Power market operation 발표

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  • 그래프 교체예정 : 지속가능경영보고서 p.13 ‘ 전력수요와 시장가격 ’
  • Power market operation 발표

    1. 1. Power Market Operation Sang-Jin Chung T &J Construction. Co. Ltd ☎ +82-10-5234-6134 [email_address]
    2. 2. Market Issues Ⅳ Ⅳ II I III Power Business Overview Electricity Market Recent Market Results
    3. 3. Power Business Overview I Electric Power System Generation Sites & Fuel Mix Transmission System Network Peak Demand & Capacity Margin
    4. 4. CHARACTERISTICS Isolated power grid within Korean peninsular. High growth rates of power consumption. - Annual increase rates; · ‘91-’95: 10.9%, ‘96-’00: 7.4%, ‘01-’05: 6.6%, ‘06-’10: 5.6% Highly dependent on foreign energy resources; - 96.4% of primary energy imported (232 million toe, ‘08) * Primary energy resources; - Oil: 43.1%, Coal: 27.6%, LNG: 15.3%, Nuclear: 14.0% KEY STATISTICS (2010) People served (million) 50 Generating capacity (MW) 76,078 Peak loads (MW) 71,308 Total transmission lines (C-Km) 30,676 Electricity traded annually (GWh) 406,000 Generators (above 20MW) 372 ea Jeju T/P Yangju Seo-Incheon Youngheung T/P Hanrim CC Namjeju Seogwipo Anduk Sin-Jeju Hanla Sungsan Jocheon Dong-Jeju Sanji Seo-Incheon C/C Incheon T/P, C/C Sin-Incheon Sin-Sihung Sin-Bupyung Sin-Dukheun Chungbu Youngdeungpo Youngseo Seo-seoul Uijeongbu Sungdong Hwasung Sin-suwon Pyungtaek T/P, C/C Ansan Sin-Dangjin Dangjin T/P Taean T/P Sin-onyang Boryeong T/P, C/C Chungyang Gunsan Sin-Gimje Youngwang N/P Sin-Gwangju Sin-Hwasun Sin-Gangjin Haenam C/S Yeosu N/P Gwangyang Hadong T/P Sin-Namwon Euiryong Sancheong P/P Muju P/P Sin-Okcheon Sinkaedong Chungwon Sin-Jincheon Sin-Gosung Samcheonpo T/P In-Masan Sin-Gimhae Bukbusan Pusan C/C Nam-Pusan Kori N/P Sin-Onsan Ulsan TP, C/C Wolseong N/P Seo-Daegu Buk-Daegu Sunsan Goryeong Daegu Sin-Kyeongsan Ulju Sin-Ulsan Sin-Youngju Sin-Youngil Cheongsong P/P Uljin N/P Donghae Yangyang P/P Sin-Jecheon Sin-Gapyung Sin-Ansung Sin-seosan Sin-Yangje Sin-Ansan Sin-Taebaek Sin-Yangsan Sin-Youngin Sin-Sungnam Dong-Seoul Migum Gonjiam
    5. 5. Bundang Seoul Sanchung Hapchun Cheongsong Incheon Pucheon Pyungtaek Anyang Youngkwang Chungju Chuam Yeosu Honam Kwangyang Sumjinkang Yongdam Muju Seocheon Boryeong POSCO Sin-Incheon Paldnag Chungpyung Euiam Chuncheon Hwachun Hadong Samrangjin Samcheonpo Busan Kori Andong Yangyang Kangreung Uljin Imha Youngnam Wolseong Small Hydro (Pocheon etc) Soyangkang Ilsan Youngheung Taean LGBugok Ulsan Daechung Dangjin Seo-Incheon Youngdong Donghae Yulchon Jeju (Unit : 10 MW) 53 180 99 120 180 50 48 45 90 50 45 180 180 180 90 40 33 74 50 40 400 300 180 300 400 40 247 140 39 400 115 53 590 278 314 590 6 60 100 11 12 8 7 20 2 3 2 9 5 9 60 41 40 60 10 70 6 5 Chungpyung * As of Dec 31, 2010 Capacity by Fuels (Unit : MW) Nuclear 17,716(23.3%) Oil 5,805(7.6%) Hydro 5,524(7.3%) Renewable 1,762(2.3%) Coal 24,800 (32.6%) LNG 20,471 (26.9%)
    6. 6. <ul><li>Second HVDC Line between main land and Jeju island is being built by 2012 ( 300MW ⇒ 700MW) </li></ul>Characteristics Direct Current Line - Connect the main land to Jeju Island 345kV Main transmission system Distribution system - Connected to major areas of consumption 154kV 765kV Mass transmission system ( Unit: C-km/ Numbers of S/S ) 154kV : 20,700 / 628 345kV : 8,552 / 88 765kV : 755 / 6 Jeju T/P Yangju Seo-Incheon Youngheung T/P Hanrim CC Namjeju Seogwipo Anduk Sin-Jeju Hanla Sungsan Jocheon Dong-Jeju Sanji Seo-Incheon C/C Incheon T/P, C/C Sin-Incheon Sin-Sihung Sin-Bupyung Sin-Dukheun Chungbu Youngdeungpo Youngseo Seo-seoul Uijeongbu Sungdong Hwasung Sin-suwon Pyungtaek T/P, C/C Ansan Sin-Dangjin Dangjin T/P Taean T/P Sin-onyang Boryeong T/P, C/C Chungyang Gunsan Sin-Gimje Youngwang N/P Sin-Gwangju Sin-Hwasun Sin-Gangjin Haenam C/S Yeosu N/P Gwangyang Hadong T/P Sin-Namwon Euiryong Sancheong P/P Muju P/P Sin-Okcheon Sinkaedong Chungwon Sin-Jincheon Sin-Gosung Samcheonpo T/P In-Masan Sin-Gimhae Bukbusan Pusan C/C Nam-Pusan Kori N/P Sin-Onsan Ulsan TP, C/C Wolseong N/P Seo-Daegu Buk-Daegu Sunsan Goryeong Daegu Sin-Kyeongsan Ulju Sin-Ulsan Sin-Youngju Sin-Youngil Cheongsong P/P Uljin N/P Donghae Yangyang P/P Sin-Jecheon Sin-Gapyung Sin-Ansung Sin-seosan Sin-Yangje Sin-Ansan Sin-Taebaek Gwangyang Steel Sin-Yangsan Sin-Youngin Sin-Sungnam Dong-Seoul Migum Gonjiam Hadong T/P Samcheonpo T/P Pusan C/C Gwangyang Steel
    7. 7. <ul><li>A peak demand of 71GW occurred on Dec 15, 2010 </li></ul><ul><ul><ul><li>6.8% increase compared to the last year‘s peak. </li></ul></ul></ul><ul><ul><ul><li>Higher than expected due to the extended cold waves. </li></ul></ul></ul><ul><li>The capacity margin was just around 6.2% (the lowest since 2001) </li></ul><ul><ul><ul><li>Has gradually decreased due to the delayed construction in facilities. </li></ul></ul></ul><ul><ul><ul><li>May improve from 2012 with the generator additions. </li></ul></ul></ul>45,000 50,000 70,000 (Unit:MW) 65,000 60,000 55,000 ’ 04 ’ 05 ’ 06 ’ 07 ’ 08 ’ 10 62,790 (0.8%) 62,290 (5.6%) 54,630 (6.6%) 51,260 (8.2%) 58,990 (8.0%) Reserve margin * As of Dec , 2010 71,308 (6.8%) Peak demand (Growth rate) 12.2% 11.3% 10.5% 7.2% 9.1% 6.2% 66,800 (6.4%) 7.9% ’ 09
    8. 8. Electricity Market <ul><li>Key Features </li></ul><ul><li>Market Operations </li></ul><ul><li>Procedures </li></ul><ul><li>Biddings </li></ul><ul><li>Load Forecasting </li></ul><ul><li>Generation Scheduling </li></ul><ul><li>Metering </li></ul><ul><li>- Settlement </li></ul>II
    9. 9. <ul><li>Mandatory Pool </li></ul><ul><ul><li>All generators(≥ 1 MW) and retailers should trade(buy and sell) electric power through the market ; All market participants should register as the KPX member. </li></ul></ul><ul><ul><li>The market players are GENCOs(sellers) and KEPCO(the single buyer). </li></ul></ul><ul><li>Generator Bidding Pool </li></ul><ul><ul><li>Only the supply(generation) side bid into the pool with their generator availabilities for each trading day. </li></ul></ul><ul><ul><li>The buyer does not bid and the purchaser, KEPCO, acts as a price taker in the market. KPX forecasts the hourly electricity demand for the trading day. </li></ul></ul><ul><ul><li>The market clearing is processed hourly base, prices and volumes are fixed day-ahead for 24 hours of the following day. </li></ul></ul>
    10. 10. <ul><li>Cost Based Pool (CBP) </li></ul><ul><ul><li>The cost (not the price) of each generator is bid into the pool. </li></ul></ul><ul><ul><ul><ul><li>The generation cost is determined monthly by the Generation Cost Evaluation Committee(GCEC) based on the fuel prices in the previous month. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>As mentioned before the generators bid only their availability. </li></ul></ul></ul></ul><ul><ul><li>The System Marginal Price( SMP) is determined in the process of Price Setting Scheduling. </li></ul></ul><ul><ul><ul><ul><li>SMP reflects actual production costs of generators(start-up, no-load, incremental cost). </li></ul></ul></ul></ul><ul><ul><li>The Capacity Payment(CP) is paid by for the availability declared(MW). </li></ul></ul><ul><ul><ul><ul><li>CP is paid to all generators(the Centrally Dispatching Units( ≥ 20 MW)) who submit offer data, whether or not dispatched. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>CP is determined at every year, and it is adjusted considering the level of reserve margin which can be the signal of investments. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>※ CON/COFF Payment are payed for the differences between the scheduled and the actual generations . </li></ul></ul></ul></ul>
    11. 11. <ul><li>M arginal Loss Factor(MLF) for the transmission loss introduced( ’07). </li></ul><ul><li>- To minimize the long-term social cost by the incentives to generation investment in heavy load center (Generation+Transmission). </li></ul><ul><li>- To operate optimally the resources in the short-term by considering the locational value of generations. The transmission losses are considered. </li></ul><ul><li>- MLFs are applied to generator nodes. Application to the load nodes is not necessary because the KEPCO is the single buyer. </li></ul><ul><li>- As the stranded costs were incurred, a relaxation factor was introduced to prevent the abrupt change of generator revenues(10% increase in each year). </li></ul><ul><li>★ Definition of MLF </li></ul>Change of generation at the reference bus MLF = ------------------------------------------------------- Change of load at a specific bus = 1 + △Loss / △Load increment where, △Loss ; change of total loss in the network △ Load increment ; incremental load at a certain bus
    12. 12. <ul><li>Types of of Ancillary Services </li></ul><ul><li>1) Frequency Control ; GF/AGC </li></ul><ul><li>2) Generation Reserves ; Operational reserves provided by fast start generators. </li></ul><ul><li>3) Black Starts ; 1 or 2 Self start-up generators per region. </li></ul><ul><li>4) Voltage Regulation Service ; Obligation of reactive power supply. </li></ul><ul><li>Ancillary Services Payments </li></ul><ul><ul><ul><ul><li>Compensation for ancillary services is paid according to their contributions, i.e. GF/AGC service performances are assessd by the performance index. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>Co-optimization between energy and ancillary is possible. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>The economic dispatch principle (merit order) is fully met, i.e. the roles of each types of the generator is fulfilled according to their functions. </li></ul></ul></ul></ul><ul><ul><li>i.e. the Base load(Coal) : Max. energy output. </li></ul></ul><ul><ul><li>the Peaker(LNG): Effective load following by providing AGC service . </li></ul></ul>
    13. 13. <ul><li>The reference capacity payment(RCP) is adjusted according to the forecasted capacity margin by regions (metropolitan/other/Jeju island) when it is beyond a reasonable value, i.e.12 %. </li></ul><ul><li>The seasonal/hourly coefficients are applied to RCP to ensure the sufficient generation capacity in peak times. </li></ul><ul><li>All the offered capabilities of the centrally dispatched generators(over 20 MW) are compensated by hourly based RCP regardless of their actual operations. </li></ul>
    14. 14.
    15. 15.
    16. 16. <ul><li>Daily Bidding </li></ul><ul><ul><li>Contents </li></ul></ul><ul><ul><ul><ul><li>Hourly availability. </li></ul></ul></ul></ul><ul><ul><ul><ul><li>Technical characteristics. </li></ul></ul></ul></ul><ul><ul><li>Bidding time </li></ul></ul><ul><ul><ul><ul><li>Closing time : AM 10:00, trading-day ahead(D-1) </li></ul></ul></ul></ul><ul><ul><ul><ul><li>Term : 34 hours (19:00 D-1 ~ 04:00 D+1) </li></ul></ul></ul></ul><ul><ul><ul><ul><li>※ Default Data is used if generators don’t submit their data due to communication failures or human error s. </li></ul></ul></ul></ul><ul><li>Re-Offers </li></ul><ul><ul><li>Starting Time: 10:01 AM before the trading day. </li></ul></ul><ul><ul><li>Closure Time: l (one) hour before the trading hour. </li></ul></ul><ul><ul><li>※ “ Re-offer” is allowed only when the generator has faults and it cannot meet the declared availability. </li></ul></ul>
    17. 17. Real-time Dispatch (D-0) A Day-ahead M arket ( D-1 ) Daily bid& offer made by standing bid procedure 5 a.m 10a.m Daily bid Submission Gate Closure 16p.m Pumping bid Gate Closure 15p.m SMP Disclosure Trading hour 20p.m 18p.m System Operation Schedule Disclosure 19p.m Bid change Closure 1 hour before trading hour, faults, outages
    18. 18. <ul><li>Generation Cost [Won/kWh] = Heat rate [kcal/kWh]  Fuel cost [Won/kcal] </li></ul><ul><li>- Gencos submit monthly the fuel cost data to the Committee. </li></ul><ul><li>- Fuel consumption rates are measured at 25%, 50%, 75%, 100% of the gen. output level during the performance test. </li></ul><ul><li>Cost curve ; Determine the efficiency coefficients(a,b,c) </li></ul>Cost(C i ) = {(aP 2 + bP + c )} x Fuel Cost $/hour Gcal/hour $/Gcal P(MW) C i ($/hour) No-load - Cost
    19. 19. <ul><li>Forecasting tool </li></ul><ul><ul><li>Load forecasting system (LOFY * ) </li></ul></ul><ul><li>Application </li></ul><ul><ul><li>For the fairness and transparency of the market pricing, the output of LOFY is used without any adjustments or modifications. </li></ul></ul><ul><ul><li>However, for the operational generation schedule, specific knowledge /experiences/judgement of the engineer who is in charge, is added. </li></ul></ul><ul><li>Using database </li></ul><ul><ul><li>Weather forecasting data (Korea Meteorological Administration) </li></ul></ul><ul><ul><li>Historical load data (using similar day pattern data) </li></ul></ul><ul><ul><li>※ LOFY was developed by the KEPRI(Korea Electric Power Research Institute) and updated their historical data base every year. </li></ul></ul>
    20. 20. Generation Scheduling Program <ul><li>Delivered by : ALSTOM-ESCA (now ALSTOM-Grid), 1999 </li></ul><ul><ul><li>in 2010, changed into New RSC with MIP(Mixed Integer Program) solution </li></ul></ul><ul><li>Major Functions </li></ul><ul><li>• Market-based scheduling and day-ahead dispatch scheduling. </li></ul><ul><li>• The price setting is made by the unconstrained schedule and the generator dispatch planning by the constrained schedule. </li></ul><ul><li>RSC( Resource Scheduling and Commitment) determines the generator start/stop operations and also the generation outputs which can minimize the total generation cost while balancing supply and demand. </li></ul>
    21. 21. <ul><li>Price Setting Scheduling </li></ul><ul><ul><li>The cost data, bidding data and forecasted load data are input for generation scheduling. </li></ul></ul><ul><ul><li>Least cost generation scheduling reflects only the technical characteristics of generators. </li></ul></ul><ul><ul><li>When the scheduling is finished, the hourly SMP’s are published at 3:00 PM. </li></ul></ul><ul><li>System Operational Scheduling </li></ul><ul><ul><li>The forecasted load data can be adjusted for the system operational scheduling. </li></ul></ul><ul><ul><li>All the system constraints, such as the reserve margin, transmission limits, fuel restrictions, co-generation for district heat supply, are reflected in the scheduling. </li></ul></ul><ul><ul><li>The scheduling result(starts/stops, dispatch targets) are notified to Gencos before 6:00 PM to prepare their operations. </li></ul></ul>
    22. 22. Price Setting Schedule System Operational Schedule Features To produce the hourly SMP in the market. To produce the actual operational schedule in consideration of various constraints of the power system. Input Data <ul><li>Hourly forecasted load (34 hrs) </li></ul><ul><li>Generation cost curve </li></ul><ul><li>Generator availability </li></ul><ul><li>Technical characteristics of the </li></ul><ul><li>generating units </li></ul><ul><li>Hourly forecasted load (24 hrs) </li></ul><ul><li>Generation cost curve </li></ul><ul><li>Generator availability </li></ul><ul><li>Technical characteristics of the </li></ul><ul><li>generating units </li></ul><ul><li>Transmission constraints </li></ul><ul><li>Reserve constraints </li></ul><ul><li>Heat supply and fuel constraints </li></ul><ul><li>Hydro and pump storage constraints </li></ul>Objective Function Total Generation Cost Minimization Disclosure Time <ul><li>Published at 15:00 (D – 1) </li></ul><ul><li>Published at 18:00 (D – 1) </li></ul>
    23. 23. Gen 1 (3.0W) Gen 2 (3.1W) Gen 3 (3.2W) Gen 4 (3.3W) Gen 5 (3.4W) Gen 6 (40W) Gen 7 (41W) Gen 8 (42W) Gen 9 (43W) Gen 11 (80W) Gen 12 (81W) Gen 13 (82W) Gen 14 (150W) Gen 15 (200W) <Total Cap> biding Gen 10 (44W) Gen 1 (3.0 원 ) Gen 2 (3.1 원 ) Gen 3 (3.2 원 ) Gen 4 (3.3 원 ) Gen 5 (3.4 원 ) Gen 6 (40 원 ) Gen 7 (41 원 ) Gen 8 (42 원 ) Gen 9 (43 원 ) Gen 11 (80 원 ) Gen 12 (81 원 ) Gen 13 (82 원 ) Gen 15 (200 원 ) Gen 1 (3.0 원 ) Gen 2 (3.1 원 ) Gen 3 (3.2 원 ) Gen 4 (3.3 원 ) Gen 5 (3.4 원 ) Gen 6 (40 원 ) Gen 7 (41 원 ) Gen 8 (42 원 ) Gen 9 (43 원 ) Gen 11 (80 원 ) Gen 12 (81 원 ) Gen 13 (82 원 ) Gen 15 (200 원 ) Gen 1 (3.0 원 ) Gen 2 (3.1 원 ) Gen 3 (3.2 원 ) Gen 4 (3.3 원 ) Gen 5 (3.4 원 ) Gen 6 (40 원 ) Gen 7 (41 원 ) Gen 8 (42 원 ) Gen 9 (43 원 ) Gen 11 (80 원 ) Gen 12 (81 원 ) Gen 13 (82 원 ) Gen 15 (200 원 ) 4h 15h SMP (Won/kWh) hour Forecasted Load ………… <Biding Cap> Pricing Nuclear Coal LNG Etc New addition(G/T) CP based on Marginal plan t SMP Based on Marginal cost Forecasted Load
    24. 24. ※ How do we set the market price (SMP) ?(2) (Time) (Unit : Won/kWh ) ( Unit:10MW ) Low High 01:00 04:00 09:00 12:00 15:00 19:00 21:00 24:00 Power demand(10MW) 3,730 3,320 4,770 5,500 5,690 5,420 5,420 4,740 Market price(won/kWh) 70.41 32.67 131.89 142.21 142.21 138.4 142.21 118.65 Power demand Market price Available supply capacity
    25. 25. <ul><li>■ All kinds of constraints should be considered in the real time </li></ul><ul><ul><li>All the data should be updated, based on the initial operational schedule, such as the load forecasts, generator availability changes(Re-Offers), heat supply and fuel constraints, and hydro and pump storage operations, etc. </li></ul></ul><ul><ul><li>SCADA data is very important at this stages for the system stability analysis. </li></ul></ul><ul><ul><li>Schedule energy (generation and dispatch-able load), regulation and operating reserves every 5 minutes to : - </li></ul></ul><ul><li>○ minimize cost </li></ul><ul><li>○ balance load </li></ul><ul><li>○ meet regulation and reserve requirements </li></ul><ul><li>○ satisfy transmission constraints </li></ul><ul><li>○ satisfy generator/load constraints. </li></ul>
    26. 26. <ul><li>Optimal dispatch by inter-connection MOS with EMS </li></ul><ul><ul><li>5-min optimal constrained dispatch using MOS(ABB). </li></ul></ul><ul><ul><li>Ancillary serve requirements is met by the MOS-EMS coupling. </li></ul></ul><ul><ul><li>AGC base points are given by MOS and economic participation factors as well. </li></ul></ul><ul><ul><li>Coupled operation between the AGC operation scheme of the existing EMS and the MOS economic dispatch algorithms. </li></ul></ul><ul><li>* Requirements of MOS-EMS Coupling </li></ul><ul><ul><li>① Transform the CBP cost data into the MOS bidding data(10 prices and outputs); </li></ul></ul><ul><ul><li>-> The bidding data transformation server does this. </li></ul></ul><ul><ul><li>② Accuracies of the Load Forecast/State Estimation are possible by the reliable </li></ul></ul><ul><ul><li>SCADA /RTU performance and the network modeling techniques. </li></ul></ul><ul><ul><li>③ The on-line monitoring of MOS operation is required. </li></ul></ul>
    27. 27.
    28. 28.
    29. 29. Day-ahead Market · Price(SMP) · Schedule Load Forecast Cost Based Bid Curve Capacity Bid Real Time System Operation A / S Bid Generation Capacity Prices A/S Prices Energy · Scheduled · Metered Capacity A / S Settlements + -
    30. 30. <ul><li>IPPs : SMP is paid for trading volumes </li></ul><ul><ul><li>Giving incentives for independent power producers and inducing the invests for the base load generations. </li></ul></ul><ul><li>KEPCO Subsidiary Gencos ; *RRC is applied instead of the full SMP. </li></ul><ul><ul><li>Can not give all the settlement revenues due to KEPCO’ revenue shortfalls. </li></ul></ul><ul><ul><li>Financial balancing among six power generation subsidiaries. </li></ul></ul><ul><ul><li>*RRC : Regulated revenue coefficients are different according to the generator types. </li></ul></ul>Classification Variable Cost Fixed Cost (Won/kW-hour) IPPS SMP 7.46 KEPCO Subsidiary (by generator types) Variable cost+ {(SMP-VC)×RRC}
    31. 31. Recent Market Results Ⅲ Trends of Electricity Trading Market Prices & Retail Tariffs Summary of the Market Experiences
    32. 32. <ul><li>Number of participants has increased due to the growth of the renewables, especially, the solar power (104 members in ‘07 ⇒ 422 members in ‘10) </li></ul><ul><li>Despite global economic recession, trade volume is increasing steadily. </li></ul><ul><ul><li>Trade volume is 441TWh (Average increase rate for the last 4 years ≒ 5 %) </li></ul></ul><ul><ul><li>Trade payments is $28 Billion (Average increase rate for the last 4 years: 14 %) </li></ul></ul><ul><ul><li>* 6 Gencos, KEPCO’s subsidiaries, take 91.7% of the total trade volume in 20 10. </li></ul></ul>Trade Volumes ( Unit : T Wh ) Trade Payments (Unit : Billion Dollar) ’ 07 ’ 08 ’ 10 ’ 07 ’ 08 ’ 10 18 23 28 Number of Members (Unit : No.) ’ 07 ’ 08 ’ 10 * As of December, 2010 104 302 422 374 392 441
    33. 33. <ul><li>Market/Purchasing Prices </li></ul><ul><ul><li>Steadily rising since the establishment of the market. </li></ul></ul><ul><ul><li>The market price jumped in 2008 due to high increase of fuel prices. </li></ul></ul><ul><ul><li>Market prices were maintained at high levels, however, the average settlement prices kept at a marginally increased level thanks to the nuclear power. </li></ul></ul><ul><li>Retail prices </li></ul><ul><ul><li>Stable even with the high fuel prices. </li></ul></ul><ul><ul><li>This is because retail tariffs are regulated by the government, and KEPCO’s financial status are not good in recent years due to the high purchasing price </li></ul></ul><ul><ul><li>Cross subsidy between the tariffs according to the usages make it difficult to progress the market evolutions . </li></ul></ul>< Retail tariffs by the usages > < Market Price/Purchasing Price > ($/MWh)
    34. 34. <ul><li>Electricity market re duces the electricity production cost and maximizes the resource availability </li></ul><ul><ul><li>Economic dispatch is possible based on generation cost. </li></ul></ul><ul><ul><li>Increasing the efficiency of O&M works of the generating facility. </li></ul></ul><ul><ul><li>Improving the rate of using low-cost facility(nuclear, coal) </li></ul></ul><ul><ul><li>( Capacity factor of nuclear and coal power plants are increased after operation of CBP market as 3.39%p and 2.7%p respectively.) </li></ul></ul><ul><li>Accomplish the efficiency of investment </li></ul><ul><ul><li>The substitution effect of new generation because the maximum capacity of generators were increased and maintenance schedules were shortened. </li></ul></ul><ul><ul><li>About 1,000MW substitution effect of new base load generator were occurred after the market opening. </li></ul></ul><ul><ul><li>O/M cost were cut down owing to the competition . </li></ul></ul>
    35. 35. Market Issues Vesting Contract Ⅳ Cross Subsidy between Customers Demand Response
    36. 36. <ul><li>Vesting Contract between Gencos and KEPCO has been suggested for the existing generators which were commissioned before the market opening(Because their construction cost has been already recovered and should be paid less compared the new generations). </li></ul><ul><li>Cross subsidized tariffs between the electricity users results in inefficient use of the electricity in the beneficiaries. </li></ul><ul><ul><li>It seems that some users waste the electricity at heating because of low electricity prices compared with other form of energy. </li></ul></ul><ul><li>Demand response mechanism in the market will contribute to the optimal use of the electricity in generals. </li></ul><ul><ul><li>By using the market price(if possible, the real-time price) as the economic signal, smart grid initiatives will have a bright future in the industry. </li></ul></ul>
    37. 37. THANK YOU

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