CIRCULAR

Provisions operating the competitive power generation marketCompetitive Power Generation Market

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Pursuant to Decree No. 189/2007/ND-CP dated December 27, 2007, issued by the Government, detailing the functions, tasks, powers, and organizational structure of the Ministry of Industry and Trade;

Pursuant to the Electricity Law dated December 3, 2004;

Pursuant to Decision No. 26/2006/QD-TTg dated January 26, 2006 of the Government approving the roadmap, conditions for forming and developing levels of the electricity market in Vietnam;

The Ministry of Industry and Trade stipulates the operation of the competitive power generation market as follows:

PART I
GENERAL PROVISIONS

Article 1. Scope of Regulation

This Circular regulates the activities of the competitive power generation market and the responsibilities of entities participating in the electricity market.

Article 2. Applicability

This Circular applies to the following entities participating in the competitive power generation market:

1. The sole bulk buyer entity.

2. Power generation units.

3. System operator and electricity market operator.

4. Transmission Unit.

5. Entity managing electricity metering data.

Article 3. Explanation of Terms

In this Circular, the following terms are understood as follows:

1. Bid sheet is the bid to sell electricity capacity to the electricity market by each generating unit, submitted by the bidding entity to the system operator and electricity market operator according to the bid form prescribed in this Circular.

2. Scheduled bid sheet is the bid accepted by the system operator and electricity market operator to schedule the next day's and hour's dispatch.

3. Settlement statement is the calculation of payments for power plants on the electricity market prepared by the system operator and electricity market operator for each trading day and each settlement cycle.

4. Market intervention is the action to change the normal operation mode of the electricity market that the system operator and electricity market operator must apply to handle situations prescribed in Clause 1, Article 55 of this Circular.

5. Group bidding is the mechanism for bidding when a representative entity performs bidding for a group of cascaded hydropower plants.

6. Full load cost is the variable cost of a generating unit when operating at full load, measured in VND/kWh.

7. Trading cycle is the period for calculating electricity prices on the electricity market within one (01) hour from the first minute of each hour.

8. Settlement cycle is the period for issuing invoices for transactions on the electricity market within one (01) month, starting from the first day of each month.

9. Published capacity is the highest available capacity of a generating unit announced by bidding entities or the system operator and electricity market operator and power generation units in accordance with the market schedule timetable.

10. Dispatched capacity is the capacity of a generating unit actually dispatched by the system operator and electricity market operator during the trading cycle.

11. Next hour dispatch capacity is the expected capacity of a generating unit to be dispatched for the first hour in the next hour's dispatch schedule.

12. Next day dispatch capacity is the expected capacity of a generating unit to be dispatched for each trading cycle in the next day's dispatch schedule taking into account transmission network constraints.

13. Additional generation capacity is the difference in capacity between the dispatched capacity and the capacity scheduled in the market pricing schedule of the generating unit.

14. Settled capacity is the capacity within the hourly schedule and settled at the market capacity price.

15. Ancillary services are frequency regulation, spinning reserve, fast start reserve, cold reserve, forced generation due to system security constraints, voltage adjustment, and black start services.

16. Additional generation energy is the amount of electricity generated by a generating unit due to being dispatched corresponding to additional generation capacity.

17. Bidding entity are entities directly submitting bids in the electricity market, including power generation units or power plants registered for direct bidding, the sole bulk buyer entity when bidding on behalf of BOT power plants, and the representative entity bidding for a group of cascaded hydropower plants.

18. Sole bulk buyer entity is the sole electricity buyer in the electricity market, responsible for purchasing all electricity through the electricity market and power purchase contracts.

19. Power Generation Unit is an entity owning one or more power plants participating in the electricity market and signing power purchase contracts with the sole bulk buyer entity for these power plants.

20. Indirectly trading power generation entity is a power generation entity with power plants not directly bidding in the electricity market, including strategic multi-purpose hydropower plants and power plants with ancillary service supply contracts.

21. Directly trading power generation entity translate is a power generation entity with power plants directly bidding in the electricity market.

22. Entity managing electricity metering data is the entity providing, installing, and managing the operation of systems for collecting, processing, storing electricity metering data and communication networks serving the electricity market.

23. Transmission electricity unit is the entity licensed to operate in the transmission sector, responsible for managing and operating the national transmission grid.

24. System Operator and Market Operator is the entity commanding and controlling the process of power generation, transmission, and distribution in the national power system, managing electricity market transactions.

25. Market-based capacity price is the price for a specified unit of reactive power for each trading cycle, applied to calculate capacity payment for power generation units in the electricity market.

26. Bid floor price is the lowest price allowed for a generating unit in the next day's bid sheet.

27. Market electricity price is the price for a specified unit of electricity for each trading cycle, applied to calculate electricity payment for power generation units in the electricity market.

28. Total market electricity price is the sum of the market electricity price and the market capacity price for each trading cycle.

29. Bid ceiling price is the highest price allowed for a generating unit in the next day's bid sheet.

30. Market electricity price ceiling is the highest market electricity price determined annually.

31. Water value is the marginal expectation price calculated for the volume of water stored in hydropower reservoirs when used to replace thermal power generation in the future, converted to a unit of electricity.

32. Efficiency decay factor is the efficiency decay index of a generating unit over time.

33. Annual or monthly average load factor is the ratio between the total amount of electricity generated in a year or a month and the product of total installed capacity with the total number of hours in a year or a month.

34. Electricity market information system is a set of equipment and databases serving the management and exchange of electricity market information managed by the System Operator and Market Operator.

35. Ancillary services supply contract is a contract for supplying fast-start reserve, cold reserve, and forced generation ancillary services due to system security constraints signed between the Power Generation Unit and the System Operator and Market Operator according to the model issued by the Ministry of Industry and Trade.

36. Electricity purchase and sale contract is a document agreeing on the purchase and sale of electricity between the sole wholesale buyer and power generation units or exporters/importers of electricity.

37. Non-standard electricity purchase and sale contract is an electricity purchase and sale contract concluded between the sole wholesale buyer and power generation units trading directly according to the model issued by the Ministry of Industry and Trade.

38. Default interest rate is the interest rate calculated based on the overnight interbank lending rate of the Vietnamese dong at the time of payment.

39. Constrained dispatch schedule is the arrangement of the sequence of power generation units mobilization using the optimal cost dispatch method considering technical constraints in the power system including transmission capacity limits, ancillary services, and other constraints.

40. Unconstrained dispatch schedule is the arrangement of the sequence of power generation units mobilization using the optimal cost dispatch method without considering transmission capacity limits and transmission losses in the power system.

41. Capacity schedule is a schedule prepared by the System Operator and Market Operator after operation to determine the quantity of capacity to be settled in each trading cycle.

42. Next hour dispatch schedule is the anticipated dispatch schedule of power generation units to generate electricity and provide ancillary services for the upcoming trading cycle and the three consecutive trading cycles thereafter.

43. Next day dispatch schedule is the anticipated dispatch schedule of power generation units to generate electricity and provide ancillary services for the trading cycles of the upcoming trading day.

44. Market electricity price calculation schedule is a schedule prepared by the System Operator and Market Operator after the current trading day to determine the market electricity price for each trading cycle.

45. Electricity market simulation model is a system of software simulating power generation unit mobilization and calculating market electricity prices used by the System Operator and Market Operator in annual, monthly, and weekly operational planning.

46. Water value calculation model is a system of software optimizing hydropower thermal electricity to calculate water value used by the System Operator and Market Operator in annual, monthly, and weekly operational planning.

47. Limit water level is the lowest upstream water level of the hydropower reservoir at the end of each month in a year or at the end of each week in a month calculated and announced by the System Operator and Market Operator.

48. Year N Current operating year of the electricity market

49. is the current trading day. Trading day

50. is the day when market electricity trading activities take place, from 00:00 to 24:00 daily. BOT power plant

51. is a power plant invested under the Build-Operate-Transfer model through a contract between foreign investors and competent state authorities. Best new thermal power plant

52. is a newly commissioned thermal power plant with the lowest average generation cost calculated for the next year and the electricity purchase and sale contract price agreed upon based on the standard power plant generation price framework issued by the Ministry of Industry and Trade. The best new thermal power plant is selected annually for use in calculating the market capacity price. Multi-purpose strategic hydropower plant

53. N |||are large hydropower plants playing significant roles in economic and social development, national defense, and security, constructed and operated exclusively by the state. Cascade hydropower plant group

54. is a collection of hydropower plants where the outflow from the reservoir of the upper cascade hydropower plant constitutes the entirety or majority of the inflow to the reservoir of the lower cascade hydropower plant, and there is no regulating reservoir larger than one week between these two power plants. is a collection of hydropower plants, in which the amount of water discharged from the reservoir of the upstream cascaded hydropower plant constitutes the entirety or the majority of the water entering the reservoir of the downstream cascaded hydropower plant, and there is no regulating reservoir between these two power plants larger than one week.

55. Scheduling software for mobilization is a software system used by the entity operating the power system and electricity market to schedule the next day and hour-ahead mobilization of generating units in the electricity market.

56. System load is the total amount of electricity generated by all generating units in the power system, converted to the equivalent at the terminals of each generating unit during a trading cycle.

57. Measured output is the amount of electrical energy measured at the metering point of the power plant.

58. Hourly contract output is the portion of monthly contract output allocated to each trading cycle and paid according to the differential power purchase contract.

59. Annual contract output is the annual committed output under the differential power purchase contract.

60. Monthly contract output is the portion of annual contract output allocated to each month.

61. Planned annual output is the anticipated output of the power plant to be mobilized in the upcoming year.

62. Planned monthly output is the anticipated output of the power plant to be mobilized in each month of the year.

63. Heat rate is the amount of heat energy consumed by a generating unit or power plant to produce one unit of electrical energy when operating at full load, determined for each type of thermal power technology.

64. 3. State management in the field of forensic appraisal; Constrained generation payment is the payment made to the power generator for additional generated electricity.

65. Market participant are entities participating in trading activities or providing services on the electricity market, as stipulated in Article 2 of this Circular.

66. Electricity market is a competitive power generation market established and developed in accordance with Article 18 of the Electricity Law.

67. Power shortage is a situation where the total announced capacity of all power generators is less than the forecasted system load demand in a trading cycle.

68. Confidential information is information classified as confidential under the law or agreed upon between parties.

69. Market information is all data and information related to market activities.

70. Deadline for bidding is the time after which power generators are not allowed to change their next-day bid, except for special cases specified in this Circular. In the electricity market, the deadline for bidding is 10:00 AM on Day D-1.

71. Mobilization sequence is the result of arranging the capacity bands in the bid according to the Unconstrained Scheduling principle.

72. Excess capacity is a situation where the total capacity offered at the floor price and the announced capacity of strategic multi-purpose hydropower plants, as published by the entity operating the power system and market in a trading cycle, exceeds the forecasted system load.

73. Peak-shaving unit is a generating unit that is only mobilized during peak hours of the system load profile.

74. Shoulder unit is a generating unit that is mobilized during peak hours and regular hours of the system load profile.

75. Base-load unit is a generating unit that is mobilized during peak hours, regular hours, and off-peak hours of the system load profile.

76. Slow-start unit is a generating unit that cannot be started up and synchronized to the grid within less than 30 minutes.

Chapter II
APPLICATION FOR PARTICIPATION IN THE ELECTRICITY MARKET

Article 4. Obligation to Participate in the Electricity Market

1. Power plants with an installed capacity greater than 30 MW that have a power operation license in the electricity generation sector and are connected to the national power grid, except for those specified in Clause 2 of this Article, must participate in the competitive electricity generation market.

2. Power plants not required to participate in the electricity market include:

a) BOT power plants;

b) Wind power plants and geothermal power plants;

c) Power plants within industrial zones that only sell part of their production to the national power grid and cannot determine long-term electricity sales plans. The Vietnam Electricity Corporation is responsible for compiling a list of these power plants and submitting it for approval by the Electricity Regulatory Authority.

3. Power plants specified in Clause 1 of this Article are responsible for investing in and completing systems and equipment to connect to the electricity market information system, the SCADA/EMS system, and the electricity metering system to meet the operational requirements of the electricity market.

Article 5. Documents for Registering Participation in the Electricity Market

1. Electricity generation units owning power plants as stipulated in Article 4 of this Circular are responsible for submitting registration documents for participation in the electricity market for each power plant.

2. Registration documents for participating in the electricity market shall include:

a) A registration form for participation in the electricity market, clearly stating the name and address of the electricity generation unit and the power plant;

b) A copy of the power operation license in the electricity generation sector;

c) Documentation certifying the acceptance of the systems and equipment for connection to the electricity market information system, the SCADA/EMS system, and the electricity metering system;

d) Other necessary information as required by the System Operator and the Electricity Market.

Article 6. Procedure for Approving Registration Documents for Participation in the Electricity Market

1. Within ten (10) working days from the date of receipt of valid documents, the System Operator and the Electricity Market are responsible for reviewing and submitting to the Electricity Regulatory Authority for permission for the power plant to participate in the electricity market.

2. In case the documents are not valid, within five (05) working days from the date of receipt of the documents, the System Operator and the Electricity Market must issue a written request for the electricity generation unit to supplement and complete the documents.

3. Within five (05) working days from the date of receipt of the submission from the System Operator and the Electricity Market, the Electricity Regulatory Authority is responsible for issuing a decision allowing the power plant to participate in the electricity market and notifying the System Operator and the Electricity Market in writing to include the power plant in the list of participants in the electricity market.

4. Within five (05) working days from the date the power plant is permitted to participate in the electricity market, the electricity generation unit is responsible for registering with the System Operator and the Electricity Market regarding the bidding entity on the electricity market (the electricity generation unit or the power plant).

Article 7. Information of Participants in the Electricity Market

1. Transmission companies, sole bulk purchasers, and electricity meter data management units are responsible for registering general information about their units with the System Operator and the Electricity Market.

2. The System Operator and the Electricity Market are responsible for storing registration information and updating changes to the registration information of market participants.

3. Participants in the electricity market are responsible for notifying the System Operator and the Electricity Market of any changes to the registered information.

4. The System Operator and the Electricity Market are responsible for publishing the registration information of market participants and any updated registration information.

Article 8. Suspension and Restoration of Participation Rights in the Electricity Market for Power Plants

1. The participation rights in the electricity market of power plants shall be suspended in the following cases:

a) Failure to fully comply with the provisions set forth in Article 4 of this Circular;

b) Committing the following acts:

- Failing to provide information or providing inaccurate information for the planning of electricity market operations and scheduling of generating units in the power system;

- Agreeing with the System Operator and Electricity Market Operator or other power generation entities on bidding prices to be included in the scheduling plan contrary to regulations;

- Directly or indirectly agreeing with other entities on the publication of capacity and bidding prices in the electricity market to increase electricity prices and affect power supply security;

- Other violations causing serious consequences to the power system's security or financial losses to other entities in the electricity market.

2. The Electricity Regulatory Authority has the authority to suspend the participation rights in the electricity market of power plants that violate the provisions stipulated in Clause 1 of this Article. The procedures and formalities for suspending the participation rights in the electricity market of power plants are specified in Article 108 of this Circular.

3. During the period when the power plant's participation rights in the electricity market are suspended:

a) The power generation entity or power plant may not bid directly in the electricity market but must comply with other provisions of this Circular;

b) The sole bulk purchaser is responsible for bidding on behalf of the power plant;

c) The power plant is responsible for providing information to the sole bulk purchaser for bidding on its behalf.

4. A suspended power plant will have its participation rights in the electricity market restored upon meeting the following conditions:

a) When the suspension period for participation in the electricity market expires;

b) Completion of all obligations prescribed in the penalty decision.

5. Upon meeting all conditions stipulated in Clause 4 of this Article, the power plant is responsible for submitting a written request for restoration of participation rights in the electricity market along with supporting documents to the System Operator and Electricity Market Operator. The System Operator and Electricity Market Operator are responsible for reviewing and allowing the power plant to participate in the electricity market.

6. In the event that the suspension period for participation in the electricity market ends but the power plant has not met the conditions stipulated in point b of Clause 4 of this Article, the System Operator and Electricity Market Operator are responsible for reporting to the Electricity Regulatory Authority for further consideration and handling.

Article 9. Termination of Participation in the Electricity Market

1. The participation of power plants in the electricity market shall terminate in the following cases:

a) At the request of the power generation entity in the following circumstances:

- The power plant of the power generation entity ceases operation or stops supplying electricity to the national power grid;

- The power plant of the power generation entity fails to maintain and cannot restore its installed capacity exceeding 30 MW.

b) The license for power activities in the power generation sector of the power plant is revoked or expires.

2. In the case stipulated in point a of Clause 1 of this Article, the power generation entity is responsible for submitting a request to terminate participation in the electricity market to the Electricity Regulatory Authority at least thirty (30) days prior to the intended date of termination.

3. The System Operator and Electricity Market Operator are responsible for updating the stored registration files and announcing information about the termination of participation in the electricity market by the power plant.

4. In the case where the power plant commits violations before the termination of its participation in the electricity market, the power generation entity owning the power plant is responsible for continuing to implement the provisions regarding inspection, verification, and handling of violations as prescribed in this Circular.

Chapter III
PRINCIPLES FOR OPERATING THE ELECTRICITY MARKET

Article 10. Limitation on Bid Prices

1. The bid price for power generation units participating in the competitive power generation market shall be limited from the floor price to the ceiling price of the bid.

2. The ceiling price of thermal power generation units shall be determined annually, adjusted monthly, and calculated based on the following factors:

a) Heat rate of the power generation unit;

b) Efficiency degradation factor according to the operation time of the power generation unit;

c) Fuel price;

d) Start-up costs.

3. The floor price for thermal power generation units is VND 1/kWh.

4. The bid price limit for hydropower units shall be determined based on the water value on a weekly basis and specified in Article 37 of this Circular.

Article 11. Water Value

1. The water value is used for planning the operation of the next year, month, and week, and for determining the bid price limit for hydropower units in the electricity market.

2. The system operator and the electricity market operator are responsible for calculating and announcing the water value according to the schedule specified in Appendix 1 of this Circular.

Article 12. Full Market Price

The full market price for each trading cycle is calculated as the sum of two (02) components:

1. Electricity energy market price.

2. Capacity market price.

Article 13. Electricity Energy Market Price

1. The electricity energy market price is a common price for the entire system, used to calculate the electricity energy payment on the electricity market for each trading cycle.

2. The electricity energy market price is calculated by the system operator and the electricity market operator after the operation period based on the non-binding scheduling method.

3. The electricity energy market price shall not exceed the ceiling market price calculated by the system operator and the electricity market operator and approved annually by the Electricity Regulatory Authority.

4. The determination of the electricity energy market price is regulated in Articles 63 and 65 of this Circular.

Article 14. Capacity Market Price

1. The capacity market price for each trading cycle is calculated by the system operator and the electricity market operator during the annual operation planning process and remains unchanged throughout the application year.

2. The capacity market price is calculated based on the principle of ensuring that the best new power plant recovers both variable and fixed costs.

3. The determination of the capacity market price is regulated in Articles 25 and 26 of this Circular.

Article 15. Differential Power Purchase and Sale Contracts

1. The power generation unit conducting direct transactions and the sole bulk buyer are responsible for signing differential power purchase and sale contracts according to the model issued by the Ministry of Industry and Trade.

2. The annual contract volume is calculated by the system operator and the electricity market operator based on the planned annual production volume and the ratio of production volume paid at the contract price as stipulated in Clause 5 of this Article. The planned annual production volume is calculated by the system operator and the electricity market operator during the annual operation planning process according to Article 27 of this Circular.

3. The monthly contract volume is determined by the system operator and the electricity market operator during the annual operation planning process based on the allocation of the annual contract volume to months as specified in Article 28 of this Circular.

4. The hourly contract volume is determined by the system operator and the electricity market operator during the monthly operation planning process based on the allocation of the monthly contract volume to hours within the month as specified in Article 35 of this Circular.

5. The Electricity Regulatory Authority is responsible for determining and announcing the ratio of production volume paid at the contract price for power generation units annually according to the following principles:

a) Ensuring harmony among the following objectives:

- Gradually reducing the proportion of electricity energy paid at the contract price;

- Stabilizing the revenue of power generation units;

- Stabilizing the average power generation price, consistent with regulations on retail electricity pricing.

b) The proportion of electricity energy paid at the contract price in the first year of market operation shall not exceed 95%, and it will gradually decrease in subsequent years but not fall below 60%.

Article 16. Principles of Payment in the Electricity Market

1. Power generation units shall be paid according to contracts and market electricity prices.

2. Power generation units shall be paid according to the following types of contracts:

a) Spot price difference contracts for power generation units directly trading;

b) Power purchase and sale contracts for strategic multi-purpose hydropower plants;

c) Ancillary service contracts for power generation units providing ancillary services.

3. Payments based on market prices shall only apply to power generation units directly trading and shall be calculated based on the following factors:

a) Market electricity price;

b) Market capacity price;

c) Generated electricity volume and mobilized capacity.

4. The payment process shall be carried out in accordance with the provisions of Chapter VI of this Circular.

Chapter IV
MARKET OPERATING PLAN

Section 1
NEXT YEAR'S OPERATING PLAN

Article 17. Next Year's Operating Plan

1. The system operator and electricity market operator shall be responsible for preparing next year's operating plan, including the following contents:

a) Selecting the best new power plant;

b) Calculating the market capacity price;

c) Calculating the value of water and water level limits of hydropower reservoirs;

d) Calculating the bidding price limit of thermal power units;

đ) Determining the market ceiling price;

e) Taking the lead and coordinating with the sole bulk buyer to calculate planned production volume, annual contract volume, and allocate annual contract volume among months for power generation units directly trading.

2. The system operator and electricity market operator shall be responsible for using the market simulation model to calculate the contents specified in Clause 1 of this Article. The bidding price used in the market simulation of thermal power units shall be the ceiling bidding price determined in Clause 1 of Article 22 of this Circular, and for hydropower units, it shall be the calculated water value for the upcoming year.

3. The system operator and electricity market operator shall be responsible for submitting the next year's operating plan to Vietnam Electricity Corporation for review and to the Electricity Regulatory Authority for approval according to the market timetable stipulated in Appendix 1 of this Circular. The submission documents shall include calculation results, input data, and calculation explanations.

Article 18. Classification of Hydropower Plants

1. Hydropower plants in the electricity market shall be specifically classified as follows:

a) Strategic multi-purpose hydropower plants;

b) Cascade hydropower plant group;

c) Other hydropower plants.

2. Annually, the system operator and electricity market operator shall be responsible for updating the list of cascade hydropower plant groups.

3. The Electricity Regulatory Authority shall be responsible for compiling the list of strategic multi-purpose hydropower plants for the Ministry of Industry and Trade to submit to the Prime Minister for approval.

Article 19. Load Forecast for Preparing Next Year's Operating Plan

The system operator and electricity market operator shall be responsible for forecasting loads to serve the preparation of next year's operating plan according to the method prescribed in the Transmission System Regulation issued by the Ministry of Industry and Trade. The load forecast data for preparing next year's operating plan shall include:

1. Total system load demand and regional load demand in the North, Central, and South regions for the entire year and each month within the year.

2. Typical daily load profiles for the North, Central, and South regions and the entire system for each month within the year.

3. Maximum and minimum system load capacities in each month.

Article 20. Ancillary Services for the Next Year's Operation Plan

1. The system operator and electricity market entity shall be responsible for determining the requirements for various types of ancillary services for the next year in accordance with the provisions of the Transmission System Regulation issued by the Ministry of Industry and Trade.

2. The system operator and electricity market entity shall be responsible for selecting power plants to provide ancillary services and signing service provision contracts with power generation units according to the model form issued by the Ministry of Industry and Trade.

Article 21. Classification of Base Load, Mid-Load, and Peak Load Units for the Next Year

1. The system operator and electricity market entity shall be responsible for classifying base load, mid-load, and peak load units in accordance with the provisions of the Procedure for Classifying Power Plants and Determining the Maximum Price of Bids for Thermal Power Plants.

2. The system operator and electricity market entity shall be responsible for using a market simulation model to determine the annual average load factor of power generation units.

3. Based on the annual average load factor from the simulation results, the units will be classified into three (03) groups as follows:

a) Base load unit group includes power generation units with an annual average load factor greater than or equal to sixty percent (60%);

b) Mid-load unit group includes power generation units with an annual average load factor greater than twenty-five percent (25%) and less than sixty percent (60%);

c) Peak load unit group includes power generation units with an annual average load factor less than or equal to twenty-five percent (25%).

Article 22. Determination of Bid Price Limits for Thermal Power Units

1. Determination of the Ceiling Bid Price for Thermal Power Units

a) The ceiling bid price for thermal power units is determined according to the following formula:

Where:

: ceiling bid price of the thermal power unit (VND/kWh);

ảo_KD: startup cost coefficient of the thermal power unit. For base load thermal power units K_KD = 0; for mid-load thermal power units K_KD = 5%; for peak load thermal power units K_KD = 25%;

f: auxiliary cost coefficient, calculated as the ratio of total auxiliary fuel costs and variable operating and maintenance costs to the main fuel cost;

"5. The pre-tax weighted average cost of capital i (%) is determined according to the formula below:_GT: main fuel cost of the thermal power unit (VND/BTU);

: heat rate of the thermal power unit (BTU/kWh).

b) The fuel price used to calculate the ceiling bid price is the anticipated fuel price for year N provided by the sole bulk buyer to the system operator and electricity market entity. The fuel price is calculated and converted to the power plant gate.

c) The heat rate of the power unit is determined based on the agreed heat rate in the contract or in the power purchase agreement negotiation documents provided by the sole bulk buyer and adjusted according to the efficiency degradation factor.

In case the thermal power unit does not have heat rate data in the contract or in the power purchase agreement negotiation documents, the heat rate of that power plant is determined based on the standard power plant's heat rate in the same category according to the technology and installed capacity. The system operator and electricity market entity shall be responsible for calculating the heat rate of the standard power plant.

In case there is no heat rate data in the contract or in the power purchase agreement negotiation documents and no suitable standard power plant in the same category, the system operator and electricity market entity shall calculate the heat rate based on past operational data provided by the power generation unit.

d) The efficiency degradation factor of the thermal power unit is determined based on the efficiency degradation factor in the contract or in the power purchase agreement negotiation documents provided by the sole bulk buyer.

In case the thermal power plant does not have efficiency degradation factor data in the contract or in the power purchase agreement negotiation documents, the efficiency degradation factor of the standard power plant in the same category as that power plant shall be applied, as determined by the system operator and electricity market entity.

đ) The auxiliary cost coefficient of the thermal power unit is determined by the sole bulk buyer based on the data in the power purchase agreement or negotiation documents and provided to the system operator and electricity market entity.

2. The floor price for thermal power units is stipulated in Clause 3, Article 10 of this Circular.

3. The system operator and electricity market entity shall be responsible for announcing the approved bid price limits of thermal power units according to the market schedule in Appendix 1 of this Circular.

Article 23. Price Quotation Limits for BOT Power Plants

1. The maximum price quotation of a BOT power plant is equal to the unit cost of electricity in the power purchase agreement of the BOT plant.

2. The minimum price quotation of a BOT power plant is one dong per kWh.

Article 24. Selection of the Best New Power Plant

1. The best new power plant for year N is a power plant participating in the electricity market that meets the following criteria:

a) Begins commercial operation and operates at full installed capacity throughout year N-1;

b) Is a base load power plant classified according to the criteria set forth in Clause 3 of Article 21 of this Circular;

c) Uses coal thermal power technology or combined cycle gas turbine technology;

d) Has the lowest average total generation cost per kWh.

2. The sole bulk buyer is responsible for compiling a list of power plants meeting the criteria specified in points a and c of paragraph 1 of this Article and providing the electricity purchase contract data of these power plants to the System Operator and Electricity Market to determine the best new power plant. The data includes:

a) Variable price for year N;

b) Fixed price for year N;

c) Agreed electricity output for calculating the contract price.

3. In the absence of a power plant meeting the criteria stipulated in points a, b, and c of paragraph 1 of this Article, the System Operator and Electricity Market will use the best new power plant selected for year N-1 and require the sole bulk buyer to update and provide the data specified in paragraph 2 of this Article for calculation purposes for year N.

4. The System Operator and Electricity Market are responsible for calculating the average total generation cost per kWh for power plants meeting the criteria stipulated in points a, b, and c of paragraph 1 of this Article using the following formula:

: Average total generation cost per kWh for the power plant in year N (dong/kWh);

: Fixed price for year N under the power purchase contract (dong/kWh);

: Variable price for year N under the power purchase contract (dong/kWh);

: Agreed electricity output for calculating the contract price for year N (kWh);

: Forecast electricity output for year N determined from the market simulation model using the constrained scheduling method (kWh).

5. The best new power plant selected for year N is the power plant with the lowest average total generation cost per kWh based on the calculation results in paragraph 4 of this Article.

Article 25. Principles for Determining Market Capacity Prices

1. Ensuring that the best new power plant recovers its generation costs when participating in the electricity market.

2. Not applying market capacity prices during low-demand nighttime hours, which are defined as hours from 00:00 to 04:00 and from 22:00 to 24:00.

3. Market capacity prices are proportional to the forecast system load for the trading period.

Article 26. Procedure for Determining Market Capacity Prices

The System Operator and Electricity Market are responsible for determining market capacity prices according to the following procedure:

1. Determine the annual shortfall cost of the best new power plant

a) Determine the expected revenue of the best new power plant on the market in year N using the following formula:

Where:

||| R_{+ C}: Expected revenue through market electricity prices of the best new power plant in year N (dong);

i: Trading period i in year N;

I: Total number of trading periods in year N;

SMP_{ANNEX I.A[31]}: Expected market electricity price of trading period i in year N determined from the market simulation model using the unconstrained scheduling method (dong/kWh);

: Expected output of the best new power plant at trading period i in year N determined from the market simulation model using the constrained scheduling method (kWh).

b) Determine the annual generation cost of the best new power plant using the following formula:

Where:

Economic life of the power plant as specified in the Appendix attached to this Circular (years)._BNE: Annual generation cost of the best new power plant in year N (dong);

"5. The pre-tax weighted average cost of capital i (%) is determined according to the formula below:_BNE: Average total generation cost per kWh of the best new power plant determined in paragraph 4 of Article 24 of this Circular (dong/kWh);

: Expected output of the best new power plant at trading period i in year N determined from the market simulation model using the constrained scheduling method (kWh);

i: Trading period I in year N;

I: Total number of trading periods in year N.

c) The annual shortfall cost of the best new power plant is determined using the following formula:

Where:

AS: Annual shortfall cost of the best new power plant in year N (dong);

Economic life of the power plant as specified in the Appendix attached to this Circular (years)._BNE: Annual generation cost of the best new power plant in year N determined in point b of this paragraph (dong);

: Expected revenue through market electricity prices of the best new power plant in year N determined in point a of this paragraph (dong).

2. Determine the monthly shortfall cost

The monthly shortfall cost of the best new power plant is determined by allocating the annual shortfall cost to each month in year N using the following formula:

Where:

t: Month t in year N;

MS: Monthly shortfall cost of the best new power plant in month t (dong);

AS: Annual shortfall cost of the best new power plant in year N (dong);

: Peak system load in month t (MW).

3. Determine the market capacity price for each trading period

a) Determine the average available capacity in year N of the best new power plant using the following formula:

Where:

Article 24_BNE: Average available capacity in year N of the best new power plant (kW);

I: Total number of trading periods in year N, excluding low-demand nighttime hours;

i: Trading period in which the best new power plant is expected to be dispatched, excluding low-demand nighttime hours;

: Expected dispatch capacity of the best new power plant in trading period i of year N according to the market simulation model using the constrained scheduling method (kW).

b) Determine the market capacity price for each trading period in the upcoming year using the following formula:

Where:

I: Total number of trading periods in month t, excluding low-demand nighttime hours;

i: Trading period i in month t, excluding low-demand nighttime hours;

: Market capacity price of trading period i (dong/kW);

Article 24_BNE: Average available capacity in year N of the best new power plant (kW);

MS: Monthly shortfall cost of the best new power plant in month t (dong);

: System load forecast for trading period i according to the typical daily load profile forecast for month t as prescribed in Article 19 of this Circular (MW);

: Minimum system load forecast for month t (MW).

Article 27. Determining the Annual Contract Volume

The annual contract volume of power plants is determined during the process of formulating the next year's operation plan, including the following steps:

1. Using market simulation models to determine the expected production volume of power plants according to the constrained scheduling method.

2. Calculating the planned annual production volume of power plants using the following formula:

          if

       if

       if

Where:

: the planned annual production volume N of the power plant (kWh);

: the expected annual production volume N of the power plant determined from the market simulation model using the constrained scheduling method converted to the metering point (kWh);

: the agreed annual electricity volume N of the power plant for calculating the purchase and sale contract price (kWh);

a, b: annual production adjustment factors, where a = 0.9; b = 1.1.

3. Calculating the annual contract volume of power plants using the following formula:

Where:

Article 24_c: the annual contract volume N (kWh);

: the planned annual production volume N of the power plant (kWh);

: the percentage of contract volume paid at the contract price applied for year N (%).

Article 28. Determining the Monthly Contract Volume

The monthly contract volume of power plants is determined during the process of formulating the next year's operation plan, including the following steps:

1. Using market simulation models to determine the expected monthly production volume of power plants.

2. Determining the monthly contract volume using the following formula:

Where:

 : the monthly contract volume t of the power plant (kWh);

Article 24_c : the annual contract volume of the power plant (kWh);

: the expected production volume in month t of the power plant determined from the market simulation model using the constrained scheduling method (kWh).

Article 29. Responsibility for Determining and Signing the Annual and Monthly Contract Volumes

1. The system operator and electricity market have the responsibility:

a) To calculate the annual and monthly contract volumes of power generation units as stipulated in Articles 27 and 28 of this Circular;

b) To send the results of the contract volume calculation to the sole bulk buyer and directly trading power generation units for verification;

2. The sole bulk buyer and directly trading power generation units have the responsibility:

a) To provide data to the system operator and electricity market for calculating the annual and monthly contract volumes;

b) To verify and coordinate with the system operator and electricity market to address discrepancies in the calculation results;

c) To supplement the appendix on annual and monthly contract volumes into the different types of purchase and sale contracts based on the calculation results.

Article 30. Determining the Market Price Ceiling

1. The system operator and electricity market have the responsibility to calculate various market price ceiling options, including the market price ceiling level, the average expected generation price for year N, and the degree of change in the average expected generation price compared to year N-1. The minimum number of market price ceiling options is three (03) options.

2. The market price ceiling for year N shall not exceed 115% of the highest cost thermal power plant's bid price ceiling.

3. The annual average generation price is calculated using the following formula:

Where:

j: power plant j of the directly trading power generation unit;

J: total number of power plants of the directly trading power generation units;

"5. The pre-tax weighted average cost of capital i (%) is determined according to the formula below:_PDTB: the average generation price of the entire system in year N (VND/kWh);

: the full market average price for year N as stipulated in Clause 4 of this Article (VND/kWh);

: the total electricity volume of the entire system in year N (kWh);

: the total electricity volume of the directly trading power generation units in year N (kWh);

: the total electricity volume in the different type of purchase and sale contract year N of power plant j (kWh);

: the different type of purchase and sale contract price year N of power plant j (VND/kWh);

: the total cost of purchasing electricity from BOT power plants in year N (VND);

: the total cost of purchasing electricity from strategic multi-purpose hydropower plants in year N (VND);

C_DVPT: the total cost of purchasing ancillary services in year N (VND).

4. The full market average price is determined using the following formula:

Where:

i: Trading period i in year N;

I: total trading cycles in year N;

: the full market average price for year N (VND/kWh);

: the expected production volume entering the market of all participating power plants in trading cycle i determined from the constrained transmission market simulation model (kWh);

: the expected electricity price of trading cycle i determined from the unconstrained transmission electricity market simulation model (VND/kWh);

: the market capacity price of trading cycle i (VND/kW).

Section 2
MONTHLY OPERATION PLAN FOR THE NEXT MONTH

Article 31. Load Forecasting for Next Month's Operation Plan

The system operator and electricity market entity shall be responsible for load forecasting to serve the preparation of next month's operation plan in accordance with the transmission system regulation issued by the Ministry of Industry and Trade. The load forecasting data for preparing next month's operation plan includes:

1. Total system load demand and load demand of each region (North, Central, South) for the entire month and each week within the month.

2. Load profile diagrams of typical days in each region (North, Central, South) and the entire system for each week within the month.

Article 32. Calculation of Water Value

The system operator and electricity market entity shall be responsible for calculating the water value for each week of the upcoming month. The results of the water value calculation will be used to prepare the next month's operation plan, including:

1. Expected output of strategic multi-purpose hydropower plants.

2. Water value of hydropower plants in cascaded hydropower groups.

3. Water value of other hydropower plants.

4. Weekly water level limits of hydropower reservoirs for the upcoming month.

Article 33. Classification of Base, Shoulder, and Peak Units for Next Month

1. The system operator and electricity market entity shall be responsible for classifying base, shoulder, and peak units for the upcoming month according to the unit classification process and the monthly maximum bid price calculation procedure for thermal power plants.

2. The system operator and electricity market entity shall be responsible for using a market simulation model to determine the average monthly load factor of generating units for the upcoming month.

3. Based on the average monthly load factor from the simulation results, the units are classified into three (03) groups as follows:

a) Base unit group consisting of generating units with an average monthly load factor greater than or equal to seventy percent (70%);

b) Shoulder unit group consisting of generating units with an average monthly load factor greater than twenty-five percent (25%) and less than seventy percent (70%);

c) Peak unit group consisting of generating units with an average monthly load factor less than or equal to twenty-five percent (25%).

Article 34. Adjustment of Maximum Bid Price of Thermal Power Units

1. The system operator and electricity market entity shall be responsible for calculating and adjusting the maximum bid price of thermal power units for the upcoming month according to the method prescribed in Article 22 and the unit classification results determined in Article 33 of this Circular.

2. The system operator and electricity market entity shall be responsible for announcing the maximum bid price of thermal power units for the upcoming month according to the market schedule specified in Appendix 1 of this Circular.

Article 35. Determination of Hourly Contract Output

The system operator and electricity market entity shall be responsible for determining the hourly contract output for power plants in the upcoming month according to the following steps:

1. Using a market simulation model to determine the expected hourly output of the power plant for the upcoming month.

2. Determining the hourly contract output according to the following formula:

Where:

i: the ith trading cycle in the month;

I: total number of trading cycles in the month;

: hourly contract output of the power plant in the ith trading cycle (kWh);

: expected generation output of the power plant in the ith trading cycle determined from the market simulation model using the constrained scheduling method (kWh);

: monthly contract output of the power plant determined according to Article 28 of this Circular (kWh);

3. The system operator and electricity market entity shall be responsible for sending the calculated hourly contract output results to the sole bulk purchaser and the direct power generation trading entity according to the market electricity schedule specified in Appendix 1 of this Circular.

4. The sole bulk purchaser and the direct power generation trading entity shall be responsible for confirming the hourly contract output according to the calculation results of the system operator and electricity market entity.

Section 3
WEEKLY OPERATION PLAN FOR THE UPCOMING WEEK

Article 36. Value of Water for the Upcoming Week

1. The entity operating the power system and electricity market shall be responsible for updating load forecast data, hydrological data, and other relevant data to calculate the value of water for the upcoming week.

2. The entity operating the power system and electricity market shall be responsible for updating information, recalculating the value of water for the upcoming week, and announcing the following results:

a) The value of water and the expected hourly generation capacity of multi-purpose strategic hydropower plants;

b) The value of water for groups of cascaded hydropower plants;

c) The value of water for other hydropower plants;

d) The weekly water level limit of hydropower reservoirs.

Article 37. Price Quotation Limits for Hydropower Plants

The price quotation limits for hydropower plants are determined based on the announced value of water for the upcoming week of that plant according to Clause 2 of Article 36 of this Circular, specifically as follows:

1. In the case where the value of water is greater than 0 VND/kWh:

a) The ceiling price of the hydropower plant is 110% of the value of water;

b) The floor price of the hydropower plant is 80% of the value of water.

2. In the case where the value of water is less than or equal to 0 VND/kWh, the ceiling price and floor price of the hydropower plant are 0 VND/kWh.

Chapter V
ELECTRICITY MARKET OPERATIONS

Section 1
OPERATIONS OF THE NEXT DAY'S ELECTRICITY MARKET

Article 38. Information for Next Day's Electricity Market Operations

Before 9:00 AM on day D-1, the entity operating the power system and electricity market shall be responsible for determining, calculating, and announcing the following information:

1. The load forecast chart for day D of the entire system and each region (North, Central, South).

2. The expected export and import electricity volume during each trading cycle of day D. Export and import electricity volumes are provided by the sole bulk buyer entity according to Articles 58 and 59 of this Circular.

3. Short-term system security assessment results for day D according to the Transmission System Regulation issued by the Ministry of Industry and Trade.

Article 39. Bid Sheet

The bid sheet must comply with the following principles:

1. There can be a maximum of five pairs of bid prices (VND/kWh) and capacities (MW) for each unit for each trading cycle of day D.

2. The capacity in the bid sheet is the capacity at the generator terminal.

3. The minimum bid increment is 3 MW.

4. Information about the technical specifications of the unit, including:

a) The declared capacity of the unit for day D;

b) The lowest stable generation capacity of the unit;

c) The maximum rate of increase and decrease in capacity of the unit.

5. The declared capacity of the unit in the bid sheet for day D cannot be lower than the declared capacity on day D-2 according to the short-term system security assessment procedure specified in the Transmission System Regulation, except in cases of unavoidable technical failures.

6. The first bid capacity range in the bid sheet must be equal to the lowest stable generation capacity of the unit. The last bid capacity range must be equal to the declared capacity.

7. The unit of bid price is VND/kWh, with the smallest decimal being 0.1.

8. The bid price must be within the range from the floor price to the ceiling price of the unit and cannot decrease with increasing bid capacity.

The format of the bid sheet is specified in Appendix 3 of this Circular.

Article 40. Group Bid for Cascaded Hydropower Plants

1. The group of cascaded hydropower plants shall be responsible for bidding according to a single group bid sheet and complying with the bid price limits stipulated in Article 37 of this Circular.

2. Hydropower plants within the group of cascaded hydropower plants shall be responsible for negotiating and agreeing on a representative entity to submit bids. The representative entity submitting bids for the group of cascaded hydropower plants shall be responsible for submitting registration documents along with the agreement document between hydropower plants in the group to the entity operating the power system and electricity market.

3. In the event of not registering a representative entity to submit bids for the group of cascaded hydropower plants, the entity operating the power system and electricity market shall be responsible for submitting bids on behalf of the plants in this group according to the group's value of water.

4. The representative entity submitting bids shall be responsible for complying with bidding regulations for all hydropower plants in the group of cascaded hydropower plants.

5. The value of water for the group of cascaded hydropower plants is the value of water of the largest hydropower reservoir in the cascade. The entity operating the power system and electricity market shall be responsible for determining the hydropower reservoir used to calculate the value of water for the group of cascaded hydropower plants together with classifying hydropower plants as stipulated in Article 18 of this Circular.

6. In the case where the group of cascaded hydropower plants includes a multi-purpose strategic hydropower plant:

a) The entity operating the power system and electricity market shall be responsible for announcing the expected hourly generation capacity of each hydropower plant in the group of cascaded hydropower plants according to Clause 2 of Article 36 of this Circular;

b) When the announced generation capacity of the multi-purpose strategic hydropower plant in the group is adjusted according to Article 51 of this Circular, the entity operating the power system and electricity market shall be responsible for adjusting the announced generation capacity of hydropower plants downstream in the cascade accordingly.

Article 41. Bidding for other hydroelectric power plants and BOT power plants

1. Other hydroelectric power plants with reservoirs regulating over one (01) week shall bid on the market weekly and comply with the bidding price limits specified in Article 37 of this Circular.

2. Other hydroelectric power plants with reservoirs regulating under one (01) week shall submit the hourly generation volume of day D to the System Operation Unit and the electricity market before 10:00 on day D-1 for scheduling purposes.

3. The sole bulk buyer shall be responsible for bidding on behalf of BOT power plants.

Article 42. Submission of Bid Documents

1. Before 10:00 on day D-1, the bidding entity shall be responsible for submitting the bid document for day D.

2. Bidding entities shall submit bid documents through the market information system. In case of technical failure preventing the use of the market information system, the bidding entity shall coordinate with the System Operation Unit and the electricity market regarding alternative submission methods in the following order of priority:

a) By email to the address specified by the System Operation Unit and the electricity market;

b) By fax to the number specified by the System Operation Unit and the electricity market;

c) Directly at the office of the System Operation Unit and the electricity market.

Article 43. Verification of Bid Document Validity

1. Thirty (30) minutes prior to the end of the bidding period, the System Operation Unit and the electricity market shall be responsible for verifying the validity of the bid documents received from the bidding entities according to the provisions of Article 39 of this Circular. If multiple bid documents are submitted by a bidding entity, only the last received bid document will be considered.

2. In the event that a bid document is invalid, the System Operation Unit and the electricity market shall immediately notify the entity that submitted the bid document and request that entity to resubmit the final bid document before the end of the bidding period.

3. Upon receiving notification from the System Operation Unit and the electricity market about an invalid bid document, the bidding entity shall be responsible for revising and resubmitting the bid document before the end of the bidding period.

Article 44. Scheduling Bid Document

1. After the end of the bidding period, the System Operation Unit and the electricity market shall verify the validity of the final received bid documents according to the provisions of Article 39 of this Circular. The final valid bid document shall be used as the scheduling bid document for the next day's scheduling.

2. In the event that the System Operation Unit and the electricity market do not receive a bid document or the final bid document of a bidding entity is invalid, the System Operation Unit and the electricity market shall use the default bid document of that power plant as the scheduling bid document.

3. The default bid document of power plants is determined as follows:

a) For thermal power plants, the default bid document is the most recent valid bid document or the bid document of an equivalent generating unit as determined by the System Operation Unit and the electricity market;

b) For hydroelectric power plants and cascaded hydroelectric power plants, the default bid document is the bid document with a bid price equal to the announced water value.

Article 45. Data for Scheduling the Next Day's Dispatch

The System Operator and Electricity Market shall be responsible for using the following data to schedule the next day's dispatch:

1. Daily load profile of the entire system and each region (North, Central, South).

2. Bids for scheduling from bidding entities.

3. Announced generation volume of hydropower plants as stipulated in Clause 2, Article 36, Clause 6, Article 40, and Clause 2, Article 41 of this Circular.

4. Exported and imported electricity volumes as stipulated in Articles 58 and 59 of this Circular.

5. Capacity of units at power plants providing ancillary services.

6. Requirements for spinning reserve capacity and frequency regulation.

7. Maintenance and repair schedules for transmission networks and generating units approved by the System Operator and Electricity Market.

8. Short-term system security assessment results for day D as prescribed in the Transmission System Regulation issued by the Ministry of Industry and Trade.

9. Updated information on the readiness of the transmission network and generating units from the SCADA system or provided by the Transmission Unit and generating units.

Article 46. Scheduling the Next Day's Dispatch

The System Operator and Electricity Market shall be responsible for scheduling the next day's dispatch. The next day's dispatch schedule includes:

1. Unconstrained dispatch schedule, including:

a) Expected electricity price in each trading cycle of the next day;

b) Order of dispatching generating units in each trading cycle of the next day.

2. Constrained dispatch schedule, including:

a) Expected dispatch curve of each unit in each trading cycle of the next day;

b) Shutdown, startup, and grid connection status schedule of each unit expected for the next day;

c) Operation mode and expected wiring diagram of the power system in each trading cycle of the next day;

d) Warning information (if any).

Article 47. Announcing the Next Day's Dispatch Schedule

Before 15:00 every day, the System Operator and Electricity Market shall be responsible for announcing the information in the next day's dispatch schedule, specifically as follows:

1. Expected dispatch capacity (including frequency regulation and spinning reserve capacities) of each unit in each trading cycle of the next day.

2. Expected electricity market price for each trading cycle of the next day.

3. List of units expected to increase or decrease their capacity in each trading cycle of the next day.

4. Information about expected power shortage warnings for the next day (if any), including:

a) Trading cycles expected to have power shortages;

b) Amount of power shortage;

c) Security constraints violated.

5. Information about expected power surplus warnings (if any) for the next day, including:

a) Trading cycles expected to have power surpluses;

b) Units expected to stop generating electricity.

Article 48. Grid Connection of Generating Units

1. For slow-start units, the Power Generation Unit shall be responsible for preparing to connect the unit to the grid according to the next day's dispatch schedule announced by the System Operator and Electricity Market. In cases where the start-up time of the unit exceeds 24 hours, the Power Generation Unit shall be responsible for connecting the unit to the grid based on the short-term system security assessment results announced by the System Operator and Electricity Market.

2. For units that are not slow-start, the Power Generation Unit shall be responsible for preparing to connect the unit to the grid according to the next hour's dispatch schedule announced by the System Operator and Electricity Market.

Article 49. Measures to handle power shortage warnings

1. Modify bidding offers

a) The bidding entity is permitted to modify and resubmit the bidding offer on the next day or for remaining trading cycles within the day D at least sixty minutes before the time of operation when the bidding offer changes, to the System Operator and Electricity Market.

b) The modified bidding offer shall not reduce the bid capacity or change the bid price compared to the bidding offer of the bidding entity on the next day.

c) The System Operator and Electricity Market are responsible for verifying the validity of the modified bidding offers and using them as scheduling bidding offers for the next hour dispatch and market pricing.

2. Modify announced capacities of multi-purpose strategic hydropower plants

The System Operator and Electricity Market are permitted to modify the announced capacities of multi-purpose strategic hydropower plants according to Clause 2, Article 51 of this Circular.

Section 2
OPERATING THE NEXT HOUR ELECTRICITY MARKET

Article 50. Data for next hour dispatch scheduling

The System Operator and Electricity Market are responsible for using the following data to schedule the next hour dispatch:

1. Load profiles of the entire system and each region (North, Central, South) forecasted for the next hour and the subsequent three hours.

2. Bids for scheduling from bidding entities.

3. Grid connection plans of slow-start units according to the next day dispatch schedule that have been published.

4. Announced outputs of multi-purpose hydropower plants.

5. Frequency regulation capacity, spinning reserve, fast-start reserve, cold reserve, and forced generation due to system security constraints for the next hour.

6. Transmission grid readiness and generator unit availability from SCADA or provided by the Transmission Company and power generation entities.

7. Other system security constraints.

Article 51. Adjusting announced outputs of multi-purpose strategic hydropower plants

1. Before scheduling the next hour dispatch, the System Operator and Electricity Market may adjust the hourly output of multi-purpose strategic hydropower plants that have been announced according to Clause 2, Article 36 of this Circular in the following cases:

a) There are unusual hydrological fluctuations;

b) There are power shortage warnings according to the next day dispatch schedule;

c) There are decisions by competent state management agencies regarding reservoir regulation of multi-purpose strategic hydropower plants for flood control and irrigation purposes.

2. The range of hourly output adjustment of multi-purpose strategic hydropower plants in the cases specified in points a and b of Clause 1 of this Article shall be determined annually by the Electricity Regulatory Authority based on the proposal of the System Operator and Electricity Market, taking into account the results of system and market operations in the previous year. In the first year of electricity market operation, the adjustment range is ±5%.

Article 52. Scheduling the next hour dispatch

1. The System Operator and Electricity Market are responsible for scheduling the next hour dispatch for generating units using constrained scheduling methods.

2. Scheduling the next hour dispatch in case of power shortage

a) The System Operator and Electricity Market schedule the units in the following order:

- According to the scheduling bidding offer;

- Multi-purpose strategic hydropower plants according to adjusted capacity;

- Units providing fast-start reserve services, units providing cold reserve services according to the next day dispatch schedule;

- Units providing forced generation services due to system security constraints;

- Spinning reserve capacity;

- Reducing frequency regulation reserve capacity to the lowest allowable level.

b) The System Operator and Electricity Market check and determine the expected amount of capacity to be shed to ensure system security.

3. Scheduling the next hour dispatch in case of excess power

The System Operator and Electricity Market are responsible for adjusting the next hour dispatch through the following measures in sequence:

a) Stopping voluntary units that cease power generation;

b) Minimizing the output of units providing spinning reserve services;

c) Minimizing the output of units providing frequency regulation services;

d) Stopping non-slow-start units according to bid prices from highest to lowest;

đ) Gradually reducing the output of slow-start units to their lowest stable output levels;

e) Stopping slow-start units in the following order:

- With the shortest start-up time;

- With the lowest to highest start-up costs. Start-up costs are agreed upon by the sole buyer and the power generation entity and provided to the System Operator and Electricity Market;

- With the lowest capacity sufficient to resolve the excess power situation.

Article 53. Announcing the upcoming dispatch schedule

The system operator and electricity market have the responsibility to announce the upcoming dispatch schedule fifteen (15) minutes before operation time, including the following contents:

1. Forecast of the upcoming hour load for the entire system and the North, Central, and South regions.

2. Dispatch schedule of power generation units for the upcoming hour and the next three (03) hours, established according to the provisions of Article 52 of this Circular.

3. Measures for handling situations of insufficient or excess capacity by the system operator and electricity market.

4. Information on adjustments to the announced capacity of strategic multi-purpose hydropower plants as stipulated in Article 51 of this Circular.

5. Scheduled load shedding plan (if any).

Section 3
REAL-TIME OPERATIONS

Article 54. Real-time System Operation Scheduling

1. The system operator and electricity market are responsible for operating the system in real-time based on the announced upcoming dispatch schedule and must comply with the regulations on real-time system operation as set forth in the Transmission System Regulation issued by the Ministry of Industry and Trade.

2. Power generation units are responsible for complying with the scheduling orders issued by the system operator and electricity market.

Article 55. Intervening in the Electricity Market

1. Cases of intervening in the electricity market

The system operator and electricity market are permitted to intervene in the electricity market in the following cases:

a) The system is operating under emergency conditions as defined in the Transmission System Regulation issued by the Ministry of Industry and Trade;

b) It is not possible to release the upcoming dispatch schedule fifteen (15) minutes before the operation time.

2. Measures for intervening in the electricity market

The system operator and electricity market shall mobilize power generation units in the following order:

a) According to valid bids from bidding entities for that trading cycle;

b) In case bidding entities do not have valid bids for that trading cycle:

- Apply the floor price for the contracted quantity;

- Apply the ceiling price of the bid for the remaining quantity.

c) In case it is not possible to implement the measures specified in points a and b of this Clause, the system operator and electricity market shall be responsible for mobilizing units to ensure the following objectives in priority order:

- Ensuring balance between generation capacity and load;

- Meeting frequency regulation reserve requirements;

- Meeting spinning reserve requirements;

- Meeting voltage quality requirements.

3. Announcing information about intervention in the electricity market

a) When intervening in the electricity market, the system operator and electricity market must announce the following contents:

- Reasons for the need to intervene in the market;

- Expected trading cycles to be intervened in the electricity market.

b) Within twenty-four (24) hours from the end of the market intervention, the system operator and electricity market are responsible for announcing the following contents:

- Reasons for the need to intervene in the market;

- Trading cycles intervened in the electricity market;

- Measures applied by the system operator and electricity market to intervene in the electricity market.

Article 56. Suspension of Electricity Market

1. The electricity market shall be suspended from operation when any of the following situations occur:

a) Due to emergency situations caused by natural disasters or national defense and security protection;

b) Upon request of the System Operator and Electricity Market Operator to suspend the electricity market in the following cases:

- The power system operates under the extremely urgent mode as prescribed in the Power Transmission System Regulation issued by the Ministry of Industry and Trade;

- Failure to ensure safe and continuous operation of the electricity market.

c) The results of the electricity market operation do not meet the set objectives.

2. The Electricity Regulatory Authority shall be responsible for reviewing and deciding to suspend the electricity market in the cases stipulated in Clause 1 of this Article and notifying the System Operator and Electricity Market Operator.

3. The System Operator and Electricity Market Operator shall be responsible for informing the participants in the electricity market of the decision to suspend the electricity market made by the Electricity Regulatory Authority.

4. Operation of the power system during the suspension period of the electricity market:

a) The System Operator and Electricity Market Operator shall be responsible for dispatching and operating the power system according to the following principles:

- Ensuring safe, stable, and reliable operation of the system with the lowest cost of electricity purchase for the entire system;

- Ensuring the fulfillment of production volume agreements in export and import electricity contracts, BOOT power plant electricity purchase and sale contracts, and electricity purchase and sale contracts with production volume commitments of other power plants;

b) Power generation units, transmission units, and other related units shall be responsible for complying with the dispatch orders of the System Operator and Electricity Market Operator.

Article 57. Resumption of Electricity Market

1. The electricity market shall be resumed when the following conditions are met:

a) The causes leading to the suspension of the electricity market have been resolved;

b) The System Operator and Electricity Market Operator confirm the ability to resume the operation of the electricity market.

2. The Electricity Regulatory Authority shall be responsible for reviewing and deciding to resume the electricity market and notifying the System Operator and Electricity Market Operator.

3. The System Operator and Electricity Market Operator shall be responsible for informing the participants in the electricity market of the decision to resume the electricity market made by the Electricity Regulatory Authority.

Section 4
EXPORT AND IMPORT OF ELECTRICITY
IN THE OPERATION OF THE ELECTRICITY MARKET

Article 58. Handling of Exported Electricity in Scheduling

1. Before 16:00 on day D-2, the sole bulk buyer shall be responsible for notifying the System Operator and Electricity Market Operator of the expected amount of exported electricity in each trading cycle of day D.

2. The amount of exported electricity shall be treated as load at the export point and used to calculate the system load forecast for scheduling the next day and hour.

Article 59. Handling of Imported Electricity in Scheduling

1. Before 16:00 on day D-2, the sole bulk buyer shall be responsible for notifying the System Operator and Electricity Market Operator of the amount of imported electricity in each trading cycle of day D.

2. The amount of imported electricity shall be treated as generation capacity located at the import point with a bid price of 0 VND/kWh in the scheduling of the next day and hour.

Article 60. Payment for Exported and Imported Electricity Quantities

The quantities of exported and imported electricity shall be settled according to the wholesale electricity purchase and sale contracts signed by the sole purchasing entity.

Chapter VI
MARKET ELECTRICITY PRICE CALCULATION AND
SETTLEMENT IN THE ELECTRICITY MARKET

Section 1
MEASUREMENT DATA OF ELECTRICITY QUANTITIES

Article 61. Provision of Measurement Data

1. Before 15:00 on day D+1, the entity managing the measurement data of electricity quantities shall be responsible for providing the system operation entity and the electricity market with the measurement data of each trading cycle on day D.

2. Prior to the eighth working day following the end of the settlement period, the entity managing the measurement data of electricity quantities shall be responsible for providing the system operation entity and the electricity market with the measurement data of electricity quantities during the settlement period as prescribed in Circular No. 27/2009/TT-BCT dated September 25, 2009 of the Minister of Industry and Trade on measuring electricity quantities in the competitive power generation market.

Article 62. Storage of Measurement Data

The system operation entity and the electricity market shall be responsible for storing the measurement data of electricity quantities and related records for at least five years.

Section 2
MARKET ELECTRICITY PRICE CALCULATION
AND SETTLEMENT CAPACITY

Article 63. Determination of Market Electricity Price

1. After trading day D, the system operation entity and the electricity market shall be responsible for establishing the pricing schedule for each trading cycle on day D in the following sequence:

a) Calculating the system load in the trading cycle by converting the measured production volume to the head-end side of the generating units;

b) Arranging the power bands in the scheduling bidding offers of the power generation entities and the announced production volumes of multi-purpose strategic hydropower plants using the unbundled scheduling method until the total arranged capacity reaches the system load level.

2. The market electricity price shall be equal to the bid price of the last power band in the pricing schedule. In case the bid price of the last power band in the pricing schedule exceeds the market ceiling price, the market electricity price shall be calculated based on the market ceiling price.

3. Before 09:00 on day D+2, the system operation entity and the electricity market shall be responsible for announcing the market electricity price for each trading cycle on day D.

Article 64. Determination of Settlement Capacity

1. After trading day D, the system operation entity and the electricity market shall be responsible for establishing the capacity schedule for each trading cycle on day D in the following sequence:

a) Calculating the adjusted load in the trading cycle by adding the system load to the following components:

- Spinning reserve capacity for the trading cycle;

- Frequency regulation capacity for the trading cycle;

- Encouraged capacity component (calculated as 3% of the system load of the trading cycle).

b) Arranging the power bands in the scheduling bidding offers of the power generation entities and the announced production volumes of multi-purpose strategic hydropower plants for that trading cycle using the unbundled scheduling method until the total arranged capacity reaches the adjusted load level. The frequency regulation and spinning reserve capacities for the trading cycle of the unit being scheduled shall be arranged with a bid price of 0 VND/kWh.

2. The settlement capacity of the unit in the trading cycle shall be equal to the capacity of that unit arranged in the capacity schedule.

3. Before 09:00 on day D+2, the system operation entity and the electricity market shall be responsible for announcing the settlement capacity of each unit in the trading cycles on day D.

Article 65. Determining the Market Electricity Price and Payment Capacity when Intervening in the Electricity Market

1. In cases where the market intervention time is less than 24 hours:

a) The system operator and electricity market entity shall use valid bids to determine the market electricity price in accordance with Article 63 of this Circular and the payment capacity according to Article 64 of this Circular;

b) In cases where there are no valid bids for generating units, the system operator and electricity market entity shall use the floor price for the contractual hour output volume and the ceiling bid price for non-contractual output volume to schedule the market electricity price calculation and capacity schedule for that trading cycle.

2. In cases where the market intervention time is equal to or greater than 24 hours, the system operator and electricity market entity shall not be responsible for calculating the market electricity price and payment capacity during the intervened market period.

Section 3
PAYMENT TO GENERATING UNITS FOR DIRECT MARKET TRANSACTIONS

Article 66. Electricity Output for Settlement in the Electricity Market

1. The system operator and electricity market entity shall be responsible for calculating the components of electricity output from power plants for settlement purposes in the trading cycle, including:

a) Electricity output settled at bid prices for thermal power plants with bid prices higher than the market ceiling price (Qbp);

b) Additional electricity output (Qcon);

c) Electricity output settled at the market electricity price (Qsmp).

2. The electricity output settled at bid prices for thermal power plants with bid prices higher than the market ceiling price in the trading cycle shall be determined as follows:

a) Identify the generating units with bid prices higher than the market ceiling price scheduled for market price calculation in trading cycle i and their metering point locations;

b) Calculate the electricity output settled at bid prices at each metering point identified in point a of this Clause using the following formula:

          if

                                                      if

Where:

i: trading cycle i;

j: metering point j of the thermal power plant, identified in point a of this Clause;

: electricity output settled at bid prices at metering point j in trading cycle i (kWh);

: electricity output measured at metering point j in trading cycle i (kWh);

: electricity output corresponding to the capacity with bid prices lower than or equal to the market ceiling price in trading cycle i of units connected to metering point j and converted to that metering point (kWh);

: electricity output corresponding to the capacity with bid prices higher than the market ceiling price and scheduled for market price calculation in trading cycle i of units connected to metering point j and converted to that metering point (kWh).

c) Calculate the electricity output settled at bid prices for the power plant using the following formula:

Where:

j: metering point j of the thermal power plant, identified in point a of this Clause;

J: total number of metering points of the power plant with units bidding higher than the market ceiling price and scheduled for market price calculation;

: electricity output settled at bid prices of the power plant in trading cycle i (kWh);

: electricity output settled at bid prices at metering point j in trading cycle i (kWh).

3. The additional electricity output of the power plant in the trading cycle shall be determined in the following sequence:

a) Identify the generating units producing additional output due to transmission constraints or other constraints in the trading cycle;

b) Calculate the additional electricity output in the trading cycle at the generator terminal using the following formula:

- For units not constrained to operate according to the next hour dispatch schedule and increase capacity according to dispatch orders in the trading cycle:

- For units already constrained to operate according to the next hour dispatch schedule:

Where:

: additional electricity output of the unit calculated at the generator terminal in trading cycle i (kWh);

: generation capacity of the unit according to the dispatch order of the system operator and electricity market entity in trading cycle i (kW);

 : capacity of the unit scheduled for market price calculation in trading cycle i (kW);

: capacity of the unit according to the next hour dispatch schedule in trading cycle i (kW);

: duration of additional output required by dispatch orders in trading cycle i (minutes).

c) Determine the additional electricity output in the trading cycle of the unit, , by converting the output  from the generator terminal to the metering point.

d) Calculate the additional electricity output of the power plant in trading cycle i using the following formula:

Where:

: total additional electricity output of the power plant in trading cycle i (kWh);

g: additional generating unit of the power plant in trading cycle i;

G: total number of additional generating units of the power plant in trading cycle i;

: additional electricity output of unit g in trading cycle i (kWh).

4. The electricity output settled at the market electricity price of the power plant in trading cycle i shall be determined using the following formula:

Where:

: electricity output settled at the market electricity price of the power plant in trading cycle i (kWh);

: electricity output measured of the power plant in trading cycle i (kWh);

: electricity output settled at bid prices in trading cycle i for thermal power plants with bid prices higher than the market ceiling price (kWh);

: additional electricity output of the power plant in trading cycle i (kWh).

Article 67. Settlement of Market Electricity Energy

1. The system operator and electricity market operator shall be responsible for calculating the total settlement amounts of market electricity energy for power plants during the settlement period according to the following formula:

Where:

Rg: total settlement amounts of market electricity energy during the settlement period (VND);

Rsmp: settlement amount for the quantity of electricity production settled at the market electricity price during the settlement period (VND);

Rbp: settlement amount for the quantity of electricity production settled at the bid price for thermal power plants with bid prices higher than the market ceiling price during the settlement period (VND);

: settlement amount for additional electricity generation in the settlement period (VND).

2. The settlement amount for the quantity of electricity production settled at the market electricity price for power plants during the settlement period shall be determined according to the following procedure:

a) Calculating for each trading cycle according to the following formula:

Where:

: settlement amount for the quantity of electricity production settled at the market electricity price for power plants in trading cycle i during the settlement period (VND);

SMP_{ANNEX I.A[31]} : market electricity price in trading cycle i during the settlement period (VND/kWh);

: quantity of electricity production settled at the market electricity price in trading cycle i during the settlement period (kWh).

b) Calculating for the settlement period according to the following formula:

Where:

: settlement amount for the quantity of electricity production settled at the market electricity price for power plants during the settlement period (VND);

i: trading cycle i within the settlement period;

I: total number of trading cycles within the settlement period;

: settlement amount for the quantity of electricity production settled at the market electricity price for power plants in trading cycle i (VND).

3. The settlement amount for the quantity of electricity production settled at the bid price for thermal power plants with bid prices higher than the market ceiling price during the settlement period shall be determined according to the following procedure:

a) Calculating for each trading cycle according to the following formula:

- In case the measured electricity production of the power plant is greater than or equal to the electricity production settled at the contract price:

Where:

: settlement amount for the portion of electricity bid at a higher price than the market ceiling for the power plant in trading cycle i (VND);

j: bid range j in the bid price list of units belonging to the thermal power plant with bid prices higher than the market ceiling price and arranged in the schedule for calculating the market electricity price;

J: total number of bid ranges in the bid price list of the thermal power plant with bid prices higher than the market ceiling price and arranged in the schedule for calculating the market electricity price;

: bid price corresponding to bid range j in the bid list of units of thermal power plant g in trading cycle i (VND/kWh);

: highest bid price among the bid ranges arranged in the schedule for calculating the market electricity price of the thermal power plant in trading cycle i (VND/kWh);

: total capacity bid at the price  in the bid list of the thermal power plant mobilized in trading cycle i and converted to the metering point (kWh);

: total quantity of electricity production with bid prices higher than the market ceiling price of the thermal power plant in trading cycle i (kWh).

- In case the measured electricity production of the power plant is less than the electricity production settled at the contract price:

Where:

: settlement amount for the portion of electricity bid at a higher price than the market ceiling for the power plant in trading cycle i (VND);

SMP_{ANNEX I.A[31]}: market electricity price in trading cycle i (VND/kWh);

: total quantity of electricity production with bid prices higher than the market ceiling price of the thermal power plant in trading cycle i (kWh).

b) Calculating for the settlement period according to the following formula:

Where:

 : settlement amount for the portion of electricity bid at a higher price than the market ceiling for the power plant in the settlement period (VND);

i: trading cycle i in which the power plant is mobilized at a bid price higher than the market ceiling;

I: total number of trading cycles in which the power plant is mobilized at a bid price higher than the market ceiling;

: settlement amount for the portion of electricity bid at a higher price than the market ceiling for the power plant in trading cycle i (VND).

4. The settlement amount for additional electricity generation of power plants in the trading cycle shall be determined according to the following procedure:

a) Calculating for each trading cycle according to the following formula:

Where:

: settlement amount for additional electricity generation in trading cycle i (VND);

g: additional generating unit of the power plant in trading cycle i;

G: total number of additional generating units of the power plant in trading cycle i;

: additional electricity generation of unit g in trading cycle i (kWh);

: bid price corresponding to the additional generation capacity range of unit g in trading cycle i (VND/kWh).

b) Calculating for the settlement period according to the following formula:

Where:

: settlement amount for additional electricity generation in the settlement period (VND);

i: trading cycle i within the settlement period in which the thermal power plant must increase generation according to dispatch orders;

I: total number of trading cycles within the settlement period in which the thermal power plant must increase generation according to dispatch orders;

: settlement amount for additional electricity generation in trading cycle i (VND).

Article 68. Market Capacity Payment Settlement

The System Operation Unit and Electricity Market shall be responsible for calculating the market capacity payment amount for power plants in each settlement cycle according to the following procedures:

1. Calculate for each trading cycle using the following formula:

Where:

: the market capacity payment amount for the power plant in trading cycle i (VND);

g: the generating unit of the power plant being paid under the capacity price;

G: the total number of generating units of the power plant being paid under the capacity price;

: the market capacity price in trading cycle i (VND/kW);

: the capacity payment quantity of generating unit g in trading cycle i (kW).

2. Calculate for the settlement cycle using the following formula:

Where:

: the market capacity payment amount for the power plant in the settlement cycle (VND);

i: trading cycle i within the settlement period;

I: the total number of trading cycles in the settlement cycle;

: the market capacity payment amount for the power plant in trading cycle i (VND).

Article 69. Differential Contract Payment Amount

Based on the electricity energy market price and the market capacity price announced by the System Operation Unit and Electricity Market, the Power Generation Unit shall be responsible for calculating the differential contract payment amount for the power plant in the settlement cycle according to the following procedures:

1. Calculate for each trading cycle using the following formula:

Where:

: the differential payment amount in trading cycle i (VND);

: the electricity energy quantity being paid at the contract price in trading cycle i (kWh);

P­_c: the differential contract price (VND/kWh);

SMP_{ANNEX I.A[31]}: market electricity price in trading cycle i (VND/kWh);

CAN_{ANNEX I.A[31]}: the market capacity price in trading cycle i (VND/kWh).

2. Calculate for the settlement cycle using the following formula:

Where:

Rc: the differential payment amount in the settlement cycle (VND);

i: the i-th trading cycle in the settlement cycle;

I: total number of trading cycles within the settlement period;

: the differential payment amount in trading cycle i (VND).

Article 70. Payment When Intervening in the Electricity Market

1. In cases where the market intervention time is less than 24 hours, the Power Generation Unit shall receive the payments stipulated in Articles 67, 68, and 69, with the electricity energy market price and the capacity payment quantity determined in Clause 65 of this Circular.

2. In cases where the market intervention time is 24 hours or more, the Power Generation Unit shall be paid according to the contract price for the entire measured electricity energy output.

Article 71. Payment When Halting the Electricity Market

During the period when the electricity market is halted, the Power Generation Unit shall be paid according to the contract price for the entire measured electricity energy output.

Section 4
SERVICE SUPPORT PAYMENTS AND OTHER PAYMENTS

Article 72. Opportunity Cost Payment for Spinning Reserve Service

1. The System Operation Unit and Electricity Market shall be responsible for calculating the opportunity cost payment amount for the Power Generation Unit providing spinning reserve service in the settlement cycle according to the following procedures:

a) Calculating for each trading cycle according to the following formula:

Where:

: the opportunity cost payment amount for the Power Generation Unit in trading cycle i (VND);

g: the generating unit providing spinning reserve service of the Power Generation Unit in trading cycle i;

G: the total number of generating units providing spinning reserve service of the Power Generation Unit in trading cycle i;

: the scheduled capacity for providing spinning reserve service of generating unit g in trading cycle i according to the next hour dispatch schedule (kWh);

: the opportunity cost in trading cycle i of generating unit g (VND/kWh). The opportunity cost is calculated as follows:

Where:

: the electricity energy market price in trading cycle i of day D (VND/kWh);

: the highest bid price among the corresponding bid prices for the range of capacities providing spinning reserve service (VND/kWh).

b) Calculating for the settlement period according to the following formula:

Where:

: the opportunity cost payment amount in the settlement cycle (VND);

i: the i-th trading cycle in the settlement cycle during which the Power Generation Unit provides spinning reserve;

I: the total number of trading cycles in the settlement cycle during which the Power Generation Unit provides spinning reserve;

: the opportunity cost payment amount in trading cycle i (VND).

2. The opportunity cost shall only be paid for thermal generating units providing spinning reserve.

Article 73. Payment for rapid start-up reserve service, cold reserve service, and mandatory operation reserve due to system security constraints

The entity providing rapid start-up reserve service, cold reserve service, and mandatory operation reserve due to system security constraints shall be paid according to the power ancillary services supply contract signed with the System Operator and the electricity market.

Article 74. Payment for multi-purpose strategic hydropower plant

Payment for a multi-purpose strategic hydropower plant shall be carried out according to the power purchase agreement signed with the sole bulk buyer.

Article 75. Other payments

1. Power generation units equipped with synchronous condenser units serving voltage regulation shall be paid for the amount of electric energy received from the grid to generate reactive power:

a) At the market price for units that have bid on the electricity market;

b) According to the power purchase agreement for units that have not bid on the electricity market.

2. Thermal power units required to shut down pursuant to points d and e of Clause 3, Article 52 of this Circular shall be compensated for start-up costs at the agreed cost level between the sole bulk buyer and the power generation unit.

3. In cases where the monthly measured electricity quantity provided by the meter data management entity under Clause 2, Article 61 of this Circular differs from the total daily measured electricity quantity provided by the meter data management entity under Clause 1, Article 61 of this Circular, the difference in electricity quantity shall be paid according to the price stipulated in the power purchase agreement signed between the sole bulk buyer and the power generation unit.

Section 5
PROCEDURE AND FORMALITIES FOR PAYMENT

Article 76. Data for calculating payment in the electricity market

By 9:00 AM on day D+2, the System Operator and Electricity Market shall be responsible for compiling and providing to the sole bulk buyer and power generation units the data necessary for calculating payments for each power plant according to Appendix 6 of this Circular.

Article 77. Daily trading settlement statement

1. Before day D+4, the System Operator and Electricity Market shall be responsible for preparing and sending to the sole bulk buyer and power generation units a preliminary settlement statement for the trading day according to the model specified in Appendix 4 of this Circular.

2. Before day D+6, the direct trading power generation units and the sole bulk buyer shall be responsible for informing the System Operator and Electricity Market of any errors in the preliminary settlement statement (if any).

3. On day D+6, the System Operator and Electricity Market shall be responsible for preparing and sending to the sole bulk buyer and power generation units a complete settlement statement for day D.

Article 78. Settlement statement for the payment cycle

1. The System Operator and Electricity Market shall be responsible for consolidating all payment data for all trading days within the payment cycle and verifying it against the consolidated electricity quantity record provided by the meter data management entity.

2. Within ten (10) working days from the last trading day of the payment cycle, the System Operator and Electricity Market shall be responsible for preparing and issuing the settlement statement for the payment cycle.

3. The settlement statement for the payment cycle includes settlement statements for each trading day and a summary report according to the model specified in Appendix 5 of this Circular and a confirmation of meter readings and electricity quantity.

Article 79. Payment Documents for Electricity Energy

1. The Direct Electricity Generation Unit shall establish and submit market electricity payment documents to the Single Electricity Purchasing Unit based on the market electricity payment statement for the payment cycle.

2. The Electricity Generation Unit shall establish and submit contract payment documents to the Single Electricity Purchasing Unit according to the provisions stipulated in the electricity purchase and sale contracts signed between the Single Electricity Purchasing Unit and the Electricity Generation Unit.

3. Prior to the twentieth day of each month, the Electricity Generation Unit shall establish and submit payment invoices to the Single Electricity Purchasing Unit. The payment invoice includes market electricity payments and contract payments within the payment cycle.

Article 80. Payment Documents for Ancillary Service Contracts

The Electricity Generation Unit is responsible for establishing payment documents for ancillary services according to the ancillary service supply contracts between the Electricity Generation Unit and the System Operation and Electricity Market Unit.

Article 81. Invoice Adjustment

1. In case of errors in the invoice, the Electricity Generation Unit or the Single Electricity Purchasing Unit has the right to request an invoice adjustment within one (01) month from the date of issuance. The relevant parties are responsible for coordinating to determine and agree on the adjusted payment amounts.

2. The Electricity Generation Unit is responsible for supplementing the adjusted payment amount into the invoice of the next payment cycle.

Article 82. Payment

1. At the latest by the last day of each month, the Single Electricity Purchasing Unit and the System Operation and Electricity Market Unit are responsible for making payments according to the invoices of the Electricity Generation Unit.

2. The Electricity Generation Unit and the Single Electricity Purchasing Unit are responsible for agreeing on the payment methods in the electricity market in accordance with this Circular and related regulations.

Article 83. Handling Errors in Payments

In cases where there are overpayments or underpayments compared to the invoice, the relevant units shall handle these errors according to the provisions in the electricity purchase and sale contracts or ancillary service supply contracts.

Chapter VII
SOFTWARE FOR THE OPERATIONS OF THE ELECTRICITY MARKET

Article 84. Software for the Operations of the Electricity Market

1. The software for the operations of the electricity market includes:

a) Market simulation model;

b) Water value calculation model;

c) Scheduling and dispatching software;

d) Settlement calculation software;

e) Other software serving the operations of the electricity market.

2. The System Operation and Electricity Market Unit is responsible for building, developing, and operating software serving the electricity market.

Article 85. Requirements for Software for the Operations of the Electricity Market

1. Ensuring accuracy, reliability, security, and meeting the standards established by the System Operation and Electricity Market Unit.

2. Having complete technical guidelines and operational procedures attached.

Article 86. Development of Software for the Operations of the Electricity Market

1. The software for the operations of the electricity market must be developed to support the calculations and transactions prescribed in this Circular and the operational procedures of the electricity market.

2. The System Operation and Electricity Market Unit is responsible for:

a) Establishing standards for software for the operations of the electricity market;

b) Reviewing and testing the software's compliance with the standards set out in point a of this Clause before implementation;

c) Announcing lists, algorithms, and usage procedures for software for the operations of the electricity market.

Article 87. Audit of Software

1. Software serving the market must be audited in the following cases:

a) Before the official operation of the electricity market;

b) Before putting new software into use;

c) After adjustments and upgrades that affect calculations;

d) Periodic audit.

2. The audit of software shall be conducted by an independent auditing entity. The entity operating the power system and electricity market is responsible for proposing an independent auditing entity, which shall be submitted to the Electricity Regulatory Authority for approval.

Chapter VIII
INFORMATION SYSTEM OF THE ELECTRICITY MARKET
AND PROVISIONS ON DISCLOSURE OF INFORMATION

Section 1
INFORMATION SYSTEM OF THE ELECTRICITY MARKET

Article 88. Structure of the Information System of the Electricity Market

The information system of the electricity market includes the following basic components:

1. Hardware and software systems for managing and exchanging information on the electricity market.

2. Database and storage systems.

3. Electronic portal serving the electricity market, including both internal electronic information pages and public electronic information pages.

Article 89. Management and Operation of the Information System of the Electricity Market

1. The entity operating the power system and electricity market is responsible for building, managing, and operating the Information System of the Electricity Market.

2. Participants in the electricity market are responsible for investing in equipment within their management scope to meet technical requirements set forth by the entity operating the power system and electricity market, ensuring connectivity with the Information System of the Electricity Market.

3. The entity managing electricity consumption measurement data is responsible for developing, managing, and operating the network connection between the Information System of the Electricity Market operated by the entity operating the power system and electricity market and the equipment of participants in the electricity market.

4. The entity operating the power system and electricity market may only put into operation or change the existing Information System of the Electricity Market after it has been fully accepted and approved by the Electricity Regulatory Authority.

5. The entity operating the power system and electricity market is responsible for equipping backup devices for the information system of the market to ensure the collection, transmission, and publication of market information in case the main Information System of the Electricity Market fails or cannot operate.

Section 2
MANAGEMENT AND DISCLOSURE OF INFORMATION ON THE ELECTRICITY MARKET

Article 90. Provision and Disclosure of Information on the Electricity Market

1. Power generation units, sole bulk purchaser, power transmission entities, and entities managing electricity consumption measurement data are responsible for providing the entity operating the power system and electricity market with information and data necessary for operational planning, scheduling, and settlement calculations as stipulated in this Circular through the electronic portal of the Information System of the Electricity Market.

2. The entity operating the power system and electricity market is responsible for providing and disclosing information, data, and operational reports on the electricity market to participants in the electricity market as stipulated in this Circular through the electronic portal of the Information System of the Electricity Market.

3. The level of access permissions to information is determined based on the functions of the entities and is specified in the Operating Procedures of the Information System of the Electricity Market and Information Disclosure.

4. The entity operating the power system and electricity market is responsible for publicly disclosing the following information on the public electronic information page:

a) Information about Participants in the Electricity Market;

b) Data on system load;

c) Statistical data on market prices;

d) Other information as prescribed in the Operating Procedures of the Information System of the Electricity Market and Information Disclosure.

Article 91. Responsibility for Ensuring the Accuracy of Electricity Market Information

1. Participants in the market shall be responsible for ensuring the accuracy and completeness of electricity market information at the time of provision.

2. In cases where inaccurate and incomplete information has been provided and published, participants in the market shall be responsible for correcting and resupplying accurate information to relevant units.

Article 92. Confidentiality of Electricity Market Information

1. The system operator and market operator shall not disclose information provided by participants in the electricity market, including:

a) Information on power purchase and sale contracts;

b) Pre-closing day bidding prices of power generation units;

c) Other information outside their authority.

2. Participants in the electricity market shall not disclose information beyond the scope of authorized provision and publication.

Article 93. Exceptions to Confidentiality of Information

1. Provision of information upon request of the Electricity Regulatory Authority or competent authorities as prescribed by law.

2. Information compiled and analyzed from publicly disclosed market information, not provided by other participants in the electricity market in violation of Article 92 of this Circular.

Article 94. Storage of Electricity Market Information

The system operator and market operator shall be responsible for retaining all information exchange activities conducted through the Electricity Market Information System. The retention period for information shall be at least five (05) years.

Section 3
REPORTING ON MARKET OPERATIONS

Article 95. Publication of Market Operation Information

The system operator and market operator shall be responsible for periodically preparing and publishing market operation information as stipulated in the Detailed Procedures for Operating the Electricity Market Information System, specifically as follows:

1. Before 15:00 each day, prepare and publish the previous day's market operation report.

2. Before each week's Tuesday, prepare and publish the previous week's market operation report.

3. Before the tenth day of each month, prepare and publish the previous month's market operation report.

4. Before January 31 each year, prepare and publish the previous year's market operation report.

Article 96. Reporting System for Market Operations

1. Before the tenth day of each month, the system operator and market operator shall be responsible for submitting to the Electricity Regulatory Authority the previous month's system and market operation reports according to the form prescribed by the Electricity Regulatory Authority.

2. Before January 31 each year, the system operator and market operator shall be responsible for submitting to the Electricity Regulatory Authority the previous year's system and market operation reports according to the form prescribed by the Electricity Regulatory Authority.

3. Within twenty-four (24) hours following the conclusion of market intervention, the system operator and market operator shall be responsible for reporting to the Electricity Regulatory Authority on the market intervention.

4. The system operator and market operator shall be responsible for providing ad hoc reports on system and market operations upon request of the Electricity Regulatory Authority.

Article 97. Auditing Data and Compliance in the Electricity Market

1. Periodic Audits

Before March 31 each year, the System Operator and Electricity Market Entity shall be responsible for organizing and completing the auditing of data and compliance in the electricity market of the previous year. The annual audit contents include:

a) Auditing data and the calculation process conducted by the System Operator and Electricity Market Entity in the electricity market, including:

- Data for the calculation process in the electricity market;

- Calculation steps;

- Calculation results.

b) Auditing the compliance of the System Operator and Electricity Market Entity with the procedures and processes stipulated in this Circular.

2. Unannounced Audits

The Electricity Regulatory Authority has the right to request the System Operator and Electricity Market Entity to organize unannounced audits according to specific audit contents and scopes in the following cases:

a) When signs of abnormal operation in the electricity market are detected;

b) Upon the request of market participants. The procedure is as follows:

- Market participants submit a written request to the Electricity Regulatory Authority detailing the audit content and reasons;

- Within thirty days from receiving the request, the Electricity Regulatory Authority is responsible for reviewing and issuing a written approval or disapproval of the audit request, specifying the audit content and scope or the reason for disapproval.

3. The System Operator and Electricity Market Entity are responsible for proposing an independent auditing entity with sufficient capacity to conduct the market audit contents and submitting it to the Electricity Regulatory Authority for approval.

4. Market participants are responsible for fully cooperating during the market audit implementation process.

5. Audit Costs

a) To be borne by the System Operator and Electricity Market Entity in cases specified in Clause 1 and Point a, Clause 2 of this Article;

b) To be borne by the requesting entity in the case specified in Point b, Clause 2 of this Article.

6. Within ten days from the end of the audit, the System Operator and Electricity Market Entity are responsible for submitting the audit report to the Electricity Regulatory Authority and relevant entities.

Chapter IX
SETTLEMENT OF DISPUTES AND HANDLING OF VIOLATIONS

Section 1
DISPUTE RESOLUTION

Article 98. Procedure for Resolving Disputes in the Electricity Market

1. Disputes arising in the electricity market shall be resolved according to the Regulations on Procedures and Processes for Resolving Disputes in the Electricity Sector issued by the Ministry of Industry and Trade.

2. Prior to resolving disputes as prescribed in Clause 1 of this Article, the parties are responsible for negotiating to resolve the dispute (mediation) within sixty (60) days through one of the following methods:

a) Self-mediation;

b) Mediation through intermediaries. The parties may invite experts with expertise or request the Electricity Regulatory Authority to appoint staff as mediators.

Article 99. Responsibilities of Parties During Mediation

1. Agreeing on the mediation format, time, and location for negotiations.

2. Providing complete, truthful, and accurate information and documents related to the dispute content.

3. Presenting lawful evidence to protect their rights and legitimate interests.

4. Participating in the negotiation process with a spirit of goodwill and cooperation.

5. During the mediation process, if a violation of market regulations is discovered, the party discovering it is responsible for informing the other party to stop the mediation and reporting to the Electricity Regulatory Authority.

Article 100. Notification of Disputes and Preparation for Negotiations

1. When a dispute arises, the complaining party shall be responsible for notifying the complained party in writing about the dispute and requesting resolution thereof, and submitting one (01) copy to the Electricity Regulatory Authority for reporting.

2. Within fifteen (15) days from the date of receipt of the notification, the parties shall be responsible for agreeing among themselves on the form of mediation, the matters to be resolved, the time and place of negotiations. In cases where they choose to mediate through an intermediary, the parties shall be responsible for agreeing on the selection of the mediator. The parties have the right to agree to change the mediator before the agreed mediation time.

Article 101. Mediation Organization

1. Self-mediation

The parties shall be responsible for exchanging and agreeing on the matters to be resolved.

2. Mediation through an intermediary

a) The parties shall be responsible for selecting the mediator and agreeing on the responsibilities of the mediator;

b) The parties shall be responsible for providing the mediator with the content of the dispute, relevant information and documents related to the dispute, and the resolution requests of each party;

c) The parties may agree with the proposed resolution by the mediator; request the mediator to modify or supplement the proposed resolution, or negotiate to reach a new resolution agreement.

Article 102. Mediation Minutes

1. After the conclusion of mediation or the expiration of the mediation period, the disputing parties shall be responsible for preparing the Mediation Minutes including the following contents:

a) Time and place of mediation;

b) Names and addresses of the parties participating in mediation;

c) Summary of the dispute content;

d) Content of the parties' requests;

đ) Agreed contents;

e) Unagreed contents and reasons for non-agreement.

2. Within five (05) days from the date of preparation of the mediation minutes, the parties shall be responsible for submitting one (01) copy to the Electricity Regulatory Authority for reporting.

Article 103. Resolution of Disputes at the Electricity Regulatory Authority

1. The parties have the right to submit the case to the Electricity Regulatory Authority for dispute resolution in the following cases:

a) Upon expiration of the mediation period stipulated in Clause 2, Article 98 of this Circular, if the dispute cannot be mediated successfully or mediation cannot be organized due to one party's non-participation in mediation;

b) One party does not implement the contents agreed upon in the Mediation Minutes.

2. After receiving the Request for Dispute Resolution (Complaint), the Electricity Regulatory Authority shall be responsible for resolving disputes according to the procedures and formalities prescribed in the Regulations on Procedures and Formalities for Resolving Disputes in Electricity Activities issued by the Ministry of Industry and Trade.

Section 2
HANDLING VIOLATIONS

Article 104. Detection and Reporting of Violations

1. Acts of violation detected in the electricity market must be reported to the Electricity Regulatory Authority in writing.

2. The content of the report on violations includes:

a) Name and address of the reporting entity;

b) Name and address of the entity committing the violation;

c) Violation act;

d) Date and time of occurrence of the violation;

đ) Reason for detecting the violation.

Article 105. Inspection and Verification of Violations

1. Within five (05) days from the date of receiving a report on a violation, the Electricity Regulatory Authority shall be responsible for organizing inspection and verification.

2. During the process of inspecting and verifying violations, the Electricity Regulatory Authority has the right to:

a) Request units suspected of violating, and related units to provide necessary information and documents for the inspection and verification process;

b) Request units suspected of violating to explain;

c) Request expert opinions or opinions from relevant agencies or units;

d) Summon units suspected of violating and affected units due to the violation to provide opinions on resolving and rectifying the violation.

3. During the inspection and verification process, the Electricity Regulatory Authority shall be responsible for keeping confidential all information and documents provided according to the provisions on information confidentiality stipulated in this Circular.

Article 106. Establishment of Violation Records

1. Within thirty (30) days from the date of commencing inspection and verification, the Electricity Regulatory Authority shall be responsible for concluding the inspection and verification and establishing a Violation Record for violations concerning the operation of the electricity market. In cases where the matter involves many complex circumstances, the inspection and verification period may be extended but not exceeding sixty (60) days from the date of initiating inspection and verification.

2. The Violation Record shall be established in accordance with the regulations on penalties for violations in the field of electricity.

3. If the results of inspection and verification show that the reported behavior does not violate the regulations on the operation of the electricity market, the Electricity Regulatory Authority shall cease inspection and verification and notify the reporting organization or individual.

Article 107. Forms of Handling Violations

1. The violator unit must bear one of the forms and levels of penalty for each violation according to the regulations on penalties for violations in the field of electricity.

2. For power plants that violate the provisions set out in Clause 1, Article 8 of this Circular, in addition to being penalized according to the provisions of Clause 1 of this Article, they will also have their right to participate in the electricity market suspended. The suspension period depends on the nature and degree of the violation but shall not exceed six (06) months.

Article 108. Procedure and Formalities for Suspending Participation Rights in the Electricity Market

1. In cases where a power plant violates the provisions set out in Clause 1, Article 8 of this Circular, within five (05) days from the date the Violation Record is established, the Electricity Regulatory Authority shall examine and issue a decision suspending the participation rights in the electricity market of the violating power plant and send it to the violating power plant and the System Operation and Market Unit.

2. Within one (01) day from the date of receipt of the Decision to Suspend Participation Rights in the Electricity Market, the System Operation and Market Unit shall be responsible for announcing the suspension of the participation rights in the electricity market for the violating power plant.

3. Upon expiration of the period specified in Clause 2, Article 107 of this Circular, if the power plant has not yet rectified the violation, the Electricity Regulatory Authority has the right to issue a decision extending the suspension of participation rights in the electricity market. The extension period shall not exceed six (06) months, starting from the date of expiration of the suspension of participation rights in the electricity market.

Chapter X
IMPLEMENTATION

Article 109. Implementation Organization

1. The Electricity Regulatory Authority shall be responsible for disseminating, guiding, inspecting, and supervising the implementation of this Circular.

2. Vietnam Electricity Group shall be responsible for directing the System Operation Units and Electricity Market Units to:

a) Develop technical procedures to be submitted to the Electricity Regulatory Authority for issuance within six (06) months from the date this Circular takes effect, including:

- Procedures for planning system operation for the year, month, and week ahead;

- Procedures for selecting the best new power plant and calculating market capacity price;

- Procedures for simulating the electricity market;

- Procedures for calculating water value;

- Procedures for classifying generating units and determining the ceiling bid price for thermal power plants;

- Procedures for scheduling power generation units;

- Procedures for operating the market information system and publishing information.

b) Invest in, construct, install, and upgrade the Electricity Market Information System and software serving the market in accordance with the requirements stipulated in this Circular.

3. Market participants shall be responsible for completing information equipment in compliance with the Electricity Market Information System as prescribed in this Circular.

4. Power generation units participating in the market shall be responsible for signing power purchase and sale contracts according to the model issued by the Ministry of Industry and Trade applicable to the competitive power generation market.

5. During the implementation of this Circular, if there are any difficulties, relevant units shall be responsible for reporting to the Electricity Regulatory Authority for research, proposal, and submission to the Ministry of Industry and Trade for amendment and supplementation of this Circular to ensure its appropriateness.

Article 110. Effective Date

1. This Circular shall take effect from June 25, 2010.

2. The Director of the Electricity Regulatory Authority, the Head of the Ministry's Office, the Inspector General of the Ministry, the Heads of Departments, Directors of relevant agencies under the Ministry, relevant units, and market participants shall be responsible for implementing this Circular./.