended to the effect that starting in June 2017, future national planning for electricity supply and demand in Korea should consider the environmental and safety impacts of such planning, such as desulfurization costs. Accordingly, the costs related to environmental and safety impacts such as the desulfurization costs, have been reflected in our variable cost of generating electricity since August 2019. In December 2019, the Regulation on the Operation of the Electricity Market was revised to reflect the cost of trading greenhouse gas emission allowances in our variable cost of generating electricity and the revision was implemented in January 2022.
In line with the spread of RE100, a global campaign by companies around the world to cover 100% of their electricity use with renewable energy by 2050, the Government introduced its own version of RE100 that allows companies and other consumers to choose energy sources from which their electricity is generated. In order for a domestic company to participate in RE100, it needs to enter into either a third-party PPA or a direct PPA, or general and industrial customers may also purchase renewable energy through us in a competitive bidding process and be issued with a certificate of use of renewable energy, which we refer to as the green premium system. On June 21, 2021, the Ministry of Trade, Industry and Resources announced the “Guidelines on Third-Party Power Purchase Agreements for Renewable Energy Generation” that stipulated the method of transaction of renewable energy power among third parties. The relevant legislation for the direct PPA was enacted in the National Assembly in March 2021 and has been in force since October 2021. The Ministry of Trade, Industry and Resources finalized and announced detailed guideline for direct PPA in September 2022. As of December 31, 2025, there are 13 third-party PPAs with total contracted capacity of 33.6 megawatts and 72 direct PPA with total contracted capacity of 836.7 megawatts, which are effective under related law and guideline. If there is an expansion in the use of direct PPA, it may adversely affect our market share in electricity sales. In addition to the PPA, the green premium system started in January 2021 and we, on behalf of Korea Energy Agency, are in charge of managing the bidding for renewable energy, receiving bid prices from winning companies, issuing a certificate of use of renewable energy to companies on a quarterly basis and receiving fees from Korea Energy Agency for our service.
Following the amendment to the Hydrogen Economy Promotion and Hydrogen Safety Management Act in June 2022 and its Enforcement Decree enacted in December 2022, the Minister of Climate, Energy and Environment has designated KEPCO and other entities under the Community Energy System to purchase hydrogen-generated electricity. Under such Act, we are required to enter into contracts with hydrogen generators that are selected through competitive bidding process.
The bidding market is comprised of the general hydrogen power market and the clean hydrogen power generation market, as categorized based on the type of fuel used. In consideration of the current ecosystem in which fuel cells are used, the general hydrogen power market is open to all kinds of hydrogen plants including plants using extracted or by-product hydrogen. On the other hand, the clean hydrogen power market is a market where only generators using clean hydrogen plants are allowed to participate. Clean hydrogen is categorized into carbon-free hydrogen, low-carbon hydrogen, and low-carbon hydrogen compounds (including ammonia)
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according to greenhouse gas emissions in the production and import procedure of hydrogen. According to the clean hydrogen certification system, hydrogen can be recognized as clean hydrogen if the CO2 emissions for the production of 1 kg of hydrogen is less than 4 kg or less. The Government has set the bidding volumes for 2023 to 2025 through a relevant notice as shown in the table below.
Year of bidding market commencement
2023 2024 2025
Year of commercial operation commencement Volume (GWh) Year of commercial operation commencement Volume (GWh) Year of commercial operation commencement Volume (GWh)
General hydrogen market 2025 1,300 2026 1,300 2027 1,300
Clean hydrogen market — — 2027 3,500 2028 3,000
The amount of hydrogen-generated electricity to be purchased by us is determined by the Minister of Trade, Industry and Energy after taking into consideration the Basic Plan and Hydrogen Economy Implementation Basic Plan and shall be determined by multiplying (i) the total amount to be purchased in the current year by (ii) the percentage of our purchase out of the total purchased amount in the year immediately preceding the year when the bidding market for the current year has been set up. The Minister shall allow us to reflect the cost arising from the purchase of hydrogen energy into the electricity tariff pursuant to the Act.
Social Programs
In 2025, as part of our safety management activities, we further strengthened our company-wide safety management framework, organizational capabilities and field-centered communication efforts. We operated a company-wide Safety Innovation Task Force and declared a new safety management vision, while intensifying preventive activities focused on the three major high-risk accident types—electric shock, falls and caught-in/between incidents—which had accounted for a significant portion of serious accidents in the past.
We also reinforced the standing and professionalism of our safety organization by elevating the Safety Innovation Division and establishing a new Safety Planning Team, while expanding dedicated safety personnel and implementing reward and training measures to enhance the accountability and participation of site managers and department heads. In addition, we strengthened field-centered safety communication through site manager-led inspections, CEO site inspections and on-site management briefing sessions, while also operating feedback and incentive programs to encourage the exercise of workers’ stop-work authority.
At the same time, we expanded investment in AI-based safety technologies and smart safety training, including internally developed smart glasses software and immersive safety training programs. We also improved the efficiency and consistency of our management system by digitalizing key safety documents through an integrated safety management platform.
Building goodwill with local communities is important to us in light of concerns among the local residents and civic groups in Korea regarding construction and operation of generation units, particularly nuclear generation units. The Act for Supporting the Communities Surrounding Power Plants and the Act on the Compensation and Support for Areas Adjacent to Transmission and Substation Facilities require that the generation companies and the affected local governments carry out various activities up to a certain amount annually to address neighboring community concerns. Pursuant to these Acts, we and our generation subsidiaries, in conjunction with the affected local and municipal governments, undertake various programs, including scholarships and financial assistance to low-income residents.
Under the Act for Compensation and Support for Areas Adjacent to Transmission and Substation Facilities, activities required to be undertaken under the Act are funded partly by the Electric Power Industry Basis Fund (see “—Sales and Customers—Electricity Rates”) and partly by KHNP as part of its budget. KHNP is required to
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make annual contributions to the affected local communities in an amount equal to Won 0.25 per kilowatt-hour of electricity generated by its nuclear generation units during the one-year period before the immediately preceding fiscal year, Won 5 million per thousand kilowatts of hydroelectric generation capacity and Won 0.5 million per thousand kilowatts of pumped-storage generation capacity. In addition, under Korean tax law, KHNP is required to pay local tax levied on its nuclear generation units in an amount equal to Won 1 (effective January 1, 2015, which reflects an increase from the previous Won 0.5 per kilowatt-hour of their generation volume in the affected areas) and Won 2 per 10 cubic meters of water used for hydroelectric generation.
The Act on the Compensation and Support for Areas Adjacent to Transmission and Substation Facilities, enacted in 2014, prescribes measures to be taken by power generation or transmission companies with respect to the communities adjacent to transmission and substation facilities. Under this Act, those who own land or houses in the vicinity of transmission lines and substation may claim compensation for damages or compel purchase of such properties by the power generation or transmission companies which are legally obligated in principle to pay for such damages or purchase such properties. In addition, under this Act, residents of communities adjacent to transmission and substation facilities are entitled to subsidies on electricity tariff as well as support for a variety of welfare projects and collective business ventures.
Under the Special Act for the National Power Grid Expansion, which took effect in 2025, the scope of compensation for landowners affected by transmission and substation facilities has been further expanded. This Act also establishes enhanced support for resident welfare projects and new grants for local governments where such facilities are installed, ensuring comprehensive assistance for the host communities.
Prior to the construction of a generation unit, our generation subsidiaries perform an environmental impact assessment which is designed to evaluate public hazards, damage to the environment and concerns of local residents. A report reflecting this evaluation and proposing measures to address the problems identified must be submitted to and approved by the Ministry of Climate, Energy and Environment following agreement with related administrative bodies prior to the construction of the unit. Our generation subsidiaries are then required to implement the measures reflected in the approved report. Despite these activities, civic community groups may still oppose the construction and operation of generation units (including nuclear units), and such opposition could adversely impact our construction plans for generation units (including nuclear units) and have a material adverse effect on our business, results of operations and cash flow.
Upon relocation of our corporate headquarters in November 2014, we developed and established Bitgaram Energy Valley as a smart energy hub city in Gwangju and Jeollanam-do, to attract and facilitate the growth of start-ups and research institutions related to new energy industries while contributing to the local economy, balanced regional development and job creation.
To achieve this goal, through industry-academic cooperation including partnerships with the Korea Institute of Energy Technology and the Korea Institute of Energy Research, we support the R&D efforts of companies, develop new technologies, and publish R&D results. We also seek to create new growth engines by assisting innovative companies with their technology development and commercialization as they enter the global market. As of December 31, 2025, we have signed agreements with 694 companies relating to investments in the Bitgaram Energy Valley. We are currently developing Bitgaram Energy Valley to establish a spontaneous industrial ecosystem, which will contribute to the power industry as well as the national economy.
Additionally, we continue to pursue businesses that promote co-prosperity with small and medium-sized enterprises (“SMEs”), such as cultivating startups, exploring for cooperative R&D projects with SMEs, and supporting export business. We also strive to strengthen the fundamental self-reliance of SMEs with continuous engagement, through improving their productivity, training specialists and also financial supports. In addition, by operating the ‘SMEs Energy Technology Market’, we are promoting cooperation between energy-related public institutions and SMEs. As of December 31, 2025, we designated 152 “innovation products” to support the early
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market entry and procurement linkage of technology innovation products developed by the SMEs with superior R&D capabilities.
Governance
We operate a risk management system to prevent possible risks in advance and effectively respond to them. The audit committee under the board of directors conducts audits of accounting and major management tasks and evaluates the operational status of the internal accounting management system. Since 2020, the ESG committee has also been established and operates under the board of directors to manage non-financial risks associated with environment, social, and governance issues.
We operate an ethical management system to meet our management needs and aim to make it systematic and effective. We provide the basic principles of conduct through ethical guidelines such as the Code of Ethics and the Code of Conduct, establish step-by-step strategies for the ethical management of our vision and management policies, and engage in relevant activities. See also Item 16.B. “Code of Ethics.” Also, in December 2023, we established a Compliance Office directly under our CEO, which is an independent organization to operate our risk management system. Our plan is to establish and operate a company-wide internal control system to minimize risks of corruption or misconduct.
See also Item 16.G. “Corporate Governance” for a further description of independence, diversity of our board and other committees thereunder.
Nuclear Safety
KHNP takes nuclear safety as its top priority and continues to focus on ensuring the safe and reliable operation of nuclear power plants. KHNP also focuses on enhancing corporate ethics and transparency in the operation of its plants.
KHNP has a corporate code of ethics and is firmly committed to enhancing nuclear safety, developing new technologies and improving transparency. KHNP has also established the “Statement of Safety Policy for Nuclear Power Plants” to ensure the highest level of nuclear safety. Furthermore, KHNP invests approximately 4% of its total annual sales into research and development for the enhancement of nuclear safety and operational performance.
KHNP implements comprehensive programs to monitor, ensure and improve safety of nuclear power plants. In order to enhance nuclear safety through risk-informed assessment, KHNP conducts probabilistic safety assessments, including for low power-shutdown states, for all its nuclear power plants. In order to systematically verify nuclear safety and identify the potential areas for safety improvements, KHNP performs periodic safety reviews on a 10-year frequency basis for all its operating units. These reviews have been completed for all of our nuclear power plants once or more. In order to enhance nuclear safety and plant performance, KHNP has established a maintenance effectiveness monitoring program based on the maintenance rules issued by the United States Nuclear Regulatory Commission, which covers all of KHNP’s nuclear power plants in commercial operation.
KHNP has developed the Risk Monitoring System for operating nuclear power plants, which it implements in all of its nuclear power plants. The Risk Monitoring System is intended to help ensure nuclear plant safety. In addition, KHNP has developed and implemented the Severe Accident Management Guidelines and is developing the Severe Accident Management Guidelines for Low Power-Shutdown States in order to manage severe accidents for all of its nuclear power plants.
KHNP conducts various activities to enhance nuclear safety such as quality assurance audits and reviews by the KHNP Nuclear Review. KHNP maintains a close relationship with international nuclear organizations in
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order to enhance nuclear safety. KHNP invites international safety review teams such as the World Association of Nuclear Operators (“WANO”) Peer Review Team to its nuclear plants for purposes of meeting international standards for independent review of its facilities. KHNP actively exchanges relevant operational information and technical expertise with its peers in other countries. For example, KHNP conducted WANO Pre-Startup Peer Reviews for Shin-Hanul #1 unit in 2024. The recommendations and findings from this event were shared with KHNP’s other nuclear plants to implement improvements at such plants. In addition, KHNP conducted the Operational Safety Review Team mission at the International Atomic Energy Agency for Saeul units 1 and 2 (formerly named as Shin-Kori units 3 and 4) in the second half of 2022. The purpose of such application was to ensure that KHNP nuclear generation units reflect the global safety standards.
The average level of radiation dose per unit amounted to a relatively low level of 0.26 man-Sv in 2025, which was substantially lower than the global average of 0.54 man-Sv/year in 2025 as reported in the WANO performance indicator report.
In response to the damage to the nuclear facilities in Japan as a result of the tsunami and earthquake in March 2011, the Government conducted additional safety inspections on nuclear power plants by a group of experts from governmental authorities, civic groups and academia. As a result of such inspections, the Government required KHNP to perform 46 comprehensive safety improvement measures. As of December 31, 2025, KHNP has completed implementation of 45 measures and is currently implementing one last measure. The Government also established the Nuclear Safety & Security Commission in October 2011 for neutral and independent safety appraisals. KHNP developed ten additional measures through benchmarking of overseas cases and internal analysis of current operations. KHNP completed implementation of all ten measures.
From time to time, our nuclear generation units may experience unexpected shutdowns. For example, on September 12, 2016, multiple earthquakes including a magnitude 5.8 earthquake hit the city of Gyeongju, a home to KHNP’s headquarters and Wolsong Nuclear Power Plants. Although there was no material safety issues, KHNP had manually stopped the operations of Wolsong #1, #2, #3, and #4 units according to the safety guidelines. All units have resumed their operations on December 5, 2016, with the approval by the Nuclear Power Safety Commission. KHNP finished implementing measures to improve the safety by reinforcing seismic capability of its core facilities and performing stress tests across all its nuclear power plants. In 2018, KHNP finished the implementation of such measures for 24 units and enhanced seismic capability of the core facilities to withstand a magnitude 7.0 earthquake (6.5 before implementation). As for the units under construction, Saeul #3 and 4 (formerly named as Shin-Kori #5 and #6), the core facilities will be able to withstand a magnitude 7.4 earthquake.
Low and intermediate level waste (“LILW”), and spent nuclear fuels (“SNFs”) are stored in temporary storage facilities at each nuclear site of KHNP. The temporary LILW storage facilities at the nuclear sites had been sufficient to accommodate all LILWs produced up to 2015. Korea Radioactive Waste Agency (“KORAD”) completed the construction of a LILW disposal facility in the city of Gyeongju, and government approval for its operations was obtained in December 2014.
In order to increase the storage capacity of temporary storage facilities for SNFs, KHNP has been pursuing various projects, such as installing high-density racks in SNFs pools and building dry storage facilities. Through these activities, we expect that the storage capacity for SNFs in all nuclear power plant sites will be adequate to temporarily accommodate all SNFs produced by the operation of nuclear power plants before the operation of an intermediate storage facility. In December 2021, the Government decided on the national policy for the management of SNFs (Reference: The second master plan for High-Level Radioactive waste management) to secure an intermediate storage and disposal facility. The national policy for the management of SNFs includes a temporary operation plan for on-site SNFs storage facility on nuclear power plants before the operation of the intermediate storage facility.
In 2009, the Radioactive Waste Management Act (“RWMA”) was enacted in order to centralize management of the disposal of SNFs and LILW and enhance the security and efficiency of related management
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processes. The RWMA designates KORAD to manage the disposal of SNFs and LILW. Pursuant to the RWMA, the Government has established the Radioactive Waste Management Fund. The management expense for LILW is paid when LILW is transferred to KORAD, and the charge for SNFs is paid based on the quantity generated every quarter. LILW-related management costs and charges for SNFs are reviewed by the Ministry of Climate, Energy and Environment every two years.
In September 2025, the Special Act on High-Level Radioactive Waste and its enforcement Decree was enacted, aiming to establish a legal framework for procedures and systems for the safe management of interim storage and permanent disposal of spent nuclear fuel.
In addition, in February 2021, in accordance with the Government’s guidelines for strengthening the safety of nuclear power plants, the period for verifying seismic resilience of major equipment was extended. Due to safety concerns, the construction periods of Saeul #3 and #4 (formerly named as Shin-Kori #5 and #6) have been extended to September 2026 and September 2027, respectively.
All of KHNP’s nuclear plants are currently in compliance with Korean law and regulations and the safety standards of the IAEA in all material respects. For a description of certain past incidents relating to quality assurance in respect of KHNP, see Item 3.D. “Risk Factors—Risks Relating to KEPCO—Our risk management policies and procedures may not be fully effective at all times.”
Decommissioning
Decommissioning of a nuclear power unit is the process whereby the unit is shut down at the end of its life, the fuel is removed and the unit is eventually dismantled. KHNP renewed the operating license of Kori #1, the first nuclear power plant constructed in Korea, which commenced operation in 1978, for an additional ten years in 2007. At the recommendation of the Ministry of Trade, Industry and Resources, KHNP has decided not to renew the operating license of Kori #1 and the initial phase of decommissioning (namely, safety inspection and removal of spent nuclear fuels) of Kori #1 has begun after its permanent shutdown in June 2017. In addition, Wolsong #1 permanently shut down in 2019 and is being prepared for decommissioning. KHNP retains full financial and operational responsibility for decommissioning its units.
KHNP has accumulated decommissioning costs as a liability since 1983. The decommissioning costs of nuclear facilities are defined by the Radioactive-Waste Management Act, which requires KHNP to credit annual appropriations separately. These costs are estimated based on studies conducted by the relevant committees, and are reviewed by the Ministry of Climate, Energy and Environment every two years. As of December 31, 2025, KHNP recorded an accrual of Won 28,541 billion for the costs of dismantling and decontaminating existing nuclear power plants, which consisted of dismantling costs of nuclear plants of Won 24,176.9 billion and decommissioning costs of spent nuclear fuels and radioactive waste of Won 4,364.1 billion.
Overseas Activities
We are engaged in a number of overseas activities. Such activities help us diversify our revenue streams by leveraging our and our subsidiaries’ operational experience from providing a full range of services from power plant construction to specialized engineering and maintenance services. We are also able to build strategic relationships with countries that are or may become our fuel providers.
The total installed capacity amounts to 37,339 megawatts, comprising 23,094 megawatts of thermal power capacity which includes coal-fired and gas-fired combined cycle power capacities. We have continuously expanded our overseas projects starting with an oil-fired power plant in Malaya, the Philippines in 1995. As of the end of December 2025, we are engaged in 30 projects in 12 countries across Asia, the Middle East, Latin America, and North America. In addition, we operate 5,600 megawatts of nuclear power capacity and 8,645 megawatts of renewable energy capacity.
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Throughout the years, we have sought to expand our project portfolio to include the construction and operation of conventional thermal generation units, nuclear generation units and renewable energy power plants, transmission and distribution network and mining and development of fuels. While strategically important, we believe that our overseas activities, as currently being conducted, are not in the aggregate significant in terms of scope or amount compared to our domestic activities. In addition, a number of the overseas contracts currently being pursued are based on non-binding memoranda of understanding and the details of such projects may significantly change during the course of negotiating the definitive agreements.
Many of our overseas operations require a significant amount of capital investment, and such costs may
unexpectedly and materially increase in the event of delays or other changes in circumstances, many of which are difficult to anticipate and are beyond our control. See Item 3.D. “Risk Factors—Risks Relating to KEPCO—We may require a substantial amount of additional indebtedness to refinance existing debt and for future capital expenditures” and Item 3.D. “Risk Factors—Risks Relating to KEPCO—We plan to pursue overseas expansion opportunities that may subject us to different or greater risks than those associated with our domestic operations.”
Generation Projects
Nuclear Generation Projects
In December 2009, following an international open bidding process, we entered into a prime contract for the original contract amount of US$18.6 billion with the Emirates Nuclear Energy Corporation (“ENEC”), a state-owned nuclear energy provider of the UAE, to design and construct four civil nuclear power generation units to be located in Barakah, a region approximately 270 kilometers from Abu Dhabi, for the UAE’s peaceful nuclear energy program. Under the contract, we and our subcontractors, some of which are our subsidiaries, are to perform various duties including, among others, designing and constructing four nuclear power generation units each with a capacity of 1,400 megawatts, supplying nuclear fuel for three fuel cycles including initial loading, with each cycle currently projected to last for approximately 18 months, and providing technical support, training and education related to plant operation. The contract amount of US$18.6 billion was increased to US$19.1 billion as per the amendment signed in November 2017. As the project has yet to be completed, we are in discussions with other parties to the contract about the costs from extension of the construction period and delay liquidated damages for the UAE nuclear power plant project. No assurance can be given whether any costs associated with the foregoing will not exceed the amounts recognized as provisions or otherwise have an adverse impact on our business, results of operations, financial condition and profitability.
On October 20, 2016, in order to foster a long-term strategic partnership and stable management of the units’ post-construction, we entered into an investment agreement with ENEC to jointly establish Barakah One PJSC, a special purpose company which oversees the operation and management of the nuclear power plant in Barakah, UAE. We have an 18% equity interest in Barakah One PJSC, and also have an 18% equity interest in Nawah Energy Company, a subsidiary of ENEC, which is also responsible for the operation and maintenance of the Barakah nuclear power plant. On December 20, 2018, the board of directors of KEPCO resolved to invest additional US$380 million in Barakah One PJSC. KEPCO’s additional contribution of US$1.22 billion was made in March 2025 under the related contracts. KEPCO’s equity interest in the project is 18%, which remains unchanged. The total project cost of the Barakah nuclear power plant is expected to be approximately US$29.5 billion. Barakah One PJSC successfully achieved the commercial operation of Unit #1, #2, #3, and #4 of Barakah nuclear power plant in April 2021, March 2022, February 2023 and September 2024 respectively, with an expected plant life span of 60 years. On August 25, 2022, KHNP signed a contract for the construction of turbine islands in El Dabaa nuclear power plant project in Egypt with Atomstroyexport JSC (“ASE JSC”), a subsidiary of Rosatom. ASE JSC had won an order for El Dabaa project from Egyptian Atomic Energy Agency in 2017 to build a nuclear power plant that consists of four reactors of which capacity is 1,200 megawatts each. KHNP will construct about 80 buildings and structures including turbine islands in four units of El Dabaa and supply equipment. The construction of the project began in 2023 and is planned to be completed in 2029.
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On June 27, 2023, KHNP entered into a contract for construction of a tritium removal facility at Cernavoda nuclear power plant site in Romania. The procurer is S.N.NUCLEARELECTRICA S.A., a government owned organization that operates two units of CANDU reactors at Cernavoda. The value of the contract is approximately 193 million Euros. KHNP will provide engineering (based on the design of the tritium removal facility provided by the client), procurement, construction and commissioning services. The term is 50 months and the commencement date is July 23, 2023.
Since March 2022, KHNP had been participating in a tender launched by Electrárna Dukovany II (“EDUII”), a subsidiary of České Energetické Závody, and it was selected as the preferred bidder in July 2024. On June 17, 2025, KHNP entered into a contract with EDUII for the construction of Dukovany Unit #5 and #6. The value of the contract is approximately KRW 25,861 billion.
We have estimated the probable outflow of economic benefits in relation to prolongation costs associated with the nuclear generation projects described above and have recognized a provision of KRW 1,450 billion as of December 31, 2025.
Non-nuclear Generation Projects
We are currently engaged in two major power projects in the Philippines: (i) a minority ownership of SPC Power Corporation, a local utility corporation engaged in independent power generation, electricity distribution and other businesses, and (ii) CFBC Coal Power Plant, a 206-megawatt power plant in Cebu on a build, operate and own basis. The plant construction was completed in May 2011 and it will be operated until 2036. The project cost of the CFBC Coal Power Plant was US$451 million, which was project-financed on a limited recourse basis. To fulfill our responsibility for carbon neutrality, we are currently planning to sell our interests in SPC Power Corporation and the CFBC Coal Power Plant.
In April 2007, we formed a limited partnership with Shanxi International Electricity Group and Deutsche Bank, which was approved by the Chinese government, to develop and operate power projects in Shanxi Province, China. The total capital investment in these projects amounted to US$1.33 billion, of which our capital investment was US$532 million. We expect to participate in the operation of the project for 50 years ending in 2057. The total capacity of these projects is 9,742 megawatts and our equity interest in the partnership is 42%.
In July 2008, a consortium consisting of us and Xenel of Saudi Arabia won the bid to build, own and operate a gas-fired power plant with installed capacity of 373 megawatts in Al Qatrana, near Amman, and we entered into definitive agreements in October 2009. Construction of this project was completed in December 2011, and the plant is currently in operation and will operate until 2035. The total project cost was US$461 million, out of which the consortium made an equity contribution of US$143 million and the remainder was funded by debt financing. We and Xenel own 80:20 equity interests in the project, respectively. As part of the asset rationalization plan for our overseas projects in operation, we are planning to sell a portion of our equity interest in Al Qatrana project.
In December 2008, we formed a consortium with ACWA Power International of Saudi Arabia and submitted a bid for the 1,204-megawatt oil-fired power project in Rabigh, Saudi Arabia. In March 2009, we were selected as the preferred bidder and in July 2009, we entered into a power purchase agreement (“PPA”) with Saudi Electricity Company. Construction of the project was completed in April 2013, and we will participate in the operation of the plant for 20 years. The total project cost was approximately US$2.5 billion. We currently hold a 40.0% equity interest in the joint venture, Rabigh Electricity Company, which operates the project.
In August 2010, we led a consortium and won the bid to build, own and operate the 433-megawatt Norte II gas-fueled combined-cycle electricity generation facility in Chihuahua, Mexico, as ordered by the Commission Federal de Electricidad (“CFE”) of Mexico. The consortium established a special purpose vehicle, KST Electric Power Company (“KST”), to act as the operating entity, and in September 2010, KST entered into a PPA with CFE for 25 years until 2038. The total cost of the project was approximately US$426 million and we hold a 56% equity interest in the consortium. Our wholly-owned subsidiary, KEPCO Energy Service Company, currently manages the operation of the project.
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In October 2010, a consortium that we are part of was selected by Abu Dhabi Water & Electricity Authority, a state-run utilities provider in the UAE, as the preferred bidder in an international bidding for the construction and operation of the combined-cycle natural gas-fired electricity generation facility in Shuweihat, UAE with aggregate capacity of 1,600 megawatts. Construction was completed in July 2014 and we will operate the plant until 2039. The total project cost was approximately US$1.4 billion, of which 20% was financed through equity investments by the consortium members and the remaining 80% through debt financing.
In January 2012, a consortium consisting of us, Mitsubishi Corporation and Wartsila Development & Financial Services of Finland was selected by National Electric Power Corporation, a state-run electricity provider in Jordan, to build and operate a 573-megawatt diesel engine power project in Al Manakher. Construction of this project was completed in October 2014 and the plant is currently in operation and will be operated until 2039. The total project cost was approximately US$760 million, of which the consortium made an equity contribution of approximately US$190 million and the remainder was funded by debt financing.
In March 2013, a consortium consisting of us and Marubeni, a Japanese corporation, was selected by the Ministry of Industry and Trade of Vietnam for construction and operation of a 1,200-megawatt coal-fired power plant in Thanh Hoa province, Vietnam. The construction was started in July 2018 and completed in July 2022. The plant is currently in operation and will operate until 2047. The total project cost was approximately US$2.5 billion, of which 24% have been funded by equity contribution and the remaining 76% by debt financing. The share capital of the special purpose entity in charge of this project is US$568 million, and we, Marubeni and Tohoku Power hold 50%, 40% and 10% equity interest in the special purpose entity, respectively.
In November 2019, we entered into an energy conversion agreement comprising of a PPA with the Guam Power Authority for a term of 25 years to construct and operate Ukudu gas-fired power plant in Guam, United States, including a 198-megawatt gas-fired power plant. We and EWP hold 60% and 40% shares in the project, respectively. The total project cost is approximately US$708 million, and we invested US$85 million for the equity interest. The construction of the project started on May 31, 2022 and the plant was completed in December 25, 2025. The plant is operated as a base load generator, replacing old heavy fuel power plants in Guam.
In January 2020, Pulau Indah Power Plant in Malaysia, a special purpose company that we own 25% of the shares, received a Letter of Notification to develop 1,200 megawatts combined-cycle gas-fired power plant from the Energy Commission of Malaysia, the host of the project. The construction started in December 2020 and was completed by March 1, 2025. The total project cost is expected to be approximately US$715 million, and invested approximately US$44 million for equity interest. We signed a PPA in August 2020 with Tenaga Nasional Berhad, which will be effective from March 2025 for a period of 21 years.
On June 30, 2020, the board of directors approved our plan to invest US$51 million in the expansion of two coal-fired power plants, Java 9 and Java 10, on the Indonesian island of Java. We invested together with PT Perusahaan Listrik Negara (“PLN”), an Indonesian state electricity company, and PT Barito Pacific Tbk., an Indonesian company. The total project cost was approximately US$3.31 billion and we, PLN and Barito Pacific will respectively own 15%, 51% and 34% shares in the joint venture. The joint venture currently manages the operation of two units of 1,000-megawatt generation capacity. The construction of Java 9 and 10 was completed in the second quarter of 2025. The joint venture is a party to a 25-year PPA with PLN.
On October 5, 2020, the board of directors approved our plan to invest US$237 million in the construction of Vung Ang 2 coal-fired power plant in Vietnam in exchange for 40% shares in the project. The new plant will be located in Ha Tinh Province, Vietnam, adjacent to Vung Ang 1 power plant and will consist of two units with 600 megawatts generation capacity each. We started the construction in October 2021 and the power plant is expected to be completed in 2026. Diamond Generating Asia, a subsidiary of Mitsubishi Corporation, a Japanese corporation, is the main sponsor of this project. We will operate this plant together with other co-investors for 25 years.
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In September 2022, we entered into an energy conversion agreement with Saudi Aramco with regard to the cogeneration plant at Jafurah, in the Kingdom of Saudi Arabia. Pursuant to the agreement, we will build a cogeneration plant with a capacity of approximately 317 megawatts of electricity generation and 694 kilo pounds per hour of steam output. When the construction is complete, this plant will supply electricity and steam to Jafurah Gas Plant for twenty years. We and Saudi Aramco hold 60% and 40% shares in the project respectively and the total project cost is expected to be approximately US$504 million. We started construction in the fourth quarter of 2022 and expect to commence commercial operation during the first half of 2026.
In November 2024, we were selected as the successful bidder with ACWA Power and Saudi Electricity Company for the Rumah 1 and Nairyah 1 gas-fired combined cycle power plant projects in the Kingdom of Saudi Arabia and entered into a power purchase agreement with Saudi Power Procurement Company (“SPPC”) with a term of 25 years. We will build power plants with a total capacity of 3,780 megawatts, and the total project cost is expected to be approximately US$4.1 billion. We hold a 30% share in the project, while ACWA Power and Saudi Electricity Company each hold a 35% share. We expect to commence commercial operation in the second quarter of 2028.
In December 2025, we entered into an energy conversion agreement with Saudi Aramco with regard to the Jafurah Phase 2 cogeneration plant, in the Kingdom of Saudi Arabia. Pursuant to the agreement, we will build a cogeneration plant with a capacity of approximately 331 megawatts of electricity generation and 1,025 kilo pounds per hour of steam output. When the construction is complete, this plant will supply electricity and steam to Jafurah Gas Plant for 16 years. This project utilizes the project company which was established for Jafurah Phase1 project in 2022, and we and Saudi Aramco hold 60% and 40% shares in the project respectively and the total project cost is expected to be approximately US$758 million. We expect to commence commercial operation in June 2029.
Renewable Energy, Transmission & Distribution Projects
We are currently pursuing overseas projects to increase sales and net profit from renewable energy and grid projects, diversify our businesses and actively address climate change. Specifically, we are looking at offshore wind power market, grid investment projects and large-scale clean development mechanism projects. We plan to expand our projects while aligning to the energy transition trend toward carbon neutrality.
Since 2004, joint ventures between us and China Datang Corporation of the People’s Republic of China have built and operated a number of wind farms in Inner Mongolia, Liaoning and Gansu provinces. We own 40% of these joint ventures, whose equity in the aggregate amount is approximately US$450 million. The projects are funded one-third by equity contributions and two-thirds by debt financing. As of December 31, 2025, the joint venture operates 22 wind farms with a total capacity of 1,017 megawatts and a 7-megawatt photovoltaic power station.
In December 2015, we entered into an agreement with the Ministry of Energy and Mineral Resources of Jordan to build, own and operate a wind farm with installed capacity of 89.1 megawatts in Fujeij in Ma’an Governorate, Jordan. Commercial operations commenced on July 14, 2019. Total project cost of approximately US$181 million was financed 41% by our equity investment and 59% by debt financing. As part of the asset optimization plan for our overseas projects under operation, we are currently planning to sell a portion of our equity interest in Fujeij project.
In June 2015, we entered into a memorandum of understanding with Energy Product (“EP”), a Japanese local developer, to build, own and operate a photovoltaic power station with a capacity of 28 megawatts, together with a 13.7-megawatt-hour energy storage system, in Chitose, Hokkaido Prefecture in Japan. The power station began operating in July 2017. The total project cost was approximately JPY 10.9 billion, of which 20% was financed through 80:20 equity investments by us and EP. In July 2021, our 15.1% equity interest and the entire equity stake of EP was sold to NH-Amundi. As a result, we now hold 65% and NH-Amundi holds 35% of the total equity interest.
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In June 2017, we won a project to build, own and operate a photovoltaic power station with a capacity of 60 megawatts and a 32 megawatt-hour energy storage system in Guam, United States for 25 years. The total project cost was approximately US$186 million, and we financed 22% of the cost through equity investment and held 100% of the equity interest. The remaining 78% was funded through debt and tax equity financing. We have entered into a PPA with Guam Power Authority in August 2018. The construction of the project started in May 2020 and commercial operation commenced in June 2022. The entire volume of electricity generated from the power station will be purchased by Guam Power Authority until 2047.
In September 2017, we entered into an agreement with Recurrent Energy to operate 3 solar photovoltaic projects in southern California, United States, with a capacity of 235 megawatts for 34 years. KEPCO partnered with Corporate Partnership Fund, a Korean private equity fund. We invested US$ 38 million in the project.
In October 2018, we entered into a Share Purchase Agreement and Share Subscription Agreement to operate a photovoltaic power station with a capacity of 50 megawatts in Calatagan in the Philippines. We own 38% interest and financed PHP 2.25 billion (approximately US$ 42.8 million) for the project, of which 80% was financed through equity investments and the remaining 20% through debt financing.
In October 2019, KEPCO and Sprott Korea as a consortium entered into a Share Purchase Agreement and Shareholders Agreement with Canadian Solar INC to develop and operate a photovoltaic power station with a capacity of 294 megawatts in Sonora and other states of Mexico for 35 years. We invested US$ 41 million in the project, and the transaction marks KEPCO’s first investment in the solar market in Mexico. The project consists of three power plants, two of which are currently in operation, and the other power plant is expected to start commercial operation in 2026.
In July 2021, a consortium comprised of us, Japan’s Kyushu Electric Power Co., Inc. and Électricité de France has been nominated as the successful bidder for the HVDC-VSC subsea transmission system construction and operation project of UAE announced by the Abu Dhabi National Oil Company (“ADNOC”), and clinched the deal through an international tender against numerous competitors. This project will supply power for the offshore production and operations facilities of ADNOC, by constructing and operating for 35 years a subsea transmission system along 2 routes with a total length of 272 kilometers. This mega project is worth US$3.8 billion and is expected to generate a stable profit through a long-term transmission agreement with the procurer for 35 years. Construction of the project commenced in September 2022 and remains ongoing. Commercial operation is expected in the fourth quarter of 2026.
In August 2023, we entered into an agreement with Ministerio de Energía y Minas to construct and expand three 138/12.5 kilovolts distribution substations in the Dominican Republic. In total, 200 megavolt-ampere of transformation facilities will be constructed, and the total project cost is expected to be approximately US$ 38 million. We will be in charge of design, procurement and construction, and we expect to complete construction of the substations by March 2027.
In September 2024, a consortium comprised of us, Korea East-West Power Co., Ltd. and Samsung C&T Corporation was awarded the Phase 4 renewable energy project in Guam. The consortium is currently developing and constructing a new photovoltaic power generation station and a battery energy storage system, with expected capacities of 132 megawatts and 326 megawatt-hour, respectively. Under the power purchase agreement, the Guam Power Authority will purchase the entire volume of electricity generated from the power station for a period of 25 years. The total project cost is expected to be approximately US$ 511 million. Commercial operation is expected to begin in the first quarter of 2028.
In October 2024, a consortium comprised of us, Abu Dhabi Future Energy Company and GD Power Development Co., Ltd was selected as a shortlisted bidder for the 2,000 megawatt Sadawi Solar PV Independent Power Plant by the SPPC. The consortium entered into the major project agreements in November 2024 and is developing a new photovoltaic power station. Under the power purchase agreement, SPPC will purchase the
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entire volume of electricity generated from the power station for a period of 25 years. The total project cost is expected to be approximately US$ 1.1 billion, and construction commenced in July 2025 and is currently ongoing. Commercial operation is expected to begin in the second half of 2027.
In October 2025, a consortium consisting of KEPCO, Etihad Water and Electricity, and Nesma Renewable Energy was awarded the contract for the 1,500 MW Dawadmi Wind Independent Power Plant by SPPC. The principal project agreements became effective in January 2026, including a power purchase agreement under which SPPC will purchase the entire electricity output generated from the plant for a period of 25 years. The total project cost is estimated at approximately US$ 879 million, with construction scheduled to commence in 2026. Commercial operation is anticipated to begin in the second half of 2028.
Exploration and Production Projects
Previously, we were engaged in a bituminous coal mining project in Bylong, Australia. In July 2015, KEPCO Bylong submitted a development application to the State Government of New South Wales (the “NSW”) of Australia. In September 2019, the Independent Planning Commission of the NSW, i.e., the state regulator, refused to accept our development application. After many rounds of legal proceedings, our request for appeal to the High Court of Australia was finally rejected in February 2022. As of December 31, 2025, we have invested approximately KRW 810 billion in the Bylong project and the impairment loss has accrued to approximately KRW 554 billion. We are currently reviewing various alternative plans to minimize our loss.
Our nuclear generation subsidiary, KHNP, is also pursuing development projects for procurements of uranium in countries including Canada, France and Niger.
Our subsidiaries, KOSEP, KOMIPO, KOWEPO, KOSPO and EWP, have been engaged in mining projects in Kalimantan, Indonesia, collectively holding a 20% equity interest in PT Bayan Resources TBK.
North Korea
Gaeseong Industrial Complex
Since 2005, we have provided electricity to the industrial complex located in Gaeseong, North Korea, which was established pursuant to an agreement made during the summit meeting of the two Koreas in June 2000. The Gaeseong Industrial Complex is the largest economic project between the two Koreas and is designed to combine Korea’s capital and entrepreneurial expertise with the availability of land and labor of North Korea. In March 2005, we built a 22.9 kilovolt distribution line from Munsan substation in Paju, Gyeonggi-do to the Gaeseong Industrial Complex and became the first to supply electricity to pilot zones such as ShinWon Ebenezer. In April 2006, we started to construct a 154 kilovolt, 16 kilometer transmission line connecting Munsan substation to the Gaeseong Industrial Complex as well as Pyunghwa substation in the complex and began operations in May 2007.
At the end of 2015, we supplied electricity to 254 units, including administrative agencies, support facilities and resident corporations, using a tariff structure identical to that of Korea. However, we suspended power transmission to the Gaeseong Industrial Complex since February 11, 2016 following the Government’s decision to halt operations of the industrial complex to impede North Korea’s utilization of funds from the industrial complex to finance its nuclear and missile programs. On August 14, 2018, we resumed power transmission to the facilities that are part of the Joint Liaison Office between South and North Korea but we suspended it again on June 16, 2020 in compliance with the request by the Ministry of Unification of the Korean Government. It has been reported in the media that the parties have now temporarily closed the Joint Liaison Office in accordance with the request by North Korea to stop the spread of COVID-19 and all KEPCO personnel have withdrawn from the facilities without resuming power transmission since June 16, 2020.
As of December 31, 2025, the book value of our facility located at the Gaeseong Industrial Complex was Won 0. For the year ended December 31, 2025, there are no trade receivables related to the companies residing in
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Gaeseong Industrial Complex. It is currently uncertain if we can exercise the property rights for our facility in the Gaeseong Industrial Complex. No assurance can be given that we will not experience any material losses as a result of the suspension of this project or failure of the project as a result of a breakdown or escalation of hostilities in the relationship between Korea and North Korea. See Item 3.D. “Risk Factors—Risks Relating to Korea and the Global Economy—Tensions with North Korea could have an adverse effect on us and the market value of our shares.”
Insurance
We and our generation subsidiaries carry insurance covering against certain risks, including fire, in respect of key assets, including buildings, equipment, machinery, construction-in-progress and procurement in transit, as well as, in the case of us, directors’ and officers’ liability insurance. We and our generation subsidiaries maintain casualty and liability insurance against risks related to our business to the extent we consider appropriate. Other than KHNP, neither we nor our generation subsidiaries separately insure against terrorist attacks. These insurance and indemnity policies, however, cover only a portion of the assets that we own and operate and do not cover all types or amounts of loss that could arise in connection with the ownership and operation of these assets.
Substantial liability may result from the operations of our nuclear generation units, the use and handling of nuclear fuel and possible radioactive emissions associated with such nuclear fuel. KHNP maintains property and liability insurance against risks of its business to the extent required by the related law and regulations or considered as appropriate and otherwise self-insures against such risks. KHNP carries insurance for its generation units against certain risks, including property damage, nuclear fuel transportation and liability insurance for personal injury and property damage. KHNP carries property damage insurance covering up to US$1 billion per accident for all properties within its plant complexes, which includes property insurance coverage for acts of terrorism up to US$300 million and for breakdown of machinery up to US$300 million. In addition to the insurance on operating nuclear power generation units, KHNP has construction insurance for Saeul #3 and #4 (formerly named as Shin-Kori #5 and #6) and Shin-Hanul #3 and #4. KHNP maintains nuclear liability insurance for personal injury and third-party property damage for coverage of up to 300 million Special Drawing Rights, or SDRs, which amounts to approximately US$406.47 million, at the rate of 1 SDR = US$1.354910 as posted on the Internet homepage of the International Monetary Fund on July 31, 2025 per plant complex, for a total coverage of 1.8 billion SDRs. KHNP is also the beneficiary of a government indemnity with respect to such risks for damage claims of up to Won 300 million SDRs per nuclear plant complex, for a total coverage of 1.8 billion SDRs. Under the Nuclear Damage Compensation Act of 1969, as amended, KHNP is liable only up to 900 million SDRs, per single accident per plant complex; provided that such limitation will not apply where KHNP intentionally causes harm or knowingly fails to prevent the harm from occurring. KHNP will receive the Government’s support, subject to the approval of the National Assembly, if (i) the damages exceed the amount of insurance coverage and (ii) the Government deems such support to be necessary for the purposes of protecting damaged persons and supporting the development of nuclear energy business. KHNP carries insurance for its generation units and nuclear fuel transportation, and we believe that the level of insurance is generally adequate and is in compliance with relevant laws and regulations. In addition, KHNP is the beneficiary of government indemnity which covers a portion of liability in excess of the insurance. However, such insurance is limited in terms of amount and scope of coverage and does not cover all types or amounts of loss which could arise in connection with the ownership and operation of nuclear plants. Accordingly, material adverse financial consequences could result from a serious accident or a natural disaster to the extent it is neither insured nor covered by the Government indemnity. See Item 3.D. “Risk Factors—Risks Relating to KEPCO—The amount and scope of coverage of our insurance are limited.”)
Competition
As of December 31, 2025, we and our generation subsidiaries owned approximately 53.4% 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 condition and results of operations.
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In particular, we compete with independent power producers with respect to electricity generation. The independent power producers accounted for 36.3% of total power generation in 2025 and 46.6% of total generation capacity as of December 31, 2025. As of December 31, 2025, there were 44 independent power producers in Korean electricity market, excluding 7,355 renewable energy producers. Since 2013, private enterprises are permitted to own and operate coal-fired power plants in Korea as the Ministry of Trade, Industry and Resources approved plans for independent power producers to construct coal-fired power plants under the Sixth Basic Plan announced in February 2013. Under the Tenth Basic Plan announced in January 2023, three coal-fired power plants are planned to be constructed by independent power producers by 2024. Two of the three coal fired power plants planned for construction were completed in 2024 and the remaining one was completed in 2025. Furthermore, independent power producers are permitted to build additional generation capacity (whether coal-fired or not), our market share in Korea may decrease.
In addition, under the Community Energy System adopted by the Government in 2004, a minimal amount of electricity is supplied directly to consumers on a localized basis by independent power producers outside the cost-based pool system. Such system is used by our generation subsidiaries and most independent power producers to distribute electricity nationwide. The purpose of this system is to geographically decentralize electricity supply and thereby reduce transmission losses and improve the efficiency of energy use. These entities do not supply electricity on a national level but are licensed to supply electricity on a limited basis to their respective districts under the Community Energy System. To date, the Community Energy System has not been widely adopted, especially in light of the significant level of capital expenditure required for such direct supply. However, if the Community Energy System were to be widely adopted, it may erode our currently dominant market position in the generation and distribution of electricity in Korea and may have a material adverse effect on our business, results of operations and financial condition.
Our market dominance in the electricity distribution in Korea also may face potential erosion in light of the recent Proposal for Adjustment of Functions of Public Institutions (Energy Sector) announced by the Government in June 2016. This proposal contemplates a gradual opening of the electricity trading market to the private sector although no detailed roadmap has been provided for such opening. It is currently premature to predict to what extent, or in what direction, the liberalization of the electricity trading market will happen. Nonetheless, any significant liberalization of the electricity trading market may result in substantial reduction of our market share in electricity distribution in Korea, which would have a material adverse effect on our business, results of operation and cash flows.
The electric power industry, which began its liberalization process with the establishment of our power generation subsidiaries in April 2001, may become further liberalized in accordance with the Restructuring Plan. See Item 4.B. “Business Overview—Restructuring of the Electric Power Industry in Korea.”
In the residential sector, consumers may use natural gas, oil and coal for space and water heating and cooking. However, currently there is no practical substitute for electricity for lighting and other household appliances, which is available on commercially affordable terms.
In the commercial sector, electricity is the dominant energy source for lighting, office equipment and air conditioning. For its other uses, such as space and water heating, natural gas and, to a lesser extent, oil, provide competitive alternatives to electricity.
In the industrial sector, electricity is the dominant energy source for a number of industrial applications, including lighting and power for many types of industrial machinery and processes that are available on commercially affordable terms. For other uses, such as heating, electricity competes with oil and natural gas and potentially with gas-fired combined heating and power plants.
Regulation
We are a statutory juridical corporation established under the KEPCO Act for the purpose of ensuring a stable supply of electric power and further contributing toward the sound development of the national economy
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through facilitating development of electric power resources and carrying out proper and effective operation of the electricity business. The KEPCO Act (including the amendment thereto) prescribes that we engage in the following activities:
1. development of electric power resources;
2. generation, transmission, transformation and distribution of electricity and other related business activities;
3. research and development of technology related to the businesses mentioned in items 1 and 2;
4. overseas businesses related to the businesses mentioned in items 1 through 3;
5. investments or contributions related to the businesses mentioned in items 1 through 4;
6. businesses incidental to items 1 through 5;
7. development and operation of certain real estate held by us to the extent that:
a. it is necessary to develop certain real estate held by us due to external factors, such as relocation, consolidation, conversion to indoor or underground facilities or deterioration of our substation or office; or
b. it is necessary to develop certain real estate held by us to accommodate development of relevant real estate due to such real estate being incorporated into or being adjacent to an area under planned urban development; and
8. other activities entrusted by the Government.
The KEPCO Act currently requires that our profits be applied in the following order of priority:
• first, to make up any accumulated deficit;
• second, to set aside 20.0% or more of profits as a legal reserve until the accumulated reserve reaches one-half of our capital;
• third, to pay dividends to shareholders;
• fourth, to set aside a reserve for expansion of our business;
• fifth, to set aside a voluntary reserve for the equalization of dividends; and
• sixth, to carry forward surplus profit.
• As of December 31, 2025, we had a legal reserve of Won 1,605 billion and a voluntary reserve for expansion of our business of Won 567 billion. For the avoidance of doubt, all such reserves have been calculated on a consolidated basis.
On December 28, 2022, the National Assembly of Korea passed an amendment to Article 16 of KEPCO Act which increased our debt ceiling on total outstanding debt securities on a separate basis to be no greater than five times (or six times if the Minister of the Ministry of Climate, Energy and Environment approves if it is urgently required to resolve a business crisis situation) the sum of our share capital and reserves updated at the end of each year. Such share capital and reserves are calculated on a separate basis under the KEPCO Act. Before such amendment, our debt ceiling was two times the sum of our share capital and reserves. Such increase in debt ceiling will be effective until December 31, 2027 and we may make use of the new debt ceiling to issue more debt securities to cover our losses, refinance existing debt and finance new capital expenditures. However, if the sum of our share capital and reserves decreases (including as a result of continued significant net losses), our debt ceiling will decrease as well and there will be no assurance that we can meet our funding requirements for capital or operational expenditures or debt repayment obligations, which situation could have a material adverse impact on our business, results of operations and financial condition.
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We are under the supervision of the Ministry of Climate, Energy and Environment, which has principal supervisory responsibility (in consultation with other Government agencies, such as the Ministry of Finance and Economy, as applicable) over us with respect to the appointments of our directors and our other senior management as well as approval of electricity tariff rate adjustments, among others.
Because the Government owns part of our capital stock, the Government’s Board of Audit and Inspection may audit our books.
The Electric Utility Act requires that separate licenses be obtained for generation, transmission, distribution and sale of electricity, subject to limited exceptions. We hold the licenses to transmit, distribute and sell electricity, and each of our six generation subsidiaries hold an electricity generation license. The Electric Utility Act governs the formulation and approval of electricity rates in Korea. See “—Sales and Customers—Electricity Rates” above. Under the current Electric Utility Act, a single business entity cannot engage in two or more types of electricity businesses concurrently. Notwithstanding the foregoing, our generation subsidiaries are permitted to directly participate in the development of renewable energy projects, and we may also participate through the establishment of new entities.
Our operations are subject to various laws and regulations relating to environmental protection and safety.
Financial Soundness Plan and Related Activities
In light of the general policy guideline of the Government for public institutions (including us and our generation subsidiaries) to reduce their respective overall debt levels, we and our generation subsidiaries have, in consultation with the Ministry of Climate, Energy and Environment and the Ministry of Finance and Economy, set target debt-to-equity levels every year and undertaken various programs to reduce debt and also strived to improve the overall financial stability.
In 2022, we and our generation subsidiaries established and implemented a five-year financial soundness plan in accordance with the guidelines of the Ministry of Finance and Economy. This plan includes sale of assets (sale of non-core assets such as idle properties, investment shares, and overseas coal power plants), expenditure restructuring (adjustment or deferral of investment without affecting stable power supply and safety management), cost efficiency improvement through intense low-budget strategies, profit growth through business system improvements, and capital expansion through revaluation of tangible assets like land. We and our generation subsidiaries have been complying with this plan to date.
In addition, since 2023, we have implemented additional measures to lower our debt levels. The measures included extension of the existing financial soundness plan, sale of additional assets (including saleable assets in the greater Seoul region and investment shares), lease of office buildings, downsizing of headquarters and business office re-organizations and launching an emergency management innovation committee within our company.
Despite our best efforts, however, for reasons beyond our control, including macroeconomic environments, government regulations and market forces (such as international market prices for our fuels), we cannot assure whether we or our generation subsidiaries will be able to successfully reduce debt burdens or otherwise improve our financial health or to a level that would be optimal for our capital structure. If we or our generation subsidiaries fail to do so or the measures taken by us or our generation subsidiaries to reduce debt levels or improve financial health have unintended adverse consequences, such developments may have an adverse effect on our business, results of operations and financial condition.
Establishment of a University
In order to enhance the competitiveness of the national energy industry, cultivate high-quality talents to revitalize the Bitgaram Energy Valley, and secure a differentiated research platform to create a new energy market, we established a university in Jeollanam-do Province in the southwestern region of Korea in accordance with the Government’s five-year state management plan.
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The university, which is called as Korea Institute of Energy Technology (“KENTECH”) is a research and entrepreneurship-oriented university specializing in the energy field and aims to be a small yet robust university with approximately 100 faculty members and 1,000 students. On April 17, 2020, the Ministry of Education authorized us to form a legal entity for the university. The total funding expected through 2025, which is when the university’s organization is expected to be completed, is Won 828.9 billion, excluding the land that was freely endowed to us. The funding for establishing the university will be jointly borne by us and the central and municipal governments.
For ten years after the commencement of the university in 2022, we expect to receive funding (to be used as expenses for operating the university) from the municipal government in the amount of Won 200 billion. In addition, we expect to receive funding from the central government that is at least in the same amount as we expect to receive from the municipal government. After taking into account the funding from the governments, we anticipate our contribution to the university through 2026 to be approximately Won 630 billion depending on the amount of contribution from the central government.
On August 8, 2019, our board of directors resolved to make an initial contribution of Won 60 billion for the promotion, initial operation and the design of the university campus, and the contribution was made in 2020. On March 24, 2021, a special law was passed in the National Assembly and finally enacted on April 1, 2021, giving an autonomy to the university and laying out the basis for direct financial support from the central and municipal governments. On May 21, 2021, our board resolved to make an additional contribution of Won 64.5 billion to the university and Won 41.3 billon of such contribution was made in December 2021. The remaining contribution of Won 23.2 billion was made by our affiliates. In addition, on July 15, 2022, our and our affiliates’ boards of directors decided to contribute Won 47.9 billion for funding the construction and operation of major campus facilities and completed the contribution in December 2022. In 2023, our and our affiliates’ boards of directors decided to contribute additional Won 110.6 billion, of which we contributed Won 70.8 billion and our affiliates contributed the remaining Won 39.8 billion. In 2024, our and our affiliates’ boards of directors decided to contribute an additional Won 177.8 billion, of which we contributed Won 113.8 billion and our affiliates contributed the remaining Won 64 billion. In 2025, our and our affiliates’ boards of directors decided to contribute an additional Won 71.7 billion, of which we contributed Won 45.9 billion and our affiliates contributed the remaining Won 25.8 billion. In March 2026, our board of directors decided to make an initial contribution of Won 48.8 billion as part of the contribution for the fiscal year 2026.
On March 2, 2022, KENTECH held its first entrance ceremony with congratulatory remarks from the President of Korea. On February 27, 2026, KENTECH held its first commencement ceremony with congratulatory remarks from senior officials of the central government and heads of municipal governments. As of 2026, the university is expected to have a total enrollment of 531 undergraduate students and 212 graduate students.
Currently, we are striving to adjust facility costs and tighten the budget of KENTECH as part of our initiative to improve our financial conditions. In order to minimize potential financial risks, we plan to let the university generate its own profits too, by, for example, attracting development funds and research and development investments and commercializing new technology among other means. Despite our efforts and anticipated funding from the municipal and central governments, we cannot assure you that the magnitude of our expected or actual contribution to the university will not have material adverse effects on our profit margins, results of operations or cash flows.
Proposed Sale and Purchase of Equity Interests
KEPCO Engineering & Construction Co., Inc.
Pursuant to the Third Phase of the Public Institution Reform Plan announced by the Government in August 2008, we conducted the initial public offering of Korea Engineering and Construction Co., Inc., or KEPCO E&C formerly known as Korea Power Engineering Co., Ltd., in December 2009 for gross proceeds to us of Won
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165 billion, following which we owned 77.9% of KEPCO E&C’s shares. In furtherance of the Public Institution Reform Plan and to improve our financial profile, we sold our equity interests representing 3.1%, 4.0%, 4.5% and 0.54% of KEPCO E&C shares in November 2011, December 2013, December 2014 and December 2016, respectively, in each case to third party investors. As part of our financial soundness plan, on June 24, 2022, our board of directors decided additional sale of KEPCO E&C shares. We sold 14.77% of KEPCO E&C’s shares on December 27, 2023. We currently hold a 51.0% equity interest in KEPCO E&C.
Korea Electric Power Industrial Development Co., Ltd.
In 2003, we privatized Korea Electric Power Industrial Development, or KEPID, formerly our wholly-owned subsidiary, by selling 51.0% of its equity interest to Korea Freedom Federation. Pursuant to the Fifth Phase of the Public Institution Reform Plan announced by the Government in 2009, we sold 20% of the KEPID shares through additional listing.
Cybersecurity
Cybersecurity presents an ever-evolving challenge to the electric power industry, and we and our generation subsidiaries have identified cybersecurity as a key enterprise risk. Our operations require the continuous availability of critical information and operational technology systems, sensitive customer and employee data, and infrastructure information, all of which are targets for malicious actors. In order to effectively respond to such cybersecurity risk, we have established various cybersecurity management systems and cybersecurity threat response solutions and have also implemented other prevention and response measures.
In accordance with laws and regulations, we have established and implemented a cybersecurity management system, which is called “Cybersecurity GRC System,” through which we identify, evaluate and manage cybersecurity risks. Additionally, the National Intelligence Service and the Ministry of Climate, Energy and Environment perform regular audits to identify, evaluate and manage material risks from cybersecurity threats in accordance with the Basic Guidelines for National Information Security and the detailed guidelines for information security issued by the Ministry of Climate, Energy and Environment.
We have formed an Information Security Committee under the supervision of our information security department. The Information Security Committee’s responsibilities include, among others, conducting investigations into cybersecurity incidents and developing preventive strategies. Moreover, we and our generation subsidiaries have jointly established a Cybersecurity Committee, a cybersecurity oversight group comprised of senior management teams of the respective companies, including Chief Information Security Officers, to monitor cybersecurity policies and provide strategic direction for the prevention, detection, mitigation and remediation of cybersecurity risks.
We use contractual terms to impose cybersecurity requirements on third-party service providers for compliance with our cybersecurity policies, including the requirement to immediately inform us of any occurrence of cybersecurity threats during the provision of their service. We and our generation subsidiaries conduct training, policies, technical and procedural controls and mitigation plans to address risks from cybersecurity threats.
In anticipation of the amendment of the Act on Promotion of Information and Communications Network Utilization and Information Protection in January 2020, we designated a Chief Information Security Officer (“CISO”) who is dedicated to cybersecurity management. In late 2020, we reorganized our security management organization to enhance its independence by transferring it from our Safety and Security Department to Co-prosperity and Cooperation Division. All material cybersecurity-related matters are promptly notified to the CISO, who provides updates on security control to the Chief Business Management Officer on a weekly basis. Under further amendment to the Act on Promotion of Information and Communications Network Utilization and Information Protection in December 2021, our generation subsidiaries also designated a CISO and reported their
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designation to the Ministry of Science and ICT of the Government. In February 2025, in order to strengthen our cyber threat response system, we elevated the former team-level unit to the Information Security Department under the Business Management Division.
Since 2021, we have formed a team in collaboration with the National Intelligence Service and other institutions to participate in the international cybersecurity attack and defense exercise (Locked Shields) hosted by the NATO Cooperative Cyber Defense Centre of Excellence. By participating in this exercise, we are able to enhance our ability to collaborate against cybersecurity attacks on critical infrastructure. In addition, since 2021, for the first time as a public corporation in Korea, we have started hosting annually the Electric Sector Cybersecurity Contest, in which more than 20 organizations, including our generation subsidiaries, universities, and high schools, participate. By hosting this competition, we are bolstering our capacity to respond to cybersecurity attacks on power grids jointly with our generation subsidiaries and attracting skilled information security personnel to join us.
In 2021, we introduced personal information pseudonym processing system. In order to prevent the leakage of personal information, we have also implemented Digital Rights Management (“DRM”) and personal information detection solution on our computers. To strengthen personal information protection, we assigned a dedicated staff to manage personal information protection in 2022, implemented personal information detection solution used in data transmission between internal and external networks, and established personal information exposure detection system that automatically detects when personal information is present or exposed on an Internet website.
In 2023, we implemented comprehensive measures to address ransomware threats targeting our electric power infrastructure. This included tailored solutions and reinforcement of our ICT system’s backup and recovery capabilities. Furthermore, we established and fully operationalized a backup security control center to ensure continued responses to cybersecurity threats during potential disasters. Collaborating with the Korea Internet & Security Agency, we introduced security enhancement initiatives such as the “Bug Bounty” program. Additionally, we developed and deployed automatic security vulnerability diagnosis software to identify and fix cybersecurity blind spots. Our aim is to establish a robust system that not only prevents cybersecurity threats but also enables swift responses in case of a breach.
In 2024, we participated as a representative public institution in “Cyber Summit Korea (CSK) 2024”, the first international cybersecurity event hosted by the National Intelligence Service of Korea. During this event, we took part in international cyber defense training exercises, demonstrating our enhanced cyber defense capabilities in the global energy sector. We have worked to improve our security management system for information systems and ICT service projects and have established comprehensive measures to protect personal data on our public websites. We have also worked to build a secure cloud-based working environment, prioritizing protection of sensitive company internal information as well as personal information.
With the growing adoption of AI technologies, there is an increasing demand for AI solutions tailored to KEPCO’s business areas to improve operational efficiency in the power sector. To this end, we are in the process of developing a mid-to-long-term master plan, which includes identifying areas where AI may be used and implementing them in stages. We also plan to launch pilot projects to verify the performance, usability, and security of these AI technologies. To ensure the safe use of AI platforms, we plan to apply a range of security measures in accordance with the National Intelligence Service’s “Security Guidelines for National Network Protection Systems.” These include user authentication, prevention of confidential data leakage and malicious content infiltration, and the establishment of a real-time monitoring system to detect cyber-attack attempts, such as hacking.
KHNP is also exposed to ongoing cyber threats, and accordingly is continuing efforts to strengthen its security management system by maintaining the international security standard, ISO27001, and the Korean standard, Personal Information & Information Security Management System certification. In September 2019,
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KHNP established an organization dedicated to nuclear control security in accordance with the Government’s strengthened information security regulation. Also, in 2023, KHNP established the Control System Security Section within the Cyber Security Control Center to strengthen cybersecurity response capabilities.
Item 4.C. Organizational Structure
As of December 31, 2025, we have 169 subsidiaries, 107 associates and 122 joint ventures (not including any special purpose entities).
Subsidiaries
Our wholly-owned six generation subsidiaries are KHNP, KOSEP, KOMIPO, KOWEPO, KOSPO and EWP. Our non-generation subsidiaries include KEPCO E&C, KEPCO KPS, KEPCO NF, and KEPCO KDN. For a full list of our subsidiaries, including foreign subsidiaries, and their respective jurisdiction of incorporation, please see Exhibit 8.1 attached to this annual report.
Associates and Joint Ventures
An associate is an entity over which we have significant influence and that is neither a subsidiary nor a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of the investee but does not have control or joint control over those policies. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement (i.e. joint ventures) have rights to the net assets of the arrangement.
The table below sets forth each of our associates and joint ventures as of December 31, 2025 by name, the percentage of our shareholdings and their principal activities.
Ownership (%) Principal Activities
Associates:
Korea Gas Corporation (9) 20.47 Importing and wholesaling LNG
Korea Electric Power Industrial Development Co., Ltd. 29.00 Electricity metering and others
Gangwon Wind Power Co., Ltd. (1) 15.00 Power generation
Hyundai Green Power Co., Ltd. 29.00 Power generation equipment consignment and operation service
Korea Power Exchange (2) 100.00 Management of power market and others
Taebaek Guinemi Wind Power Co., Ltd. (26) 67.25 Power generation
Daeryun Power Co., Ltd. (1) 6.85 Power generation
KNH Solar Co., Ltd. 27.00 Power generation
SPC Power Corporation (27) 38.00 Power generation
Gemeng International Energy Co., Ltd. 42.00 Power generation
PT. Cirebon Electric Power 27.50 Power generation
KNOC Nigerian East Oil Co., Ltd. (3) 14.63 Resources development
KNOC Nigerian West Oil Co., Ltd. (3) 14.63 Resources development
PT Wampu Electric Power 46.00 Power generation
PT. Bayan Resources TBK 20.00 Resources development
S-Power Co., Ltd. 49.00 Power generation
Xe-Pian Xe-Namnoy Power Co., Ltd. 25.00 Power generation
PT. Mutiara Jawa 29.00 Manufacturing and operating floating coal terminal
Noeul Green Energy Co., Ltd. 29.00 Power generation
Goseong Green Power Co., Ltd. 29.00 Power generation
Gangneung Eco Power Co., Ltd. 29.00 Power generation
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Ownership (%) Principal Activities
Shin Pyeongtaek Power Co., Ltd. 40.00 Power generation
Haeng Bok Do Si Photovoltaic Power Co., Ltd. 28.00 Power generation
Dongducheon Dream Power Co., Ltd. (4) 33.61 Power generation
Jinbhuvish Power Generation Pvt. Ltd. (1) 5.16 Power generation
Daejung Offshore Wind Power Co., Ltd. 46.59 Power generation
GS Donghae Electric Power Co., Ltd. 34.00 Power generation
Daegu Photovoltaic Co., Ltd. 29.00 Power generation
Busan Green Energy Co., Ltd. 29.00 Power generation
Hansuwon KNP Co., Ltd. 28.98 Electric material agency
Korea Electric Power Corporation Fund (5) 98.09 Developing electric enterprises
Energy Infra Asset Management Co., Ltd. (31) 9.90 Asset management
YaksuESS Co., Ltd. 29.00 Installing ESS related equipment
Nepal Water & Energy Development Company Private Limited (6, 29) 66.10 Construction and operation of utility plant
Gwangyang Green Energy Co., Ltd. 20.00 Power generation
PND solar Co., Ltd. 29.00 Power generation
Hyundai Eco Energy Co., Ltd. (1) 19.00 Power generation
YeongGwang Yaksu Wind Electric Co., Ltd. (1) 9.63 Power generation
Green Energy Electricity Generation Co., Ltd. 29.00 Power generation
Korea Energy Solutions Co., Ltd. 20.00 R & D
ITR Co., Ltd. (29, 30) 8.03 R & D
STN Co., Ltd. 20.00 Technical testing and consulting
Indeck Niles Development, LLC 50.00 Power generation
Indeck Niles Asset Management, LLC 33.33 Power generation
Hanwha Corporation-linked Sunlight Power Special Private Equity Investment Trust No. 1 49.00 Holding company
Suwon New Power Co., Ltd. 39.90 Power generation
Gwangbaek Solar Power Investment Co., Ltd. 44.00 Power generation
Go deok Clean Energy Co., Ltd. 40.00 Fuel cell generation
SureDataLab Co., Ltd. (29) 0.35 R & D
SEP Co., Ltd. 21.26 R & D
Hankook Electric Power Information Co., Ltd. (11) 16.16 R & D
Tronix Co., Ltd. (11) 12.50 R & D
O2&B Global Co., Ltd. 20.00 R & D
Muan Sunshine Solar Power Plant Co., Ltd. 20.00 Power generation
Bigeum Resident Photovoltaic Power Co., Ltd. 27.31 Power generation
Goesan Solar Park Co., Ltd. 29.00 Power generation
Saemangeum Heemang Photovoltaic Co., Ltd. 35.00 Power generation
Bitgoel Eco Energy Co., Ltd. 49.25 Power generation
Jeju Gimnyeong Wind Power Co., Ltd. 30.00 Power generation
Seoroseoro Sunny Power Plant Co., Ltd. 42.58 Power generation
Muan Solar park Co., Ltd. 20.00 Power generation
YuDang Solar Co., Ltd. 20.00 Power generation
Anjwa Smart Farm & Solar City Co., Ltd. 20.00 Power generation
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Ownership (%) Principal Activities
KPE Green Energy Co., Ltd. 25.36 Power generation
G.GURU Co., Ltd. (29) 14.42 R & D
UD4M Co., Ltd. (8) 12.50 R & D
Dongbu Highway Solar Co., Ltd. 20.00 Power generation
Seobu Highway Solar Co., Ltd. 20.00 Power generation
Korea Energy Data Co., Ltd. 29.37 R & D
Gangneung Sacheon Fuel Cell Co., Ltd. 41.00 Power generation
Taebaek Gadeoksan Wind Power Co., Ltd. 34.00 Power generation
Chuncheon Green Energy Co., Ltd. 45.00 Power generation
Yeomsubong Wind Power Co., Ltd. 29.00 Power generation
Yeongyang Wind Power Corporation II 30.00 Power generation
Haeparang Energy Co., Ltd. 25.00 Power generation
Saemangeum Sebit Power Plant Co., Ltd. (10) 55.14 Power generation
PlatformN. Co., Ltd. 29.58 R & D
PT. Cirebon Energi Prasarana (7) 10.00 Power generation
Green Radiation Co., Ltd. (11,39) 8.74 R & D
Future Convergence Technology Laboratory. Co., Ltd. 20.12 R & D
Eco Motion Co., Ltd. 20.00 R & D
REC’s Innovation Co., Ltd. (31) 11.04 R & D
ACE 20.00 R & D
Environment and Energy Co., Ltd. (11) 10.54 R & D
Santiago Solar Power SpA 50.00 Power generation
Yanggu Floating Photovoltaic Power Plant Inc. 29.00 Power generation
Power Embedded 23.33 R & D
Changwon SG Energy Co., Ltd. (11) 18.78 Power generation
Donpyung Technology. Co., Ltd. 20.00 R & D
HORANG ENERGY Inc. 40.00 Power generation
Hoenggye Renewable Energy Co., Ltd 36.12 Power generation
Haman Green Energy Co., Ltd. 35.00 Power generation
Songsan Green Energy Co., Ltd. (6) 60.00 Power generation
SkyPic Inc. 20.00 R & D
HyChangwon Fuel Cell. Co., Ltd. 40.00 Power generation
Dreams Co.,Ltd. (11) 11.00 R & D
DEEPAI Co.,Ltd. (11, 36) 1.20 R & D
Amaala Sustainable Company for Energy LLC (7) 10.00 Power generation
Remal First Holding Company 30.00 Holding company
Naseem First Holding Company 30.00 Holding company
Cheonwang Green Energy Co., Ltd. 40.00 Power generation
Namjeju Bitdream Energy Co., Ltd. 50.00 Power generation
Jeju Bukchon BESS Power Plant Co., Ltd. 41.00 Power generation
Commerce and Industry Energy Co., Ltd. 24.46 Power generation
KI Tech Co., Ltd. 24.70 R & D
Enlight Energy Advanced Industry Venture Fund 28.00 Holding company
Gunsan Green Energy Co., Ltd. 42.63 Power generation
Joint Ventures:
Shuweihat Asia Power Investment B.V. 49.00 Holding company
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Ownership (%) Principal Activities
Shuweihat Asia Operation & Maintenance Company (12) 55.00 Maintenance of utility plant
Waterbury Lake Uranium L.P. (13,29) 29.45 Resources development
ASM-BG Investicii AD 50.00 Power generation
RES Technology AD 50.00 Power generation
KV Holdings, Inc. (27) 40.00 Power generation
KEPCO SPC Power Corporation (12,27) 60.00 Construction and operation of utility plant
Gansu Datang Yumen Wind Power Co., Ltd. 40.00 Power generation
Datang Chifeng Renewable Power Co., Ltd. 40.00 Power generation
Datang KEPCO Chaoyang Renewable Power Co., Ltd. 40.00 Power generation
Rabigh Electricity Company (13) 40.00 Power generation
Rabigh Operation & Maintenance Company Limited 40.00 Maintenance of utility plant
Jamaica Public Service Company Limited 40.00 Power generation
KW Nuclear Components Co., Ltd. 45.00 Manufacturing
Busan Shinho Solar Power Co., Ltd. 25.00 Power generation
Global Trade Of Power System Co., Ltd. (14) 29.00 Exporting products and technology of small or medium business by proxy
Expressway Solar-light Power Generation Co., Ltd. 50.00 Power generation
Amman Asia Electric Power Company (12) 60.00 Power generation
KAPES, Inc. (12) 51.00 R & D
Honam Wind Power Co., Ltd. 29.00 Power generation
Korea Power Engineering Service Co., Ltd. 29.00 Construction and service
Chun-cheon Energy Co., Ltd. 29.90 Power generation
Yeonggwangbaeksu Wind Power Co., Ltd. (14) 15.00 Power generation
Nghi Son 2 Power LLC 50.00 Power generation
Kelar S.A. (12) 65.00 Power generation
PT. Tanjung Power Indonesia 35.00 Power generation
Incheon New Power Co., Ltd. (16) 29.00 Power generation
Seokmun Energy Co., Ltd. 29.00 Power generation
Daehan Wind Power PSC 50.00 Power generation
Barakah One Company (17) 18.00 Power generation
Nawah Energy Company (17) 18.00 Operation of utility plant
MOMENTUM 33.33 International thermonuclear experimental reactor construction management
Daegu Green Power Co., Ltd. (18) 29.00 Power generation
Yeonggwang Wind Power Co., Ltd. 46.00 Power generation
Chester Solar IV SpA (15) 90.00 Power generation
Chester Solar V SpA (15) 90.00 Power generation
Diego de Almagro Solar SpA (15) 90.00 Power generation
South Jamaica Power Company Limited 20.00 Power generation
Daesan Green Energy Co., Ltd. 35.00 Power generation
RE Holiday Holdings LLC 50.00 Power generation
RE Pioneer Holdings LLC 50.00 Power generation
RE Barren Ridge 1 Holdings LLC 50.00 Power generation
RE Astoria 2 LandCo LLC 50.00 Power generation
RE Barren Ridge LandCo LLC 50.00 Power generation
Laurel SpA (15) 90.00 Power generation
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Ownership (%) Principal Activities
KIAMCO KOWEPO Bannerton Hold Co Pty Ltd (14) 12.37 Power generation
Cheong-Song Noraesan Wind Power Co., Ltd. (13) 29.01 Power generation
Chester Solar I SpA (15) 90.00 Power generation
Solar Philippines Calatagan Corporation 38.00 Power generation
Saemangeum Solar Power Co., Ltd. (19) 81.01 Power generation
Chungsongmeon BongSan wind power Co., Ltd. (14) 29.00 Power generation
Jaeun Resident Wind Power Plant Co., Ltd. (14) 29.00 Power generation
Dangjin Eco Power Co., Ltd. 34.00 Power generation
Haemodum Solar Co., Ltd. 49.00 Power generation
Yangyang Wind Power Co., Ltd. 50.00 Power generation
HORUS SOLAR, S.A. DE C.V. (20) 14.95 Renewable power generation
RECURSOS SOLARES PV DE MEXICO II, S.A. DE C.V. (20) 14.95 Renewable power generation
SUNMEX RENOVABLES, S.A. DE C.V. (20) 14.95 Renewable power generation
Stavro Holding II A.B. 20.00 Holding company
Solaseado Solar Power Co., Ltd. 39.00 Power generation
Yeongam Solar Power Co., Ltd. (14) 19.00 Power generation
Samsu Wind Power Co., Ltd. (14) 19.00 Power generation
Pulau Indah Power Plant Sdn. Bhd. 25.00 Power generation
NH-Amundi Global Infrastructure Investment Private Investment Trust 21 29.53 Holding company
Shin-han BNPP Private Investment Trust for East-West Sunlight Dream (12) 90.00 Holding company
PT Barito Wahana Tenaga 30.61 Power generation
Cheongna Energy Co., Ltd. (19) 50.10 Generating and distributing vapor and hot/cold water
Naepo Green Energy Co., Ltd. 29.20 Power generation
Boim Combined Heat and Power Generation Co., Ltd. (21) 30.66 Power generation
OneEnergy Asia Limited 40.00 Power generation
KAS INVESTMENT I LLC (13) 29.89 Holding company
KAS INVESTMENT II LLC (13) 29.89 Holding company
Energyco Co., Ltd. 29.00 Power generation
CAES, LLC 36.00 Holding company
Hapcheon Floating Photovoltaic Power Plant Inc. (14) 49.00 Power generation
Busan Industrial Solar Power Co., Ltd. 28.02 Power generation
Bitsolar Energy Co., Ltd. 27.10 Power generation
Pulau Indah O&M Sdn. Bhd. (14) 40.00 Power generation
Guadalupe Solar SpA (22) 60.00 Power generation
Omisan Wind Power Co., Ltd. 42.00 Power generation
Foresight Iberian Solar Group Holding, S.L. (22) 75.00 Power generation
Yeongwol Eco Wind Co., Ltd. 29.00 Power generation
Gurae Resident Power Co., Ltd. 29.00 Power generation
Cheongju Eco Park Co., Ltd. 29.00 Power generation
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Ownership (%) Principal Activities
Enel X Midland Photovoltaic, LLC 20.00 Power generation
Geumsungsan Wind Power Co., Ltd. 29.00 Power generation
KEPCO KPS CARABAO Corp. (16) 40.00 Utility plant maintenance
Prime Swedish Holding AB 45.00 Holding company
Goheung New Energy Co., Ltd. 46.15 Power generation
Gunsan Land Solar Co., Ltd. (22,28) 75.29 Power generation
International Offshore Power Transmission Holding Company Limited 35.00 Undersea transmission network operation
Pyeongchang Wind Power Co., Ltd. (25) 58.00 Power generation
Eumseong Eco Park Co., Ltd. 29.00 Power generation
Changwon Nu-ri Energy Co., Ltd. (14) 61.00 Fuel cell generation
PungBack Wind Farm Corporation (24) 32.89 Power generation
Trumbull Asset Management, LLC (25) 78.00 Holding company
S-Power Chile SpA 50.00 Power generation
Seungmun Green Energy 33.00 Power generation
Seobusambo highway photovoltaics Co., Ltd. (23) 80.00 Power generation
Yangyang Suri Wind Power Co., Ltd. (13) 29.00 Power generation
KEPCO for Power Company (32) 60.00 Power generation
Taebaek Wind Power Co., Ltd. (33) 60.00 Power generation
Kumyang Eco Park Co., Ltd. 29.00 Power generation
Jeongeup Green Power Co., Ltd. (34) 44.86 Power generation
Hadong E-factory Co., Ltd. (13) 29.99 Power generation
Namyangju Combined Heat and Power Co., Ltd. (35) 70.10 Generating and distributing vapor and hot/cold water
Samcheok Eco Materials Co., Ltd. (37) 25.54 Recycling fly ashes
Wadi Noor Solar Power Company SAOC 50.00 Power generation
Fairhaven Energy Storage LLC 35.00 Power generation
Rutile BESS Holdings, LLC 50.00 Holding company
Trumbull Development Partners, LLC (38) 56.23 Holding company
Imha Floating Photovoltaic Power Plant Inc. (13) 49.00 Power generation
EDFR KOWEPO AJBAN PV HOLDING LIMITED 50.00 Holding company
Roof One Energy Co., Ltd. 48.00 Holding company
Taean Haetdeulwon Solar Power Co., Ltd. 45.00 Power generation
Haetbyeotgil Solar Power Co., Ltd. 30.00 Power generation
Seongseo Neulpureun Energy Co., Ltd. 49.80 Power generation
Luluah SKY Energy Holding Ltd. (34) 15.00 Power generation
KES Yona Holdings LLC (38) 80.00 Holding company
Siraj AlTaqa AlNazifa 20.00 Power generation
Nour Ibri Solar Power Company 30.77 Power generation
Lucy Equity Holdings, LLC 20.00 Power generation
Notes:
(1) The effective percentage of ownership is less than 20%. However, the Group can exercise significant influence by virtue of its contractual right to appoint directors to the board of directors of the entity, and by strict decision criteria of the Group’s financial and operating policy of the board of directors.
(2) The effective percentage of ownership is 100%. However, the Government regulates the Group’s ability to make operating and financial decisions over the entity, as the Government requires maintaining arms-length
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transactions between KPX and the Group’s other subsidiaries. Accordingly, the entity is not classified as a consolidated subsidiary. The Group can exercise significant influence by virtue of right to nominate directors to the board of directors of the entity.
(3) The effective percentage of ownership is less than 20%. However, the Group can exercise significant influence by virtue of its contractual right to appoint one out of four members of the steering committee of the entity. Moreover, the Group has significant financial transactions, which can affect its significant influence on the entity.
(4) The effective percentage of ownership is 34.01% considering the conversion of redeemable convertible preferred stock into ordinary stock.
(5) The effective percentage of ownership is more than 50% but the Group does not hold control over relevant business while it exercises significant influence by participating in the Investment Decision Committee. Accordingly, the entity is classified as an associate.
(6) The effective percentage of ownership is more than 50% but the Group does not hold control over the entity according to the shareholders’ agreement. Accordingly, the entity is classified as an associate.
(7) The effective percentage of ownership is less than 20%. However, the entity is classified as an associate because the Group exercises significant influence over the decisions related to finance and operation.
(8) The effective percentage of ownership is 14.29% due to the acquisition of treasury stocks. The effective percentage of ownership is less than 20%. However, the Group exercises significant influence over the decisions related to finance and operation by virtue of right to nominate directors to the board of directors of the entity.
(9) The effective percentage of ownership is 21.66%, considering hybrid bonds.
(10) The effective percentage of ownership is more than 50% but the Group does not hold control over relevant business while it exercises significant influence by participating in the Investment Decision Committee. Accordingly, the entity is classified as an associate.
(11) The effective percentage of ownership is less than 20%. However, the entity is classified as an associate because the Group exercises significant influence over the entity.
(12) The effective percentage of ownership is more than 50%. However, according to the shareholders’ agreement, all critical financial and operating decisions must be agreed to by all ownership parties and the Group can exercise same voting rights as other shareholders at the board of directors. Accordingly, the entities are classified as joint ventures.
(13) The effective percentage of ownership is less than 50%. However, the investment is classified as a joint venture because decisions regarding significant financial and operating policies require the unanimous consent of all parties sharing control.
(14) According to the shareholders’ agreement, the parties have joint control over all decisions related to finance and operation. Accordingly, the entity is classified as joint ventures.
(15) Although the Group holds majority of shares in the entities marked above by acquiring additional shares for the year ended December 31, 2025, the entities are classified as joint ventures due to the shareholders’ agreement requiring unanimous approval from the entities’ board of directors for making material decisions on financial and operational policies.
(16) The joint arrangement which the Group has joint control is structured through a separate company. The parties have joint control over the joint arrangement are classified as joint ventures, judging that they have rights to the net assets of the arrangement.
(17) The effective percentage of ownership is less than 50%. However, decisions in relevant activities must be agreed by ownership parties. Accordingly, the entity is classified as joint ventures.
(18) Although the nominal percentage of ownership is 29%, the effective percentage of ownership is 54.24%, considering the interest of financial investors as a liability component.
(19) The effective percentage of ownership is more than 50%. However, decisions in relevant activities must be agreed by all ownership parties. Accordingly, the entity is classified as a joint venture.
(20) The effective percentage of ownership is less than 50%. However, according to the shareholders’ agreement, decisions related principal operation must be agreed by all ownership parties. Accordingly, the entity is classified as a joint venture.
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(21) According to the Boim Combined Heat and Power Generation Co., Ltd. Investment Agreement signed in March 2011, the Group has a commitment to guarantee principal and certain returns on shares of REC’s Innovation Co., Ltd. (formerly, Wang San Engineering Co., Ltd.). held by NH Power 2nd Co., Ltd. and the National Agricultural Cooperative Federation. Since NH Power 2nd Co., Ltd. and the National Agricultural Cooperative Federation have put option regarding their share of the entity, the Group was deemed to have acquired an additional 15.6% stake. As a result, the effective percentage of ownership is 46.3% in the current and prior period. In accordance with shareholders’ agreement signed during the current period, the Group has joint control with other investors in making important financial and operation decisions, so it has been reclassified from an associate to a joint venture.
(22) The effective percentage of ownership is more than 50%. However, decisions in relevant activities must be agreed by all ownership parties. Accordingly, the entity is classified as a joint venture.
(23) Although the effective percentage of ownership is more than 50%, decisions in relevant activities must be agreed by all members of the board of directors.
(24) The effective percentage of ownership is 37%, considering potential common stock.
(25) The effective percentage of ownership is more than 50%. However, decisions in relevant activities must be agreed by all members of the board of directors. Accordingly, the entity is classified as a joint venture.
(26) The effective percentage of ownership is more than 50%. However, by the shareholders’ agreement, the Group does not hold control over relevant business while it exercises significant influence by participating in the Investment Decision committee. Accordingly, the entity is classified as an associate.
(27) The Group is planning to sell its investment in SPC Power Corporation, KEPCO SPC Power Corporation, and KV Holdings, Inc. and the timing of and proceeds from such sales transaction is not specified as of December 31, 2025.
(28) The nominal percentage of ownership is 75.29% and the effective percentage of ownership is 53.83%, as the Group has an obligation to provide excessive dividend income to Gunsan City when a certain rate of return defined in the shareholders’ agreement is met.
(29) During the period ended December 31, 2025, the Group’s ownership interest in the entity changed due to a disproportionate capital increase by the financial investors.
(30) Although the Group’s effective percentage of ownership is less than 20%, the entity has been classified as an associate as the Group has significant influence on the entity considering the fact that ordinary resolutions passed at the shareholders’ meeting require the majority decision and the Group has the right to elect the entity’s directors.
(31) Although the Group’s effective percentage of ownership is less than 20%, the Group can exercise significant influence on the entity through its contractual right to appoint one director to the entity’s board of directors.
(32) Although the Group’s effective percentage of ownership is more than 50%, the entity is classified as a joint venture since the entity’s material financial and operational decisions require unanimous agreement of members in the board of directors due to the shareholders’ agreement.
(33) Although the Group’s effective percentage of ownership is more than 50%, the entity is classified as a joint venture considering the minimum number of the entity’s board of directors’ members required to agree for making decision on material financial and operational policies due to the joint shareholders’ agreement.
(34) Although the Group’s effective percentage of ownership is less than 50%, the entity is reclassified as a joint venture considering the Group can exercise significant influence on the entity due to the Group’s contractual right to appoint a director to the entity’s board of directors and the minimum number of the entity’s board of directors members required to agree for making decision on material financial and operational policies in accordance with the joint shareholders’ agreement.
(35) Although the Group’s effective percentage of ownership is more than 50%, the entity is classified as a joint venture since the entity’s material financial and operational decisions require unanimous agreement of members in the board of directors.
(36) The effective ownership interest is 1.32%, considering convertible redeemable preferred shares.
(37) Although the Group’s effective percentage of ownership is less than 50%, the entity is reclassified as a joint venture considering the minimum number of the entity’s board of directors’ members required to agree for making decision on material financial and operational policies as the joint shareholders’ agreement revised in the year ended December 31, 2025.
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(38) Although the Group’s effective percentage of ownership is more than 50%, the entity is classified as a joint venture since the entity’s material financial and operational decisions require unanimous agreement of the representative committee due to the shareholders’ agreement.
(39) The effective ownership interest is 10%, considering convertible redeemable preferred shares.
Item 4.D. Property, Plant and Equipment
Our property consists mainly of power generation, transmission and distribution equipment and facilities in Korea. See Item 4.B. “Business Overview—Power Generation,” “—Transmission and Distribution” and “—Capital Investment Program.” In addition, we own our corporate headquarters building complex at 55 Jeollyeok-ro, Naju-si, Jeollanam-do, 58322, Korea. As of December 31, 2025, the net book value of our property, plant and equipment was Won 187,752 billion. As of December 31, 2025, the net book value of our investment properties, which are accounted for separately from our property, plant and equipment, amounted to Won 239 billion. No significant amount of our properties is leased. There are no material encumbrances on our properties, including power generation, transmission and distribution equipment and facilities.
Pursuant to a Government plan announced in 2005, which mandated relocation of the headquarters of select government-invested enterprises from the Seoul metropolitan area to other provinces in Korea as part of an initiative to foster balanced economic growth in the provinces, we, our generation subsidiaries and certain of our subsidiaries relocated their respective headquarters to designated locations during 2014 and 2015. Our headquarters are currently located in Naju in Jeollanam-do, while the headquarters of our six generation subsidiaries and other subsidiaries are located in various cities outside of Seoul across Korea.
In connection with the relocation of our headquarters, in September 2014 we entered into an agreement to sell the property housing our prior headquarters to a consortium consisting of members of the Hyundai Motor group for Won 10,550 billion through an open bidding. The sale was completed in September 2015.
During 2025, we completed the disposal of 155 properties on a separate basis (including residential properties, storage spaces, and substation lots that are located in Korea) which are not directly related to our operations for an aggregate sale price of approximately Won 312 billion. The book value of such properties amounted to Won 33 billion, representing 0.4% of our total real properties as of December 31, 2025. The foregoing sales reflect our ongoing efforts to improve our financial soundness through related financial stabilization plan and enhance our management efficiency, selling non-core properties that have no direct relations to electricity facilities.