Thông tư 25/2016/TT-BCT

CIRCULAR

REGULATIONS ON ELECTRICITY TRANSMISSION SYSTEM

Pursuant to the Government's Decree No. 95/2012/ND-CP dated November 12, 2012, defining the functions, tasks, powers and organizational structure of the Ministry of Industry and Trade;

Pursuant to the Law on Electricity dated December 03, 2004 and the Law on Amendments to a number of articles of the Law on Electricity;

Pursuant to the Government's Decree No. 137/2013/ND-CP dated October 21, 2013 detailing the implementation of a number of articles of the Law on Electricity and the Law on Amendments to the Law on Electricity;

At the request of general director of Electricity Regulatory Authority,

The Minister of Industry and Trade promulgates the Circular stipulating electricity transmission system.

Chapter I

GENERAL PROVISIONS

Article 1. Governing scope

This Circular stipulates:

1. Requirements of operation of the electricity transmission system

2. Load forecasts

3. Transmission grid development plan

4. Technical requirements and procedures for connection to transmission grid.

5. Assessment of electricity system security

6. Operation of electricity transmission system

Article 2. Regulated entities

1. This Circular applies to:

a) Transmission network operator;

b) Electricity system and market operator;

c) Electricity wholesalers;

d) Electricity distribution units;

dd) Electricity retailers;

e) Generating units;

g) Electricity customers receiving electricity from transmission grid (hereinafter referred to as “electricity customers”);

h) Vietnam Electricity;

i) Other organizations, individuals.

2. Generating sets of a power plant with total installed capacity greater than 30 MW connected to distribution grid must meet technical requirements of equipment connected to transmission grid and other relevant requirements prescribed herein.

Article 3. Interpretation of terms

In this Circular, some terms are construed as follows:

1. AGC (Automatic Generation Control) is an automatic equipment system for adjusting active power of generating sets to maintain stability of electricity system frequency within permissible scope according to operating principles of generating sets.

2. Electricity system security is the ability of the system to supply power to meet demands for loads at a certain point of time or for a specified period with account taken of electricity system obligations.

3. AVR (Automatic Voltage Regulator) is a system used to control terminal voltage of generating sets through the impact on the excitation system of the generating set to ensure terminal voltage of the generating set within permissible limits.

4. Voltage level is one of nominal voltage values of a system, including:

a) Low voltage: nominal voltage level to 01 kV;

b) Medium voltage: nominal voltage level over 01 kV to 35 kV;

c) High voltage: nominal voltage level over 35 kV to 220 kV;

d) Ultra- high voltage: nominal voltage level over 220 kV.

5. Dispatching level with control authority (hereinafter referred to as “the dispatch level”) is a dispatching level that has the right to direct and dispatch the electricity system under the dispatching hierarchy prescribed in the Dispatch Procedure of national electricity system promulgated by the Ministry of Industry and Trade.

6. Available capacity of a generating set is the maximum generating capacity of the generating set for a specified period of time.

7. Governor deadband is a frequency band within which any change of electricity system frequency shall not result in reactions or impacts of the governor for adjusting primary frequency.

8. Spinning reserve is the ability of a generating set operating in the national electricity system to increase or decrease generating capacity to restore electricity system frequency to permissible scope after a single fault and restore reserve capacity of frequency control.

9. Primary frequency adjustment is the process of adjusting electricity system frequency immediately by a large number of generating sets equipped with a governor.

10. Secondary frequency adjustment is the adjustment process following the primary frequency adjustment carried out through the impact of AGC system on some generating sets specified in the system or load shedding system under the frequency or dispatching instructions

11. Electricity system dispatching is activities of directing and controlling the process of power generation, transmission and distribution in the national electricity system according to the defined procedures, technical regulations and operation modes.

12. Electricity wholesaler is the electricity unit that is granted the operation licence in electricity wholesaling. According to level of competitive electricity market, an electricity wholesaler shall be one of the following units:

a) Electric Power Trading Company;

b) Power Corporations;

c) Other electricity wholesalers which are established according to individual levels of competitive electricity market.

13. Generating unit is an electricity unit which is granted the operation licence in power generation, possesses one or several power plants connected to the transmission grid or a power plant of over 30 MW in installed capacity connected to distribution grid.

14. Electricity distributor means the electricity unit that is granted the operation licence in electricity distribution, including:

a) Power Corporations;

b) Electricity companies of provinces, central-affiliated cities (hereinafter referred to as “provincial electricity companies”) affiliated to Power Corporations.

15. Electricity retailer is an electricity unit that is granted the operation licence in electricity retailing.

16. Transmission network operator is the electricity unit that is granted the operation licence in electricity transmission responsible for management and operation of national transmission grid.

17. Electricity system and market operator (the national electricity system dispatch center) is the unit responsible for directing and controlling the process of power generation, transmission and distribution in the national electricity system and conducting transactions in electricity market.

18. Reliability of a protection system includes:

a) Impact reliability of the protection system is the factor indicating ability of the protection system to work properly on an incident within the determined scope of protection;

b) Non-impact reliability of the protection system is the factor indicating ability of the protection system to avoid malfunctioning at the normal operation mode or any incident arising beyond the determined scope of protection.

19. Governor is a device used to regulate rotating speed of the turbine of a generating set according to frequency changes to restore frequency to nominal electricity system frequency.

20. EMS (Energy Management System) is an energy management software system to optimize operation of the electricity system.

21. DCS (Distributed Control System) is a system of control equipment in a power plant or power station connected to the network on the principle of distributed control to increase reliability and restrict effects caused by breakdown of control elements in the power plant or power station.

22. Electricity system is a system of generating equipment, electricity network and utilities connected to each other.

23. The national electricity system is an electricity system which is managed in a uniform manner across the country.

24. Electricity transmission system is an electricity system including a transmission grid and power plants connected to the transmission grid.

25. SCADA (Supervisory Control and Data Acquisition) is a data collection system serving monitoring, control and operation of the electricity system.

26. Earth-fault factor is the ratio between the voltage on a healthy phase during a fault and value of voltage of such phase before the fault (in case of single or double phase to ground fault).

27. Synchronization is the act of connecting generating sets to the electricity system or two parts of the electricity system together according to synchronization conditions prescribed in the operating procedure in the national electricity system issued by the Ministry of Industry and Trade.

28. Black start capability is the ability of a power plant to restore at least one generating set to operation from the state of complete stop and synchronize to the electrical grid without relying on transmission network in the area.

29. Black start is the process of restoring all or part of an electricity system to operation from the state of wholly or partial loss of power by using generating sets with black start capability.

30. Customers using transmission grid are organizations and/or individuals possessing electrical equipment, electrical grid to connect to transmission grid, including:

a) Generating units;

b) Electricity distribution units receiving electricity direct from transmission grid;

c) Electricity retailers receiving electricity direct from transmission grid;

d) Electricity customers.

31. Dispatch instruction is an order of commanding and controlling operation mode of an electricity system in real time.

32. Electrical grid is a system of transmission lines, power station and utilities for power transmission.

33. Distribution grid is a part of an electrical grid including transmission lines and power stations of up to 110 kV.

34. Transmission grid is a part of an electrical grid including transmission lines and power stations of over 110 kV.

35. Short-term flicker perceptibility (P_st) is a value measured for ten minutes by a flicker meter of IEC868 standard.

36. Long-term flicker perceptibility (P_lt) is a value calculated from 12 measurement results of short-term perceptibility for about two hours in following formula:

37. Year N is the current year of operating an electricity system, calculated according to calendar year.

38. Typical day is a day that has the typical day of consumption of loads as prescribed in the contents, methods and procedure for electrical load research issued by the Ministry of Industry and Trade. Typical days include typical working days, weekends, holidays (if any) of years, months and weeks.

39. Outage or reduction of power supply according to plan is the suspension of power supply to carry out the plan for maintenance, repairs, overhaul and installation of electrical works; regulation and restriction of loads in case of a shortage according to the plan as informed by the electricity system and market operator.

40. Thermo-electric plant is a power plant operating on the principle of thermal to electrical energy conversion including biomass, biogas and solid waste power plants.

41. Regulations on competitive electricity market operation are the regulations issued by the Ministry of Industry and Trade and also the responsibility of the units in the electricity market by level.

42. Load shedding is the process of cutting loads from electricity system in case of incident or lack of electricity system security, carried out through an automatic load shedding system or dispatch instruction.

43. Breakdown is an event or one or several equipment in the electricity system causing a disruption of power supply or affecting safe and stable supply of power to the national electricity system.

44. Single fault is a breakdown occurring in a single component of an electricity transmission system as the electricity system is in normal operation mode.

45. Multi fault is a breakdown occurring in at least two components of an electricity transmission system at the same time.

46. Serious fault is an breakdown causing extensive loss of power on the entire transmission grid, or fire & explosion which damages people and property.

47. Electricity system split is a situation in which the national electricity system is separated into disconnected small electricity systems by a fault.

48. RTU/Gateway (Remote Terminal Unit/Gateway) is a device placed at a power station or power plant serving collection and transmission of data to SCADA system of the electricity system dispatch center or control center.

49. PSS (Power System Stabilizer) is a device added to the automatic voltage regulator to decrease voltage fluctuation in the electricity system.

50. Time of starting is a minimum period of time needed to start a generating set from the time the generating unit receives the starting order from the electricity system and market operator to the time the generating set is synchronized into the national electricity system.

51. N-1 criterion is a criterion for planning, design, investment, construction and operation of an electricity system that ensures the electricity system operates normally in accordance with the operating standards, permissible operating limits when a breakdown occurs in the system or a component is taken from the system for maintenance and repairs.

52. IEC standards are electrotechnical standards issued by the International Electrotechnical Commission.

53. Automatic under-frequency load shedding is the act of cutting loads by frequency relays when frequency or frequency slope of the electricity system drops below permissible limit.

54. Power station is a substation, switching station or compensation station.

55. Control center is a center equipped with information technology and telecommunications infrastructure system to remotely monitor and control a group of power plants, power stations or switchgears on the electrical grid.

56. pu is a per-unit system expressing the ratio between actual value and rated value.

Chapter II

REQUIREMENTS FOR OPERATION OF ELECTRICITY TRANSMISSION SYSTEM

Article 4. Frequency

1. Nominal frequency of the national electricity system is 50 Hz. In normal operation mode, electricity system frequency may fluctuate within ± 0.2 Hz compared with nominal frequency. In other operation modes, permissible frequency band fluctuation and time for restoration of electricity system to normal operation are prescribed in Table 1 below:

Table 1

Permissible frequency band fluctuations and time for restoration of electricity system to normal operation at other operation modes of the national electricity system

2. Permissible frequency band and acceptable number of beyond-the-limit times (the number of times the frequency may exceed the permissible limits) in case of multi fault, serious fault or extreme emergency mode are determined according to annual or biennial cycle in Table 2 below:

Table 2

Permissible frequency band and acceptable number of beyond-the-limit times in case of multi fault, serious fault or extreme emergency mode

3. During the operation of the national electricity system, the electricity system and market operator shall be responsible for dispatching and operating the national electricity system and mobilizing all forms of ancillary services to ensure the frequency is within the permissible band.

Article 5. Stabilization of electricity system

1. Stabilization of an electricity system is the ability of the electricity system, with predetermined initial conditions, to return to normal operation mode or reset mode after a physical impact has changed operational parameters of the electricity system. Stabilization of electricity system is classified as follows:

a) Transient stability is the ability of generating sets in the electricity system to maintain consistent operational state when subjected to major disturbances.

b) Small signal stability is the ability of generating sets in the electricity system to maintain consistent operational state when subjected to small disturbances;

c) Dynamic voltage stability is the ability of an electricity system to maintain steady voltage at all buses when subjected to major disturbances.

d) Steady state voltage stability is the ability of an electricity system to maintain steady voltage at all buses when subjected to small disturbances.

dd) Frequency stability is the ability of an electricity system to maintain steady frequency when disturbances have caused loss of load-generation balance.

2. Sub-synchronous resonance is a phenomenon in which the resonant frequency of the turbine shaft coincides with electricity system frequency resulting in torsional stress on the turbine shaft.

3. The national electricity system operating at normal operation modes or after the fault is cleared must maintain consistency and meet electricity system stability standards prescribed in Table 3 below:

Table 3

Electricity system stability standards

Article 6. Voltage

1. Nominal voltage levels of a transmission grid are 500 kV, 220 kV.

2. In normal operation conditions or in case of a single fault in a transmission grid, permissible voltage at busbars on the transmission grid is prescribed in Table 4 below:

Table 4

Voltage at busbars on transmission grid

3. In case of a multi fault, serious fault, in an extreme emergency operation mode or electricity system restoration mode, permissible voltage fluctuation on the transmission grid is greater than ± 10 % to ± 20 % compared with nominal voltage.

4. During the fault, voltage at the place where the fault occurs and surrounding areas may drop to 0 at phases with fault or increase over 110% of the nominal voltage at phases without fault until the fault is cleared.

Article 7. Phase balance

In normal operation mode, negative sequence voltage components are not allowed to exceed 3% of nominal voltage on transmission grid.

Article 8. Harmonics

1. Permissible maximum value of total harmonic distortion (based on percentage of nominal voltage) caused by high-level harmonic components to the voltage level 220 kV and 500 kv is not allowed to exceed 3%.

2. Permissible maximum value of total demand distortion (based on percentage of nominal voltage) to the voltage level 220 kV and 500 kv is not allowed to exceed 3%.

3. In normal operation mode, the transmission network operator shall ensure total harmonic distortion on the transmission grid is within the range as prescribed in Clause 1, this Article.

4. Customers using transmission grid shall ensure harmonics in the equipment connected to the transmission grid must not exceed the range as prescribed in Clause 2, this Article.

5. If total harmonic distortion shows signs of violation of the range as prescribed in Clause 1 or 2, this Article, the customer using transmission grid or the transmission network operator has the right to order other relevant units to inspect harmonic values or hire an independent testing unit to do the job. If the result of inspection shows that the total harmonic distortion violates the range as prescribed in Clause 1 or 2, this Article, all the expenses for inspection, verification, damage and implementation of remedial measures shall be incurred by any entity that is found in breach of the regulation.

Article 9. Flicker perceptibility

1. Permissible maximum flicker perceptibility in a transmission grid is stipulated in Table 5 below:

Table 5

Flicker perceptibility

Where: P_lt95%, P_st95%: Threshold value of P_lt, P_st respectively.

2. The transmission network operator shall control flicker perceptibility on the transmission grid to ensure that the flicker perceptibility at connection point must not exceed the value prescribed in Table 5 in normal operation mode. Customers using transmission grid shall ensure flicker perceptibility on the equipment connected to the transmission grid must not exceed the value as prescribed in Table 5.

3. If flicker perceptibility shows signs of violation of the range as prescribed in Clause 1, this Article, the customer using transmission grid or the transmission network operator has the right to order other relevant units to inspect flicker perceptibility or hire an independent testing unit to do the job. If the result of inspection shows that the flicker perceptibility violates the range as prescribed in Clause 1, this Article, all the expenses for inspection, verification, damage and implementation of remedial measures shall be incurred by any entity that is found in breach of the regulation.

Article 10. Voltage fluctuation

1. Voltage fluctuations at connection points on the transmission grid by fluctuating loads shall be not allowed to exceed 2.5% of nominal voltage and must be within permissible voltage values according to each voltage level prescribed in Article 6 herein.

2. If a voltage divider is operated manually, the voltage fluctuations at the points connected to loads are not allowed to exceed voltage value indicated by the transformer’s voltage divider.

3. Permissible adjustable voltage level is 5% of nominal voltage to a maximum provided that such adjustment shall not cause damage to the equipment on electricity transmission system and equipment belonging to customers using transmission grid.

Article 11. Neutral grounding

1. Neutral grounding of a transmission grid is the connection of the grid direct to the ground.

2. If the neutral grounding of some equipment in the transmission grid is in opposition to the provisions prescribed in Clause 1, this Article, a written consent of the electricity system and market operator is required.

Article 12. Short-circuit current and fault clearing time

1. Permissible maximum value of short-circuit current and fault clearing time by main protection on the electricity system are stipulated in Table 6 below:

Table 6

Permissible maximum value of short-circuit current and fault clearing time by main protection

2. For 110 kV busbars of 500 kV or 220 kV transformers in the transmission grid, permissible maximum short-circuit current is 40 kA/1s.

3. Total value of unsaturated sub transient reactance of a generating set (X_d^’’-%) and short-circuit reactance of a terminal transformer (U_k-%) according to the per-unit system pu is not allowed to be less than 40%.

If the aforesaid requirements cannot be met, the investor shall be responsible for installing further reactance so that total value of X_d^’’, U_k and electrical reactance according to the per-unit system is not less than 40%.

4. If value of short-circuit current at connection point of any electrical works to an electricity transmission system is greater than permissible maximum short-circuit as stipulated in Table 6, the investor shall take measures to restrict the short-circuit current at connection points to a level lower or equal to permissible maximum short-circuit current as stipulated in Table 6.

5. Main protection of an electrical equipment is a key element of protection which is installed and set to make initial impacts, ensuring quickness, sensitivity, selectivity and reliability of impacts of the protection system in case of a fault within the scope of protection.

6. If maximum short-circuit current exceeds the values as stipulated in Table 6, the transmission network operator or customers using transmission grid shall be responsible for reporting to the Electricity Regulatory Authority for instructions.

7. The transmission network operator shall be responsible for informing the customer using transmission grid about maximum value of short-circuit current at connection point for coordination during the investment and installation of equipment, ensuring that the switchgears are able to de-energize maximum short-circuit current at connection point at least for the next 10 years.

Article 13. Earth fault factor

Earth fault factor of a transmission grid at all voltage levels is not allowed to exceed 1.4.

Article 14. Reliability of transmission grid

1. Reliability of a transmission grid is determined by percentage of electrical production not supplied annually due to outage or reduction of power supply outside and inside the plan, and faults on the transmission grid causing loss of power to electricity customers.

2. Electrical production not supplied is calculated as the product of the load power suspended or reduced and the corresponding time of suspension, reduction in case the loss of power lasts over one minute, except for following cases:

a) Outage or reduction of power supply due to lack of power from national electricity system

b) Outage or reduction of power supply due to force majeure events.

3. Percentage of electrical production not supplied annually by a transmission grid is determined in following formula:

Where:

- k_kccd: Percentage of electrical production not supplied in a year by a transmission grid_;

- T_i: Time of outage or reduction of power supply lasting over one minute at time I is determined as the period from the time of outage or reduction to the time power supply is restored (hour);

- P_i: Average load power suspended, reduced at time i (kW);

- n: Number of times of outage or reduction of power supply in a year;

- A_tt: Total electrical production transmitted through a transmission grid in a year (kWh).

Article 15. Loss of power on transmission grid

1. Annual loss of power on a transmission grid is determined in following formula:

Where:

- ΔA: Annual loss of power on a transmission grid;

- A^tt_received: Total electrical production transmitted to the transmission grid in a year is the production received by all the customers using transmission grid at connection points plus total electrical production imported through the transmission grid;

- A^tt_delivered:Total electrical production delivered from the transmission grid in a year is the production the electricity distribution units and electricity customers receive from connection points plus total electrical production exported through the transmission grid;

Chapter III

LOAD FORECASTING FOR NATIONAL ELECTRICITY SYSTEM

Article 16. General provisions on load forecasting for national electricity system

1. Load forecasting for the national electricity system is forecasts on demand for loads to be supplied by the national electricity system except loads from independent power supplies and not connected to the national grid. Load forecasting for the national electricity system is grounds for making annual electricity transmission system development plans, plans and methods for operation of electricity system, electricity market.

2. Load forecasting for the national electricity system includes annual, monthly, weekly and daily forecasts on loads and electricity market transaction cycle.

3. Responsibility for making forecasts

a) The electricity system and market operator shall make forecasts on loads for the national electricity system, electricity systems in the Northern, Central and Southern Vietnam and connection points.

b) Electricity distribution units, electricity retailers and electricity customers shall provide load forecasts to the electricity system and market operator including forecasts on demand for loads of the entire unit and individual 110 kV transformers

c) Electricity wholesalers shall provide forecasts on exportation and importation of electricity to the electricity system and market operator including forecasts on general demand and demands of connection points serving exportation and importation of electricity.

4. Regarding forecasts on demand of connection points and resolution of load forecasting cycle and depending on each stage of development and market demand, the Electricity Regulatory Authority shall provide instructions on implementation of this regulation.

Article 17. Annual load forecasting

1. Annual load forecasting made for next year (year N+1) and the year thereafter (year N+2).

2. Figures serving annual load forecasting include:

a) Monthly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle for 104 weeks provided by electricity distribution units, electricity retailers and electricity customers;

b) Monthly export, import forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle for 104 weeks provided by electricity wholesalers.

3. Elements taken into account for annual load forecasting:

a) Economic growth (GDP) for the next two years officially published by competent agencies;

b) Annual load forecasts and load factor under approved electricity development master plan;

c) Statistical figures on capacity, electrical energy consumed, exported and imported at least for at the last five years by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers;

d) Solutions and targets of the plan for energy saving and demand management;

dd) Other necessary information.

4. Results of annual load forecasting for national electricity system include: Maximum capacity, electrical energy, typical daily diagrams in a 30-minute cycle for 104 weeks of national, regional electricity systems and connection points.

5. Implementation

a) Before August 01 annually, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide results of annual load forecasting to the electricity system and market operator as prescribed in Clause 2, this Article.

If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last year’s figures to make forecasts on loads for the national electricity system.

b) Before September 01 annually, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of annual load forecasting on its website as prescribed in Clause 4, this Article.

Article 18. Monthly load forecasting

1. Monthly load forecasting made for next month.

2. Figures serving monthly load forecasting include:

a) Weekly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle every week provided by electricity distribution units, electrical retailers and electricity customers;

b) Weekly export, import forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle every week provided by electricity wholesalers.

3. Elements taken into account for monthly load forecasting:

a) Results of monthly load forecasting in the published annual load forecasting;

b) Statistical figures on capacity, consumed, exported and imported electrical energy, maximum loads in daytime and nighttime for the month year-on-year and the last three months provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers;

c) Events that may cause major changes to demand for loads and other necessary information.

4. Results of monthly load forecasting for national electricity system include: Maximum capacity, electrical energy, typical daily diagrams for each week with a 30-minute cycle of national, regional electricity systems and connection points.

5. Implementation

a) Before 20^th every month, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide monthly load forecasts to the electricity system and market operator as prescribed in Clause 2, this Article.

If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last month’s figures or results of annual load forecasting to make forecasts on loads for national electricity system.

b) Before the last seven days every month, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of month loading forecasting on its website as prescribed in Clause 4, this Article.

Article 19. Weekly load forecasting

1. Weekly load forecasting made for the next two weeks.

2. The figures serving weekly load forecasting include figures on capacity, electrical energy forecasts in a 30-minute cycle every day of the next two weeks provided by electricity distribution units, electricity retailers and electricity customers and 110 kV transformers.

3. Elements taken into account for weekly load forecasting:

a) Results of weekly load forecasting in the published monthly load forecasting;

b) Statistical figures on capacity, consumed electrical energy, maximum loads in daytime and nighttime for the last four months provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers;

c) Daily weather forecasts for the next two weeks, public holidays, Tet holidays and events that may cause major changes to demand for loads.

4. Results of weekly load forecasting for national electricity system include: Capacity, electrical energy in a 30-minute cycle every day of the next two weeks of national, regional electricity systems and connection points.

5. Implementation

a) Before 10:00 every Tuesday, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide weekly load forecasts to the electricity system and market operator as prescribed in Clause 2, this Article.

If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last week’s figures or results of monthly load forecasting to make forecasts on loads for national electricity system.

b) Before 15:00 every Thursday, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of weekly load forecasting on its website as prescribed in Clause 4, this Article.

Article 20. Daily load forecasting

1. Daily load forecasting made for the next two days.

2. Elements taken into account for daily load forecasting:

a) Results of daily load forecasting in the published monthly load forecasting;

b) Figures on capacity, electrical energy of the electricity system of the last seven days or the holidays, Tet holidays of last year if the figures fall within public holidays, Tet holidays;

c) Weather forecasts of the next two days and other necessary information.

3. Results of daily load forecasting for national electricity system include: Capacity, electrical energy in a 30-minute cycle of national, regional electricity systems and connection points.

4. Before 10:00 every day, the electricity system and market operator shall be responsible for completing and publishing results of daily load forecasting as prescribed in Clause 3, this Article.

Article 21. Load forecasting in a electricity market transaction cycle

1. Load forecasting made for next transaction cycle and eight cycles thereafter.

2. Elements taken into account for load forecasting in a transaction cycle:

a) Results of load forecasting from the published daily load forecasting and the electricity market transaction cycle previously published;

b) Figures on capacity, electrical energy of the same period of last week;

c) Weather forecasts;

dd) Other necessary information.

3. Results of load forecasting in a electricity market transaction cycle include:

a) Capacity and production of the national electricity system and regional electricity systems in a 30-minute cycle of the next transaction cycle and eight cycles thereafter;

b) Capacity and production at each point connecting the transmission grid and distribution grid in a 30-minute cycle of the next transaction cycle and eight cycles thereafter.

4. At least 15 minutes before the next transaction cycle, the electricity system and market operator shall be responsible for completing and publishing results of load forecasting of a transaction cycle as prescribed in Clause 3, this Article.

Chapter IV

TRANSMISSION GRID DEVELOPMENT PLAN

Article 22. General principle

1. Annually, the transmission network operator shall be responsible for making a transmission grid development plan for next year (year N+1) with account taken of the year thereafter (year N+2).

2. Annual transmission grid development plans shall be made based on:

a) Published annual load forecasting plans;

b) Approved national electricity development plans, provincial electricity development planning and signed connection agreements;

c) Requirements for operation of the electricity system prescribed in Chapter II and technical requirements of connection points prescribed in Chapter V herein;

d) Demand for loads and requirements for electricity system and market operation; ensuring the national electricity transmission system operates in a safe, reliable and stable manner.

3. The electricity system and market operator shall be responsible for cooperating with the transmission network operator during the process of transmission grid development plan formulation to ensure investment, connection and operation of the power generation and electrical grid works meet the requirements prescribed in Clause 2, this Article.

Article 23. Content of transmission grid development plan

The transmission grid development plan includes following subject matters:

1. Assessment of performance of the transmission grid to the end of June 30 of the current year.

2. Load forecasts in each point of delivery between the transmission grid and distribution grid for the next year with account taken of the year thereafter.

3. Assessment of implementation of investment and estimated implementation of investment in the list of transmission grids according to the approved transmission grid development plan until the end of December 31 of current year.

4. List of power generation projects connecting to the transmission grid for next year with account taken of the year thereafter accompanied by planned connection points, connection agreements for these power generation projects.

5. List of information system works, SCADA system, RTU/Gateway, measurement system, data collection system serving electricity market and electricity system operation and dispatching.

6. Results of calculation of reset modes of the electricity transmission system for each month next year, dry and rainy seasons of the year thereafter including results of calculation of methods and assessment of ability of the transmission grid to meet N-1 criterion.

7. Results of calculation of short-circuit current at 500 kV, 220 kV, 110 kV busbars on the transmission grid in which the positions where maximum value of short-circuit current exceed 90% of permissible maximum value as prescribed in Article 12 herein must be determined.

8. Results of calculation and analysis of stability of the electricity transmission system.

9. Results of calculation of reactive power compensation on the transmission grid.

10. Determination of obligations and constraints on the transmission grid that may have effect on safe and stable operation of the electricity transmission system including effects on requirements for stability of the electricity system as prescribed in Article 5 herein.

11. Proposals for norms of reliability and loss of power of the transmission grid for the next year according to Article 14 and Article 15 herein.

12. Analysis of ability to meet operational requirements of the electricity system prescribed in Chapter II and technical requirements of connection points prescribed in Chapter V herein, and proposals for solutions to meet the prescribed requirements.

13. Analysis and selection of methods of investment in the transmission grid to ensure transmission of all the power from power plants meeting demand for loads, technical requirements and lowest costs.

14. Lists and schedules of construction of transmission grid items by month of next year and by quarter of the year thereafter. Fund plan for each project.

15. Proposals (if any).

Article 24. Responsibility for supplying information serving formulation of transmission grid development plan

1. Generating units shall be responsible for supplying following information:

a) Lists of new power plants planned to be connected to the transmission grid in the next year with account taken of two years thereafter, progress of investment and connection, and expected date of operation of such power plants.

b) Main parameters of power plants shall be connected to the electricity transmission system and information about connection points are stipulated in Annex 1B enclosed herewith;

c) Changes related to connection to existing power plants in the next year with account taken of two years thereafter.

2. Electricity distribution units, electricity retailers and electricity customers shall be responsible for providing following information:

a) Lists of connection points in the next year with account taken of the year thereafter; lists of transmission grid projects to be invested and constructed;

b) Planned progress of energizing new connection points;

c) Maximum load capacity at new connection points and information about connection are specified in Annex 1C enclosed herewith;

d) Expected proposals for changes to existing connection points in the next year with account taken of the year thereafter.

3. The electricity system and market operator shall be responsible for providing following information:

a) Results of annual load forecasting as prescribed in Article 17 herein;

b) Expected demand for ancillary services in next year with account taken of the year thereafter;

c) Plan for mobilization of power supplies in the next year with account taken of the year thereafter.

4. Electricity wholesalers shall be responsible for supplying following information:

a) Exported, imported capacity and electrical energy;

b) Progress of putting new power generation projects into operation in the next year with account take of two years thereafter.

Article 25. Procedures for formulation, approval and public announcement of transmission grid development plans

1. Before August 01 annually, the transmission network operator shall be responsible for delivering requests for supply of information and time limit of supply of information to the electricity market and system operator, electricity wholesalers and customers using transmission grid (including customers who need to establish new connections).

2. Before September 01 annually, the electricity system and market operator, electricity wholesalers and customers using transmission grid shall be responsible for providing sufficient information as prescribed in Article 24 herein to the transmission network operator.

3. Before October 15 annually, the transmission network operator shall be responsible for completing draft plans for transmission grid development in the next year with account taken of the year thereafter, and submitting requests to the electricity system and market operator for suggestions on assessment of impacts of expected transmission grid projects on safety, stability and reliability of the electricity transmission system.

4. Before November 01 annually, the transmission network operator shall be responsible for completing the plan for transmission grid development in the next year with account taken of the year thereafter and reporting to Vietnam Electricity.

5. Before November 15 annually, the transmission network operator shall be responsible for submitting the plan for transmission grid development in the next year with account taken of the year thereafter approved by Vietnam Electricity  to Electricity Regulatory Authority.

6. Before December 15 annually, the Electricity Regulatory Authority shall conduct assessment, grant approval and publish on its website the plan for transmission grid development in the next year with account taken of the year thereafter.

7. Within 15 working days since the plan for transmission grid development is approved by Electricity Regulatory Authority, the transmission network operator shall be responsible for publishing the plan on its website.

Chapter V

CONNECTION TO TRANSMISSION GRID

Section 1. GENERAL PRINCIPLE

Article 26. Connection point

1. Connection points are the points connecting equipment, electrical grids and power plants of customers using transmission grid with the electricity transmission system.

2. Depending on structure of the electrical grids and connection lines, connection points shall be determined as follows:

a) Regarding overhead lines, connection points are the end points of the suspension string for outgoing feeders connected to the disconnect switches of the substation or distribution area of the power plant.

b) Regarding underground lines, connection points are the cosse of disconnector insulators on the outgoing side of the substation or distribution area of the power plant.

3. Any connection point which is in opposition to provisions prescribed in Clause 2, this Article shall be agreed by the two parties.

4. Connection points must be detailed in relevant drawings, diagrams and explanations in the connection agreement or power purchase agreement (PPA).

Article 27. Borders of assets and operation management

1. Borders of assets between the transmission network operator and customers using transmission grid are connection points.

2. Assets belonging to each party at connection point must be detailed and accompanied by relevant drawings and diagrams or power purchase agreement (PPA).

3. Each party shall be responsible for investing, constructing and managing assets of its own in accordance with standards and laws unless otherwise agreed.

Article 28. General requirements

1. The transmission network operator shall be responsible for developing transmission grids according to approved electricity development planning and investment plan, ensuring transmission grid facilities meet requirements of the electricity system as prescribed in Chapter II herein and technical requirements of connection points prescribed in this Chapter.

2. Connecting electrical equipment, electrical grids and power plants of customers using transmission grid with the transmission grid must be consistent with the electricity development planning approved by competent state agencies, ensuring transmission grid facilities meet requirements of the electricity system as prescribed in Chapter II herein and technical requirements of connection points prescribed in this Chapter.

3. The transmission network operator shall be responsible for making notification to the electricity customer of any connection proposed by such customer which is in opposition to the approved electricity development planning. Any customer who needs to get connected shall be responsible for submitting an application for grant of approval for adjustments and supplements to the planning according to the regulation on contents and procedures for formulation, assessment, approval and adjustment of electricity development planning issued by the Ministry of Industry and Trade before taking next steps.

4. The transmission network operator and customer that request connection must execute a connection agreement according to the form prescribed herein including following information:

a) Position of connection point;

b) Technical information related to connection point;

c) Progress of connection;

d) Responsibility for investment and operation management;

dd) Terms and conditions of the connection agreement.

5. The transmission network operator is entitled to reject proposals for connection in following cases:

a) Customer’s electrical equipment, grids fail to meet operational and technical requirements prescribed herein and other relevant technical regulations;

b) Proposals for connection are inconsistent with the approved electricity development planning.

6. The transmission network operator is entitled to disconnect the customer from its transmission grid if such customer violates technical and operational requirements as prescribed herein or violates the regulation on safety and operation of its assets. The procedures for settlement of dispute prescribed in Chapter IX herein shall apply if the two parties fail to reach an agreement on the disconnection.

7. If any change or upgrading of equipment or change of connection diagram by the customer using transmission grid within its scope of management affects safe operation of the electricity transmission system or electrical equipment belonging to the transmission network operator at connection point, such customer must make a written notification to the transmission network operator and the dispatch level before implementation.

8. Any change related to connection point during the investment and operation must be updated in the dossier of connection point and signed connection agreement.

9. The customer using transmission grid shall be responsible for storing figures concerning working modes, operation and maintenance and incidents on the components within its management for a period of five years. As requested by the transmission network operator, the customer shall provide adequate information related to the incident on the components within its management. For any connection serving purchase and sale of electricity between power plants overseas or outside the territory of Vietnam and the national electricity system, the technical and operational requirements of the equipment connecting to the transmission grid shall be in order of priority as follows:

a) Be conformable with regulations, international agreements and commitments of which Vietnam is a signatory;

b) An agreement between relevant parties must be reached to meet all the technical requirements and technical regulations on each country’s electricity system and ensure that the operation of the electrical grids is safe, reliable and stable.

Section 2. GENERAL TECHNICAL REQUIREMENTS FOR EQUIPMENT CONNECTING TO TRANSMISSION GRID

Article 29. Requirements for connecting equipment

1. The diagram of main connection point shall represent all the electrical equipment from middle-voltage to super high-voltage levels and connectivity between the electrical grid of the customer using transmission grid and the transmission grid. The electrical equipment must be described in symbols, standard signs and numbered by the dispatch level according to the operating procedure of the national electricity system issued by the Ministry of Industry and Trade.

2. Circuit breakers directly related to connection points accompanied by protection, measurement and control systems must be capable of de-energizing maximum short-circuit current at connection point, meeting the electrical grid and power generation development diagram under the approved electricity development planning at least for the next 10 years.

3. Equipment connecting directly to the transmission grid shall be fully capable of withstanding possible maximum short-circuit current at connection points according to the calculations by the transmission network operator, meeting the electrical grid and power generation development diagram under the approved electricity development planning at least for the next 10 years.

Article 30. Requirements for protective relay system

1. The transmission network operator and the customer using transmission grid shall be responsible for designing, installing, setting and testing the protective relay system within their own management to meet requirements for quickness, sensitivity, selectivity and reliability in case of fault clearance to ensure safe and reliable operation of the electricity system.

2. Coordination in installing protective relay equipment at connection points must be agreed between the dispatch level, the transmission network operator and the customer using transmission grid. The transmission network operator or the customer using transmission grid shall not be allowed to change its own protective relay equipment and installation parameters without consent of the dispatch level.

3. The dispatch level shall be responsible for issuing relay setting notes within scope of transmission grid belonging to the transmission network operator and granting approval for the relay settings of the protective relay equipment belonging to the customer using transmission grid.

4. Maximum time limit for fault clearance through main protection on the components of the electricity system belonging to the customer using transmission grid is not allowed to exceed the values prescribed in Article 12 herein.

5. If the protection equipment belonging to the customer is required to connect to the transmission network operator’s protection equipment, such equipment must meet requirements of the transmission network operator for connection and be approved by the dispatch level.

6. If the electrical grid belonging to the customer using transmission grid has a problem, the protective relay equipment in the electrical grid may send commands to disconnect circuit breakers on the transmission grid with consent of the transmission network operator and the dispatch level with regard to these circuit breakers.

7. Reliability of impacts of the protective relay system shall not be less than 99%.

8. In addition to requirements prescribed from Clause 1 to Clause 7, this Article, the protective relay system belonging to the customer using transmission grid and the transmission network operator must meet following requirements:

a) Power plants must be equipped with synchronization system;

b) Power plants must be equipped with a GPS.

c) Power plants with total installed capacity from 300 MW and on must be equipped with a phasor measurement unit (PMU) and a GPS. Power plants with total installed capacity less than 300 MW, equipment of PMU must follow calculations and requirements of the electricity system and market operator;

d) The transmission network operator and customer using transmission grid other than generating units shall be responsible for installing a GPS, PMU according to requirements of the dispatch level, ensuring compatible, reliable and stable connection to the GPS and PMU located at the electricity system and market operator. The dispatch level shall be responsible for integrating the GPS and PMU of the transmission network operator and customer using transmission grid to the system located at the dispatch level;

dd) During operation, in case of upgrading or changing the GPS and PMU, the transmission network operator and customer using transmission grid shall be responsible for making notifications and entering negotiations with the dispatch level before implementation;

e) The transmission lines from 220 kV and over connecting to generating sets or distribution area of the power plant must be equipped with two independent communication channels serving transmission of signals of protective relay between two ends of lines (transmission time no more than 20 ms);

g) Electricity customers shall be responsible for investing and installing low-frequency relays within scope of automatic load shedding management according to calculations and requirements of the dispatch level.

9. Scope, positioning and technical requirements of protective relay equipment for generating sets, transformers, busbars and lines connecting to the transmission grid shall be conformable with the regulation on technical requirements of protective relay and automation system in the power plant and transformer issued by Electricity Regulatory Authority.

Article 31. Requirements for information system

1. The customer using transmission grid shall be responsible for investing, installing and managing the information system and ensuring it is connected to the information system belonging to the transmission network operator and the dispatch level. Means of communications serving dispatching and operation include direct communication channel, telephone and facsimile.

2. The information system belonging to the customer using electrical grid must be compatible with that of the transmission network operator and the dispatch level.

The customer may negotiate an agreement for use of information system of the transmission network operator or other suppliers to connect to the information system of the dispatch level to ensure continuous and reliable communication serving electricity system and market operation.

3. The transmission network operator shall be responsible for investing and managing the information system of its own to serve electricity system and market operation; cooperating with the dispatch level in establishing a information transmission line to the dispatch level.

4. The dispatch level shall be responsible for providing requirements for information data, data transmission and necessary information interface serving electricity system and market operation to the transmission network operator and customer using transmission grid.

5. The dispatch level and the transmission network operator shall be responsible for cooperating with the customer using transmission grid in testing, inspecting and connecting the customer’s information system to the existing information system managed by the units.

Article 32. Requirements for connection of SCADA system

1. Transformers from 220 kV and on, power plants with installed capacity greater than 30 MW and power plants connected to the transmission grid which is not yet connected to the Control Center must be equipped with a Gateway or RTU with two ports connecting directly, simultaneously and independently to the SCADA system of the dispatch level.

2. Power plants with installed capacity greater than 30 MW and power plants connecting to the transmission grid which is connected to the Control Center must be equipped with a Gateway or RTU with one port connecting directly to the SCADA system of the dispatch level and two ports connecting directly to the Control Center. Transformers from 220 kV and on which is connected to the Control Center must be equipped with a Gateway or RTU with two ports connecting directly to the Control Center.

3. If a power plant, transformer has multiple dispatching levels with control authority, such dispatching levels shall be responsible for sharing information to serve electricity system operation coordination.

4. The transmission network operator and customer using transmission grid shall be responsible for investing, installing and operating the RTU/Gateway within management or hiring the data transmission lines from service providers to ensure continuous and reliable connection to the SCADA system of the dispatch level and the Control Center.

5. Technical characteristics of RTU/Gateway belonging to the transmission network operator and customer using transmission grid must be compatible with the SCADA system of the dispatch level and the Control Center (if any).

6. The dispatch level shall be responsible for integrating data according to the list of data agreed with the transmission network operator and customer using transmission grid to its SCADA system. The transmission network operator and customer using transmission grid shall be responsible for cooperating with the dispatch level in configuring and setting database on its system to ensure compatibility with the SCADA system of the dispatch level and control system of the Control Center (if any).

7. If the SCADA system of the dispatch level has had some technological changes approved by competent agencies after the connection agreement is signed resulting in changes or upgrading of the control system, RTU/Gateway of the transmission network operator and customer using transmission grid, the dispatch level, the transmission network operator and customer shall be responsible for making necessary adjustments to ensure that the equipment belonging to the transmission network operator and customer using transmission grid is compatible with changes of the SCADA system. The transmission network operator and customer using transmission grid shall be responsible for investing and upgrading the control system and RTU/Gateway to ensure compatibility with the SCADA system of the dispatch level.

8. During operation, in case of upgrading or expansion of the control system, RTU/Gateway, the transmission network operator and customer using transmission grid shall be responsible for entering negotiations with the dispatch level before the upgrading or expansion is carried out.

9. Requirements on lists of data, technical requirements of RTU/Gateway are detailed in the regulation on technical requirements and SCADA system operation management issued by the Electricity Regulatory Authority.

Article 33. Neutral grounding in transformers

Neutral grounding in transformers must ensure value of earth fault factor does not exceed the value prescribed in Article 13 herein.

Article 34. Power factor

1. In normal operation mode, electricity distribution units and electricity customers must maintain a power factor (cosφ) at key measuring positions from 0.9 and over in case of receiving reactive power and from 0.98 and on in case of transmitting reactive power.

2. The customer using transmission grid must provide parameters of reactive power compensation equipment in its electrical grid (if any) to the transmission network operator and the dispatch level, including:

a) Rated reactive power and adjustment range;

b) Principle of reactive power adjustment.

Article 35. Load fluctuation

The speed of changing power consumption by electricity customers in a minute is not allowed to exceed 10% of power consumption in normal operation mode unless the electricity customer adjusts demand as requested or under an agreement with the electricity system and market operator.

Article 36. Automatic frequency load shedding system

1. The customer using transmission grid shall be responsible for cooperating with relevant units in unifying the installation of the automatic frequency load shedding system and ensuring that it operates in accordance with calculations and requirements of the dispatch level.

2. The system must be designed to meet following requirements:

a) Reliability not less than 99%;

b) Any unsuccessful load shedding must not affect operation of the entire electricity system.

c) Load shedding procedures and amount of shed power must be in compliance with level of distribution by the dispatch level and must not be changed in any case without consent of the dispatch level.

3. Low-frequency relays must be installed and put into operation at the request of the dispatch level.

4. Load recovery procedures after frequency is restored to normal operation mode must be in compliance with dispatch instruction of the dispatch level.

Article 37. Requirements of Control Center

1. General technical requirements

a) Monitoring, control and information systems installed in the Control Center must be equipped to ensure safe and reliable operation of power plants, substations;

b) The Control Center’s monitoring and control systems must be technically compatible and ensure stable, reliable and continuous connection of power plants, substations and switchgears to SCADA system of the dispatch level;

c) The Control Center must have a backup power supply to ensure normal operation in case of loss of power from the national electricity system.

2. Requests for connection from Control Center

- There are two independent data transmission lines to be connected to the information system of the dispatch level. If multiple dispatching levels with control authority exist, an information sharing method must be agreed by all the dispatching levels;

- There are two data transmission lines to be connected to the control and information system of power plants, substations remotely controlled by the Control Center;

- Means of communications serving dispatching and operation include direct communication channel, telephone, facsimile and computer network.

b) Requirements for connection to SCADA system

- There are two ports connecting directly, simultaneously and independently to SCADA system of the dispatch level. If multiple dispatching levels with control authority exist, a common information sharing method must be agreed by all the dispatching levels;

- There are ports connecting to RTU/Gateway, control system of power plants, substations and switchgears on the electrical grid remotely controlled by the Control Center.

c) The Control Center must install a monitoring screen connected to the surveillance camera at power plants, substations and switchgears on the electrical grid.

3. Power plants, substations or switchgears on the electrical grid remotely controlled by the Control Center must be equipped with a control and surveillance camera system to establish stable, reliable and continuous connection to the Control Center meeting requirements prescribed in Clause 1 and Clause 2, this Article.

Section 3. TECHNICAL REQUIREMENTS FOR CONNECTION TO HYDRO POWER PLANTS AND THERMO POWER PLANTS

Article 38. Requirements for generating sets’ power control

1. Power plants with installed capacity over 30 MW must be equipped with facilities, control systems , AGC system to ensure stable and reliable connection to a generating set’s power control system of the electricity system and market operator serving remote control of the generating set’s power according to dispatch instruction of the electricity system and market operator. Particular technical requirements for connection of the generating set's AGC system to SCADA/EMS of the electricity system and market operator are prescribed in the regulation on technical and operation requirements of SCADA system issued by the Electricity Regulatory Authority.

2. The generating set of a power plant must be capable of generating rated active power in a power factor from 0.85 (corresponding to reactive power generation mode) to 0.9 (corresponding to reactive power receiving mode) in accordance with characteristics of the generating set’s reactive power.

3. The generating set must be capable of adjusting primary and secondary frequency as prescribed in the national load dispatch process issued by the Ministry of Industry and Trade and controlling voltage in the electricity system through continuous adjustment of active power and reactive power of the generating set.

4. In normal operation mode, voltage changes at connection point to transmission grid within permissible scope prescribed in Article 6 herein must not affect amount of active power generated and reactive power generation capability of the generating set.

5. The generating set of a power plant must be capable of generating rated active power continuously within frequency band 49 Hz – 51 Hz. In a frequency band from 46 Hz to under 49 Hz and over 51 Hz, level of power reduction must not exceed value according to frequency reduction ratio of the electricity system. Minimum time to maintain operation of power plants with installed capacity over 30 MW or power plants connected to the transmission grid in proportion to frequency bands of the electricity system is specified in Table 7 below:

Table 7

Minimum time to maintain power generation in proportion to frequency band of the electricity system

6. Generating sets of a power plant must be capable of withstanding level of voltage symmetry loss in the electricity system as prescribed in Article7 herein.

7. Generating sets of a power plant must be capable of working continuously in following modes:

a) Unbalanced three-phase loads from 10% and under;

b) Indicator of response of the exciter in a synchronous generating set greater than 0.5%;

c) Negative sequence current is 5% less than rated current.

Article 39. Excitation system of a generating set

1. The excitation system of a generating must ensure that the generating set can operate in a power factor range prescribed in Clause 2, Article 38 herein. The excitation system must ensure the generating set operates at a rated apparent power (MVA) within the range ± 5 % of rated voltage at the generating set’s terminal posts.

2. The generating set must be equipped with AVR which operates continuously and is capable of maintaining deviation of terminal voltage within ± 0,5 % of rated voltage in the entire permissible working band of the generating set.

3. AVR must be capable of making up for voltage drop on terminal transformers and ensure stable distribution of reactive power among generating sets connected to a common busbar.

4. AVR must be installed with following limits:

a) Minimum excitation current;

b) Maximum excitation current.

5. When terminal voltage of a generating set is in a range from 80 to 120% of rated voltage and the system frequency is in a range from 47.5 to 52Hz in a maximum of 0.1 second, the excitation system of the generating set must be capable of increasing the current and excitation voltage to following values:

a) For a generating set of a hydro power plant: 1.8 rated value;

a) For a generating set of a thermo power plant: 2.0 rated value;

6. Change of excitation voltage is not allowed to be less than 2.0 rated excitation voltage/second when a generating set carries the rated load.

7. A generating set with a capacity over 30 MW must be equipped with a PSS capable of dampening 0.1 Hz – 5 Hz frequency fluctuation contributing to improvement of the electrical system. Generating units must install and set parameters of the PSS according to calculations by the electricity system and market operator to ensure dampening ratio of the PSS is not smaller than 5%. For generating sets equipped with PSS, the generating units shall be responsible for putting the PSS into operation at the request of the dispatch level.

Article 40. Governor

1. Generating sets of a power plant in operation must engage in adjusting primary frequency in the national electricity system.

2. Generating sets of a power plant must be equipped with a governor capable of responding to changes of system frequency in normal operation conditions. The governor must be capable of performing commands from SCADA/EMS system of the electricity system and market operator unless it is not required.

3. The governor must be capable of setting value of static coefficient less than or equal to 5%. Set value of static coefficient shall be determined by the electricity system and market operator.

4. Apart from add-on generating sets of combined cycle power plants, minimum value of a dead-band in the governor must range within ± 0,05 Hz. Value of dead-band of the governor of each generating set shall be calculated and determined by the electricity system and market operator during connection and operation.

5. The governor control system must be installed with following limits and anti-over speed control as follows:

a) For steam turbines: From 104% to 112% of rated speed;

b) For gas and thermo power turbines: From 104% to 130% of rated speed;

c) If the generating set in the grid area is temporarily disconnected from the national electricity transmission system but keeps supplying power to customers, the governor system of the generating set must maintain frequency stability for such grid area.

Article 41. Black start

1. In some important positions in electricity transmission system, some power plants must be capable of black starting. Requirements for installation of black start capability must be stated in the connection agreement.

2. The electricity system and market operator shall be responsible for determining important positions in the national electricity system for the construction of power plants capable of black start and cooperate with the transmission network operator, generating units in determining specific requirements for black start of individual power plants.

Section 4. TECHNICAL REQUIREMENTS OF WIND AND SOLAR POWER PLANTS

Article 42. Technical requirements of wind and solar power plants

1. Wind and solar power plants must be capable of maintaining generation of active power within frequency band from 49 to 51 Hz in following modes:

a) Free generation mode

b) Generating capacity control mode

Wind and solar power plants must be capable of adjusting generation of active power as commanded by the dispatch level in accordance with change of primary sources no more than 30 seconds with tolerance within ± 01 % of rated power, specifically as follows:

- Generation of power in accordance with dispatch instruction in case primary sources are equal or greater than forecast value;

- Generation of possible maximum power in case primary sources are lower than forecast value.

2. In normal operation mode, wind and solar power plants must be capable of generating active power and ensure no negative effect is caused by change of voltage at connection point within permissible band prescribed in Article 6 herein.

3. Wind and solar power plants must be capable of maintaining generation of power for a minimum period of time in proportion to frequency band prescribed in Table 8 below:

Table 8

Minimum time to maintain power generation in proportion to frequency band of electricity system

4. When the electricity system’s frequency is greater than 51 Hz, wind and solar power plants must reduce active power at a speed no less than 01% of rated power. Level of power reduction in proportion to frequency is determined as follows:

Where:

- ΔP: Level of active power reduction (MW);

- P_m: Active power in proportion to the point of time prior to power reduction (MW);

- f_n: Electricity system frequency prior to power reduction (Hz).

5. Wind and solar power plants must be capable of adjusting reactive power and voltage as follows:

a) If a power plant generates an active power greater or equal to 20% of rated active power and voltage in normal operation band, such power plant must be capable of adjusting reactive power continuously in a power factor from 0.85 (corresponding to reactive power generation mode) to 0.95 (corresponding to reactive power receiving mode) at connection point in proportion to rate power;

b) If a power plant generates an active power less than 20% of rated power, such power plant may reduce ability to receive or generate reactive power in accordance with characteristics of the generating set;

c) If voltage at connection point is within ± 10 % of rated voltage, the power plant must be capable of adjusting voltage at connection point with deviation no more than ± 0,5 % of rated voltage in permissible working band of the generating set;

d) If voltage at connection point varies beyond ± 10 % of rated voltage, the power plant must be capable of adjusting reactive power to the minimum of 2% compared with rated reactive power in proportion to each per cent of voltage varying at connection point.

6. Wind and solar power plants at every time of connection to the grid must be capable of maintaining generation of power in proportion to voltage range as follows:

a) Voltage less than 0.3 pu, minimum time is 0.15 seconds;

b) Voltage from 0.3 pu to under 0.9 pu, minimum time is calculated in following formula:

T_min = 4 x U – 0.6

Where:

- T_min (second): Minimum time to maintain power generation:

- U (pu): Actual voltage at connection point (pu).

c) Voltage from 0.9 pu to under 1.1 pu, wind and solar power plants must maintain continuous generation;

d) Voltage from 1.1 pu to under 1.15 pu, wind and solar power plants must maintain generation for three seconds;

dd) Voltage from 1.15 pu to under 1.15 pu, wind and solar power plants must maintain generation for 0.5 seconds;

7. Wind and solar power plants must ensure not to cause negative phase sequence component in excess of 01% of rated voltage. Wind and solar power plants must be capable of withstanding negative phase sequence components up to 03% of rated voltage for voltage from 220 kV and on.

8. Total harmonic distortion caused by wind, solar power plants at connection point is not allowed to exceed 03%.

9. Flicker perceptibility caused by wind and solar power plants at connection point is not allowed to exceed the value prescribed in Article 9 herein.

Section 5. PROCEDURES FOR CONNECTION AGREEMENT

Article 43. Procedures

1. When establishing or changing connection, customers must submit an application for connection to the transmission network operator.

2. Application includes:

a) A written request for connection accompanied by information according to the form in Annexes 1A, 1A 1B, 1C enclosed herewith;

b) Technical documents concerning equipment expected for connection or possible changes at existing connection points;

c) Expected time for project completion, economic – technical figures of new connection or connection change projects.

3. After receiving the application, the transmission network operator shall:

a) Review requirements concerning the equipment expected for connection;

b) Preside over assessment of effects of connection of equipment, electrical grid, power plants of customers on transmission grid including following subject matters:

- Calculate reset modes of regional electrical grids under requests for connection in the next 10 years including calculation of all alternatives and assess ability of regional transmission grid to meet N-1 criterion;

- Calculate and assess short-circuit current at connection points to the transmission grid;

- Determine obligations and constraints from new connections that may have effects on safe and stable operation of electricity transmission system;

- Assess ability to meet requirements for operation of the electricity system prescribed in Chapter II herein and technical requirements of connection points prescribed in this Chapter;

c) Prepare a draft connection agreement according to the form in Annex 2 enclosed herewith and submit it to customers who need to get connected and the dispatch level;

d) After 15 working days at the latest since receipt of the application for connection from customers, the transmission network operator shall submit a written request to the dispatching with control authority and relevant units for official suggestions as follows:

- Assessment of impacts of connection on the electricity transmission system;

- Technical requirements of equipment at connection points, requirements of operation and dispatching of generating sets, requirements of frequency load shedding system of electricity customers to ensure compliance with technical and operation requirements prescribed in Chapter II and Chapter V herein;

- Draft connection agreement in accordance with provisions prescribed in annexes enclosed herewith.

4. The dispatch level shall be responsible for cooperating with the transmission network operator in assessing effects of connection on the electricity transmission system as prescribed in Point b, Clause 3, this Article.

5. Customers who need to get connected shall be responsible for providing other necessary information to the transmission network operator and the dispatch level for determination of technical characteristics and other technical requirements to ensure safe, reliable and stable operation of the electricity transmission system.

6. Within 20 working days since receipt of request from the transmission network operator, the dispatch level and relevant units shall be responsible for delivering suggestions in writing on issues prescribed in Point d, Clause 3 and Clause 4, this Article to the transmission network operator.

7. Upon receipt of suggestions from the dispatch level and other relevant units, the transmission network operator shall be responsible for completing the draft connection agreement.

8. The connection agreement shall be made into four copies. Each party keeps two copies. The transmission network operator shall submit a copy to the dispatch level, relevant units for cooperation during construction, energizing and official operation.

9. Time for review of the application, negotiation on relevant issues and execution of the connection agreement is prescribed in Article 44 herein.

10. A customer who needs to get connected to the electrical grid or equipment of the customer using transmission grid shall be responsible for making direct negotiation with this customer. Before reaching an agreement for connection plan with the customer who needs to get connected, the customer using transmission grid shall be responsible for cooperating with the transmission network operator and the dispatch level in ensuring that the equipment of the customer meets technical requirements of the equipment at connection points prescribed herein. The customer using transmission grid shall be responsible for updating connection-related issues to the connection agreement signed with the transmission network operator.

11. In case of connection to 110 kV or medium-voltage busbars belonging to transformers 500 kV or 220 kV within management by the transmission network operator, the procedures for execution of the connection agreement are prescribed in Clauses 1 to 9, this Article.

Article 44. Time limit for execution of connection agreement

Time limit for negotiation and signing of the connection agreement is prescribed in Table 9 below:

Table 9

Time limit for review and signing of connection agreement

Section 6. IMPLEMENTATION OF CONNECTION AGREEMENT

Article 45. Rights to get access to equipment at connection points

The transmission network operator and customers who need to get connected shall have the rights to get access to the equipment at connection points during survey process to make plans for connection, construction, installation, testing, replacement, removal, operation and maintenance of connection equipment.

Article 46. Dossier for inspection of energizing conditions

1. Dossier serving general inspection of energizing conditions (technical documents confirmed by customers who need to get connected and certified copy of legal documents) includes:

a) Written records of inspection of individual parts and whole of connection equipment, transmission lines and transformers (according to technical standards of Vietnam or international standards applicable in Vietnam and technical requirements of connection equipment prescribed in this Chapter);

b) Approved technical documents, amendments and supplements (if any) to initial design including following documents:

- General explanation, electrical equipment layout;

- Schematic diagrams of protective relay, automation and control system that represents circuit breakers, current transformers, voltage transformers, lightning arrestor, disconnect switches …;

- Secondary diagrams of protective relay, automation and control system;

- Diagrams detailing connection to the transmission grid and parameters of transmission lines;

- Other relevant diagrams (if any).

c) Documents concerning technical parameters and operation management including:

- Technical parameters of equipment including parameters of transmission lines;

- Documents concerning primary energy system, excitation systems, governors, simulation modeling, PSS, Laplace transform diagram together with other installation values (for construction of new power plants);

- Instruction manuals for setting of protective relays, automation, specialized software;

- Instruction manuals for equipment operation and other technical documents.

d) Calculations and proposals for trial operation, energizing and putting the plant into operation.

2. Unless otherwise as agreed, customers who need to get connected shall be responsible for providing all the documents prescribed in Clause 1, this Article to the dispatch level and the transmission network operator serving energizing as follows:

a) At least three months prior to date of initial trial operation of the power plant;

a) At least three months prior to the date of initial trial operation of the power plant;

3. The dispatch level shall be responsible for making plans for energizing and putting the power plant into operation, ensuring safety and reliability of the equipment of the national electricity system. Customers who need to get connected shall be responsible for cooperating with the dispatch level in formulating methods of energizing the power plant.

4. Within 20 working days since receipt of the documents, the dispatch level shall be responsible for delivering following documents to the customer:

a) Equipment numbering diagram;

b) Requirements for methods of receiving dispatch instruction;

c) Settings of protective relays of the customer from connection points; protective relay settings note within transmission grid and other settings related to protective relays of the customer;

d) Agreed energizing method;

dd) Requirements for testing and calibration of equipment;

e) Requirements for establishment of communication system serving dispatching;

g) Requirements for connection and operation of SCADA, monitoring equipment, PMU and PSS;

h) Requirements for installation of information technology system and other necessary infrastructure serving electricity market operation;

i) Procedures related to electricity system and market operation;

k) Lists of relevant officials and dispatchers accompanied by phone and facsimile numbers.

5. Within 20 working days prior to the date connection points are energized, customers who need to get connected must reach an agreement with the dispatch level for trial operation schedules, methods of energizing and putting electrical equipment into operation.

6. Within 15 working days prior to the energizing day, customers who need to get connected must provide followings to the transmission network operator:

a) Trial operation schedules, methods of energizing and putting the electrical equipment into operation agreed with the dispatch level;

b) Agreement for assignment of responsibility of relevant parties for management and operation of connection equipment;

c) Internal regulation on safe operation of connection equipment;

d) Lists of qualified operators as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade including full name, professional title, responsibility, phone number.

7. Within 15 working days prior to the date connection points are energized, customers who need to get connected must provide information as prescribed in Points b, c, d, Clause 6, this Article and information as prescribed in Point a, Clause 6, this Article to the dispatch level and electricity wholesalers respectively.

Article 47. Inspection of conditions for energizing connection points

1. Within five working days prior to the date connection points are expected to energized, customers who need to get connected shall be responsible for negotiating with the transmission network operator on the date for physical inspection of connection points.

2. The transmission network operator shall be responsible for presiding over and cooperating with relevant units in negotiating with the customer on procedures for inspection of dossier, written record of inspection and installation of equipment at connection points.

3. If connection points or electrical equipment of the customer fail to meet conditions for energizing as notified by the transmission network operator, the customer must carry out adjustment, supplement or replacement as requested and re-negotiate with the transmission network operator on the time for next inspection.

4. If the dispatch level provides warnings about negative impacts of energizing on safe, reliable and stable operation of the electricity transmission system or equipment of the customer, the customer must cooperate with the dispatch level and the transmission network operator in re-inspecting matters related to the warnings and reaching an agreement for settlement method and re-negotiating with the transmission network operator on the time for next inspection.

5. If the customer detects possible effects of energizing on safe and reliable operation of its equipment, the customer shall make proposals to relevant units for handling and re-negotiating with the transmission network operator on the time for next inspection.

6. The transmission network operator, customers who need to get connected and relevant units shall be responsible for signing the written record of inspection of conditions for energizing connection points (hereinafter referred to as “the written record of inspection”).

Article 48. Energizing connection points

1. After the written record of inspection is signed, customers who need to get connected shall be responsible for delivering an application for energizing accompanied by following documents to the dispatch level:

a) Written confirmations of fulfillment of legal and technical procedures:

- Equipment within the scope of energizing that meet operational and technical requirements at connection points;

- Copy of the written record of inspection;

- Measurement system completed as prescribed, electrical meter indicators finalized;

- Signed power purchase agreement (PPA) or any agreement for power purchase;

- Dossier of work acceptance according to the law on construction:

- Primary equipment numbered according to the primary diagram issued by the dispatch level;

- Protective relay, automation, control, excitation and governor systems that have been installed and set in accordance with requirements prescribed herein and by the dispatch level;

- Lists of qualified operators as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade including full name, professional title, responsibility, phone number.

- Means of communications serving dispatching as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade;

- Connection to SCADA, monitoring system, PMU and communication system of the dispatch level fully completed;

- Operation coordination procedure agreed between the generating unit and the dispatch level.

2. If the energizing of connection points of customers has impacts on operation mode or in case of separation of equipment on the transmission grid from operation, the transmission network operator shall be responsible for delivering an application for separation of equipment within management to the dispatch level.

3. Within five working days since receipt of the application, the dispatch level shall be responsible for making notification to the transmission network operator and customers who need to get connected of the time and method of energizing connection points.

4. The transmission network operator and customers shall be responsible for coordinating energizing connection points according to the method notified by the dispatch level.

Article 49. Trial operation, acceptance and official operation of equipment behind connection points

1. During trial operation, acceptance and official operation of the equipment behind connection points, customers who need to get connected must appoint dispatchers and competent officials for keeping watch round the clock and send the list of officials with phone numbers to the transmission network operator and the dispatch level if need be.

2. Procedures for trial operation and acceptance shall be conformable with the manufacturer’s instructions and applicable regulations (if any).

3. During trial operation and acceptance, customers who need to get connected shall be responsible for cooperating with the transmission network operator, the dispatch level and relevant units in minimizing effects of new equipment in trial operation on safe and reliable operation of the national electricity transmission system.

4. After the process of trial operation and acceptance is completed, customers who need to get connected must provide confirmations and following information to the dispatch level and the transmission network operator:

a) Technical specs of electrical equipment, transmission lines, transformers and generating sets;

b) Test results and installation parameters of excitation and governor systems;

c) Other technical requirements as agreed in the connection agreement.

If equipment of customers who need to get connected fails to meet requirements prescribed herein and signed connection agreement, the transmission network operator or the dispatch level has the right not to connect the power plant or electrical grid of the customer to the transmission grid and request the customer to take remedial measures.

5. Electrical grid, power plant and electrical equipment of the customer shall be put into official operation after the process of trial operation and acceptance is completed and requirements prescribed herein and the signed connection agreement are met.

Article 50. Inspection and monitoring of equipment after put into official operation

1. During operation, the transmission network operator or the dispatch level (hereinafter referred to as "the requester") has the right to request the customer using transmission grid to carry out inspection, trial operation and supplementing the equipment within its management for following purposes:

a) Inspect the ability of the equipment to meet provisions prescribed herein, technical regulations applicable in Vietnam and particular requirements of the signed connection agreement;

b) Inspect the compliance of the equipment with terms and conditions under the PPA and the signed connection agreement;

c) Assess impacts of electrical grid, power plants of the customer using transmission grid on safe and reliable operation of the national electricity system;

d) Reset technical parameters of generating sets and electrical grids of the customer using transmission grid to serve safe, stable and reliable operation of the national electricity system.

2. Expenses for inspection, trial operation and additional tests shall be agreed by two parties and stated in the connection agreement or the PPA. Or shall be stipulated as follows:

a) If inspection result shows that the equipment fails to meet provisions prescribed herein and applicable technical regulations, the customer using transmission grid shall incur all the expenses for inspection and additional tests;

b) If inspection result shows no violation, the requester shall incur all the expenses for inspection and additional tests. For requirements for inspection as prescribed in Point c and Point d, Clause 1, this Article, the dispatch level must report to the Electricity Regulatory Authority before carrying out inspection.

3. The requester must make notification of subject matters, time and list of officials involved to the customer using transmission grid at least 15 days prior to the inspection and additional testing of the electrical grid and electrical equipment. The customer using transmission grid shall create favorable conditions for the requester to perform the inspection.

4. During the inspection, the requester is allowed to install monitoring equipment to the electrical equipment and electrical grid of the customer using transmission grid without having any negative effect on safe and reliable operation of such equipment.

5. During operation, if equipment of the customer using transmission grid at connection points has technical problems which may lead to loss of safety and reliability for the operation of the electricity transmission system, the dispatch level must make notification of such problems and requests for the remedy of the problems to the customer and the transmission network operator. The customer using transmission grid must take remedial measures and carry out trial operation to put the equipment behind connection points into operation again as prescribed in Article 49 herein. If such technical problems remain un-remedied, the dispatch level or the transmission network operator has the right to separate the equipment from the connection point and make notification to the customer.

6. For a generating set, the dispatch level has the right to request the generating unit to carry out testing one or several operational characteristics (it registered) at any time but no more than three times a year except for following cases:

a) Test result shows that one or several operational characteristics are inconsistent with parameters published by the generating unit;

b) When the dispatch level and the generating unit do not reach a common agreement on operational characteristics of the generating set;

c) Trial operation or inspection at the request of the generating unit;

d) Tests of fuel change.

7. The generating unit has the right to inspect and test its generating sets to re-determine operational characteristics of each generating set after the repair, replacement, improvement or re-assembly is completed. The time for trial operation must be agreed by the dispatch level.

Article 51. Replacement of equipment at connection points

1. During operation, to ensure safety, stability and reliability of the electricity transmission system, the dispatch level or the transmission network operator has the right to request the customer using transmission grid to invest, upgrade, or replace equipment at connection points or make adjustment to the settings of the equipment and must make prior notification to the customer.

2. If the customer using transmission grid needs to replace or upgrade the equipment at connection points or install/add new electrical equipment which may have impact on normal operation mode of the transmission grid, the customer must make a written notice to and reach an agreement for such changes with the transmission network operator. Within 10 working days since receipt of the written notice from the customer using transmission grid, the transmission network operator shall issue a written response to the customer concerning such changes.

3. If the proposal made by the customer using transmission grid is rejected, the transmission network operator shall issue a written notice of such rejection to the customer.

4. All the equipment for replacement or supplementation must be inspected and accepted according to the provisions prescribed in Article 45 to Article 50 herein. Subject matters concerning upgrading, replacement or adjustment of the settings of the equipment must be added to the signed connection agreement.

Section 7. PREPARATION FOR ENERGIZING ELECTRICAL EQUIPMENT OF TRANSMISSION NETWORK OPERATOR

Article 52. Dossier for inspection of connection point energizing conditions

1. Dossier serving general inspection of connection point energizing conditions (technical documents with customers’ confirmations and certified copy of legal documents) includes:

a) Main connection diagram, primary one-line diagram, layout of electrical equipment, schematic diagram of protective relay, automation and control systems representing circuit breakers, current transformers, voltage transformers, lightning arrestor;

b) Instruction manuals for setting of protective relays, automation, specialized software;

c) Documents and technical specs of installed equipment;

d) Secondary diagrams of protective relay, automation and control system;

dd) Diagrams detailing connection to electrical works of the transmission network operator and parameters of transmission lines;

e) Other relevant diagrams (if any);

g) Plans for energizing work items, schedules for trial operation, energizing and operation.

2. Within two months prior to the date the transmission lines, substations are put into operation for the first time, the transmission network operator shall provide adequate documents prescribed in Clause 1 of this Article to the dispatch level.

3. At least 20 working days since receipt of the documents, the dispatch level deliver following documents to the customer:

a) Trial operation schedules, methods of energizing and operating electrical equipment;

b) Equipment numbering diagram;

c) Requirements for methods of receiving dispatch instruction;

d) Relay setting notes for protective relays of the transmission network operator;

dd) Requirements for testing and calibration of equipment;

e) Requirements for establishment of communication system serving dispatching;

g) Requirements for connection and operation of SCADA system;

h) Processes related to electricity system and market operation;

i) Lists of relevant officials and dispatchers accompanied by phone and facsimile numbers.

4. Within 20 days prior to the date of energizing, the transmission network operator shall negotiate with the dispatch level on plans for energizing work items, schedule for trial operation, energizing and operation.

Article 53. Energizing

1. The transmission network operator shall submit the written registration for energizing together with following documents to the dispatch level:

a) Written confirmations of fulfillment of legal and technical procedures:

- Equipment within the scope of energizing that meets operational and technical requirements at connection points;

- Measurement system completed as prescribed, electrical meter indicators finalized;

- Dossier of work acceptance according to the law on construction.

- Primary equipment numbered according to the primary diagram issued by the dispatch level;

- Protective relay and automation system reset in accordance with the requirements of the dispatch level.

- Lists of qualified operators as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade including full name, professional title, responsibility, phone number.

- Means of communications serving dispatching as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade;

- Connection to SCADA, monitoring system, PMU and communication system of the dispatch level fully completed.

2. If energizing the electrical grid of the transmission network operator has impact on the operation of the electrical grid, power plants of the customer using transmission network operator, the transmission network operator shall be responsible for registering plans for separation of the equipment with the dispatch level. The dispatch level shall report to the customer using transmission grid for energizing coordination.

3. Within five working days since receipt of the application for energizing, the dispatch level shall be responsible for making notification to the transmission network operator of the time for energizing.

4. The transmission network operator shall be responsible for energizing connection points according to the method notified by the dispatch level.

Article 54. Replacement of equipment on transmission grid

1. If the transmission network operator needs to change or upgrade the equipment on the transmission grid, or add new equipment likely to affect operation mode of the transmission grid, the transmission network operator must make a written notice to and reach an agreement with the dispatch level on such changes. If such changes result in changes to the equipment of the customer using transmission grid at connection points, the transmission network operator must make a written notice to the customer for coordination ensuring no impact on operation of the electrical equipment of the customer at connection points.

2. The dispatch level must make notification to the transmission network operator upon rejection of the proposal for changes made by the transmission network operator.

3. Equipment for replacement or supplementation must be conformable with Article 52 and Article 53 herein.

Section 8. DISCONNECTION AND RECONNECTION

Article 55. General provisions on disconnection and reconnection

1. Cases of disconnection:

a) Voluntary disconnection;

b) Compulsory disconnection.

2. The customer using transmission grid must incur all the expenses for disconnection and reconnection.

Article 56. Voluntary disconnection

1. Permanent disconnection

a) Permanent disconnection of the customer using transmission grid from the electricity transmission system and responsibility of relevant parties must be stated in the PPA and connection agreement.

b) Responsibility of the customer using transmission grid for permanent disconnection from the electricity transmission system:

- Make a written notice to the transmission network operator and the dispatch level at least two months prior to the date of permanent disconnection in case the customer does not possess any generating set connecting to the transmission grid.

- Make a written notice to the transmission network operator and the dispatch level at least six months prior to the date of permanent disconnection in case the customer possesses a generating set connecting to the transmission grid.

2. Temporary disconnection

In case of temporary disconnection from the electricity transmission system, the customer using transmission grid must make a written notice to and reach an agreement with the transmission network operator and the dispatch level on the time of disconnection at least one month prior to the date of temporary disconnection.

Article 57. Compulsory disconnection

1. The transmission network operator or the dispatch level shall disconnect equipment of the customer using transmission grid from the electricity transmission system in following cases:

a) At the request of competent state agencies when the customer using transmission grid violates the regulation;

b) As stated in the PPA or connection agreement;

c) Cases prescribed in Clause 5, Article 50 herein.

2. The Electricity Regulatory Authority has the right to request compulsory disconnection in case the customer using transmission grid violates the provisions prescribed herein, in the operation license for electricity, the regulation on competitive electricity market operation, the regulation on electricity measurement in electricity system.

3. The customer using transmission grid failing to perform compulsory disconnection shall face penalties as prescribed.

Article 58. Reconnection

The transmission network operator shall be responsible for performing reconnection in following cases:

1. As requested by competent state agencies or the Electricity Regulatory Authority or the dispatch level provided that the reasons for compulsory disconnection are excluded and consequences remedied.

2. As requested by the customer using transmission grid in case all the expenses for temporary disconnection have been paid by the customer.

Chapter VI

OPERATION OF ELECTRICITY TRANSMISSION SYSTEM

Section 1. OPERATING PRINCIPLES

Article 59. Operation modes of electricity transmission system

1. In normal operation mode, the electricity transmission system shall meet following conditions:

a) Generating capacity and loads are in the state of balance;

b) No load shedding made;

c) Load carrying level of the lines and transformers in the transmission grid is below 90% of rated value;

d) Power plants and other electrical equipment operate within permissible parameter band;

dd) Electricity system frequency is within permissible band in normal operation mode as prescribed in Article 4 herein;

e) Voltage level on the transmission grid is within permissible band in normal operation mode as prescribed in Article 6 herein;

g) Reserve power of the national electricity system is readily available to maintain frequency and voltage of the national electricity system within the band in normal operation mode; the equipment automatically works within permissible scope to ensure no load shedding in case of incident.

2. The electricity transmission system shall operate in a warning mode under one of following conditions:

a) Frequency regulation reserve, spinning reserve and quick-start reserve levels are lower than required in normal operation mode;

b) Load carrying level of the lines and transformers in the transmission grid is from 90% and on but not in excess of rated value;

c) Voltage level on the transmission grid is beyond permissible range in normal operation mode but within permissible voltage range in case of single fault as prescribed in Article 6 herein;

d) Natural disasters or unusual weather conditions that are likely to affect electricity supply security;

dd) Issues related to national defense and security likely to threaten electricity system security

3. The electricity transmission system shall operate in an emergency mode under one of following conditions:

a) Electricity system frequency is beyond permissible band in normal operation mode but within permissible band in case of a single fault as prescribed in Article 4 herein;

b) Voltage level on the transmission grid exceeds permissible range in case of a single fault as prescribed in Article 6 herein;

c) Load carrying level of any electrical equipment in the transmission grid is beyond rated value but under 110% of rated value when an incident caused by an overload to the equipment may lead to an extreme emergency mode.

4. The electricity transmission system shall operate in an extreme emergency mode under one of following conditions:

a) Electricity system frequency exceeds permissible band in case of a single fault as prescribed in Article 4 herein;

b) Load carrying level of any equipment in the transmission grid or equipment connecting to the transmission grid is from 110% of rated value and on when an incident caused by an overload to the equipment may result in disintegration of individual components of the electricity system.

c) That the electricity transmission system operates in an emergency mode and measures taken to bring the system to the state of stable operation fail has resulted in the disintegration of individual components of the electricity transmission system or voltage collapse in the electricity system.

5. The electricity transmission system operates in a restoration mode when the generating sets, transmission grid and loads are energized and synchronized to the state of normal operation.

Article 60. Operating principles of electricity transmission system

1. The electricity system and market operator shall be responsible for operating the electricity transmission system in a safe, reliable, stable and economic manner ensuring compliance with principles, regulations on operation and dispatching of the national electricity system prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade..

2. Principles of formulating electricity transmission system operation plan

a) Ensure safety, stability and reliability of the operation

a) Ensure compliance with requirements for anti-flooding, irrigation and maintenance of ecological currents according to the approved procedures for hydroelectric reservoir operation;

c) Ensure obligations for sources of primary fuel for thermo power plants;

d) Ensure permissible technical conditions of generating sets and transmission grids;

dd) Ensure execution of agreement for electrical production and power through PPAs or electricity import, export contracts;

e) Ensure principles of minimizing expenses for purchasing electricity for the entire electricity system.

3. The electricity system and market operator shall be responsible for formulating the plan for electricity transmission system operation in the next year (year N+1) with account taken of the year thereafter (year N+2), next month, next week, day-ahead mobilization schedules and transaction cycle mobilization schedules including following information:

a) Equipment and transmission grid maintenance and repair plan;

b) Assessment of electricity system security;

c) Load forecasts, plans for supply of fuel to thermo power plants, progress of operation of new electrical works, hydrographical forecasts of hydro power plants, calculations of electricity system reserves, power supplies and ancillary service mobilization plans, and load shedding (if any) to ensure electricity system security;

d) Warnings about the decline in electricity system security (if any).

4. The plan for electricity transmission system operation in the next year (year N+1) with account taken of the year thereafter (year N+2):

a) The plan for electricity transmission system operation in the next year (year N+1) formulated by the electricity system and market operator must be in compliance with the method of national electricity system operation in the next year (year N+1) as prescribed in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade;

b) Plan for operation of electricity transmission system in year N+2 must include assessment of electricity system security, orientation of operational scenarios and medium-term measures to ensure the national electricity system operates in a safe, reliable and stable manner.

5. The transmission network operator and the customer using transmission grid shall rely on the operation plan and mobilization schedules of the electricity system and market operator to formulate plans for operation of power plants and electrical grids of their own ensuring no negative impact on safe, reliable and stable operation of the electricity transmission system.

6. During the operation of the electricity transmission system, the electricity system and market operator must comply with following principles to maintain safety, stability and reliability of the electricity transmission system:

a) In normal operation mode, the electricity system and market operator shall be responsible for operating and dispatching the electricity system and assuring operational standards and parameters within permissible scope in normal operation mode as prescribed in Chapter II herein and meeting the requirements prescribed in Clause 1, Article 59 herein;

b) In a warning mode, the electricity system and market operator must publish on its website the status and warnings about the electricity system and put forward necessary measures to restore the electricity system to normal operation mode;

c) In an emergency mode, the electricity system and market operator must take necessary measures to restore the electricity system to normal operation mode as soon as possible.

d) In an extreme emergency mode or in case of multi-fault or a threat to human lives or safety of equipment, load shedding can be made but must be in compliance with the procedure for handling of incident to the national electricity system issued by the Ministry of Industry and Trade.

Article 61. Inspection and monitoring of protective relay system

The dispatch level shall request relevant units to ensure the protective relay, automation and control system in the electricity system meets the requirements prescribed herein, electrical equipment norms issued by the Ministry of Industry and Trade and technical requirements of the protective relay and automation system in power plants and transformers issued by the Electricity Regulatory Authority.

Article 62. Stable operation of electricity system

1. The electricity system and market operator shall be responsible for calculating and determine limits of stable operation of the electricity system. The transmission network operator and customer using transmission grid must provide information at the request of the electricity system and market operator to serve the research and assessment of stability of the electricity system.

2. During the formulation of the electricity system operation plan, the electricity system and market operator shall be responsible for considering obligations for electricity system security to ensure operation mode of the electricity system does not exceed electricity system stability standards prescribed in Article 5 herein.

3. Generating units shall be responsible for operating power plants to maintain working voltage level and ensuring adequate supply of reactive power to the electricity system during operation; not separating generating sets from the operation in case of a fault unless such fault runs the risk of threatening human lives or safety of the equipment or the frequency exceeds permissible limits prescribed in Article 38 herein or permitted by the electricity system and market operator.

4. Electricity distribution units and electricity customers shall be responsible for maintaining operation of the voltage regulation equipment within the electrical grid of their own in order to ensure stability of voltage to the electricity system.

5. Other relevant units shall be responsible for maintaining operation of electrical grids, power plants of their own within limits of stability set for individual stages, coordinating maintenance of protective diagram to remove quickness, sensitivity and selectivity faults.

Article 63. Trial operation and monitoring

1. Generating units shall be responsible for carrying out trial operation of generating sets of their own at the request of the electricity system and market operator. Upon request for trial operation, the electricity system and market operator must make notification of the time for pausing the monitoring of generating sets for the purpose of trial operation.

2. Trial operation of automation of generating sets according to changes of electricity system frequency shall be carried out when the electricity system is in normal operation mode. In this case, the electricity system and market operator shall make a written notification of the trial operation at least three working days in advance to generating units for coordination.

3. Trial operation shall be carried out within limits of operation according to characteristics of the generating set and within the period of time specified.

4. The electricity system and market operator has the right to test a generating set at any time but no more than three times a year unless otherwise as prescribed in Clause 6, Article 50 herein.

5. The generating unit has the right to request trial operation in following cases:

a) Re-inspect operational characteristics of the calibrated generating set after every incident;

b) Inspect the generating set after it is installed, overhauled, improved or re-assembled.

6. Upon request for trial operation of the generating set, the generating unit shall submit an application to the electricity system and market operator stating following information:

a) Records of the generating set;

b) Characteristics of the generating set;

c) Value of operational characteristics expected to change during operation.

7. Within three working days since receipt of the request from the generating unit, the electricity system and market operator shall arrange the plan for trial operation. If the trial operation cannot be carried out, the electricity system and market operator may request the generating unit to operate the generating set according to current operational characteristics.

Article 64. Handling of incident

1. During the handling of incident, the electricity system and market operator is allowed to operate the electricity system in the frequency and voltage other than the standards prescribed in normal operation mode but shall promptly take measures to restore the electricity system to normal operation mode to ensure stability of the system.

2. The electricity system and market operator, the generating unit and the customer using transmission grid shall carry out the handling of the incident in accordance with the provisions prescribed in the incident handling procedure issued by the Ministry of Industry and Trade.

3. Key measures to handle the incident

a) Change generating capacity of the generating set, stop or start the generating set to restore frequency to the frequency band at normal operation mode;

b) Carry out load shedding on each line through an automatic under-frequency load shedding relay or under dispatch instruction;

c) Automatic under-frequency load shedding. The automatic frequency load shedding system must be arranged and installed appropriately to prevent the electricity system from falling into pieces in case of incident. The electricity system and market operator shall be responsible for determining installation positions and settings of the low-frequency relay and carry out load shedding in case of incident.

d) Construct methods of separating the system into regions or creating a ring circuit to be able to balance power in each region in case of an incident, to maintain operation of individual components of the electricity system and prevent the incident from spreading throughout the electricity system.

dd) When the frequency increases to the permissible value, the electricity system and market operator shall restore the loads shedded;

e) The electricity system and market operator has the right to interfere in to restrict constant separation of generating sets, loading lines from operation;

g) In case part or whole of the electricity system falls to pieces, the electricity system and market operator shall be allowed to appoint a power plant with black start capability to restore the electricity system. If necessary, the electricity system and market operator may request the power plant to operate the generating set without relying on operational characteristics provided that the safety of human beings and equipment is assured. The generating unit shall be responsible for complying with black start instruction and making notification to the electricity system and market operator. The electricity system and market operator shall be responsible for restoring all the loads appropriately to ensure stable operation of the generating set and synchronizing other generating sets.

Article 65. Notice of decline in electricity system security

1. Upon detection of any sign of decline in electricity system security, the electricity system and market operator shall make a written notification to the transmission network operator, the customer using transmission grid and relevant parties of following information:

a) State of decline in electricity system security;

b) Causes;

c) Possible load shedding;

d) Affected units and areas.

2. The electricity system and market operator shall make notification to the affected units before carrying out load shedding under the dispatch instruction. The notification shall include following information:

a) Areas subject to suspension or reduction of power supply;

b) Reasons for suspension or reduction of power supply;

c) Time of starting suspension or reduction of power supply;

d) Expected time for restoration of power supply.

3. When notification of load shedding under dispatch instruction cannot be made, the electricity system and market operator must make notification to the transmission network operator, the customer using transmission grid and relevant units right after it has completed load shedding under dispatch instruction:

a) Areas subject to suspension or reduction of power supply;

b) Reasons for suspension or reduction of power supply;

c) Start time for suspension or reduction of power supply;

d) Expected time for restoration of power supply.

4. Manner of notification: Based on the assessment of electricity system security according to annual, monthly and weekly electricity system operation plans and daily mobilization schedules, the electricity system and market operator shall be responsible for making notification of the decline in electricity system security and measures to prevent suspension or reduction of power supply (if any) as follows:

a) Make written notification of decline in electricity system security to relevant units and publish the notification on the website of the electricity system and market operator according to annual, monthly electricity system operation plans;

b) Give dispatch instruction within competence and publish the notification of decline in electricity system security on the website of the electricity system and market operator according to weekly, daily electricity system operation plans and methods.

Article 66. Load shedding for electricity system security

1. The dispatch level shall calculate and allocate capacity and electrical energy in the electricity distribution units and electricity customers in accordance with Article 60 and Article 64 herein and the Regulation on formulation and implementation of power supply plan when the national electricity system is short of power issued by the Ministry of Industry and Trade to ensure the electricity system operates in a safe, reliable and stable manner.

2. The electricity distribution units and electricity customers shall be responsible for suspending or reducing power supply at the request of the dispatch level.

3. If the electricity system operates in an extreme emergency mode, the dispatch level has the right to shed part of the loads from the electricity distribution units and electricity customers even though the amount of electrical energy and capacity is reduced as required.

Section 2. RESPONSIBILITY OF UNITS IN OPERATION OF ELECTRICITY TRANSMISSION SYSTEM

Article 67. Responsibility of electricity system and market operator

1. Formulate operational plans and methods serving dispatching and operation of the national electricity system on an annual, monthly, weekly and daily basis and hour-ahead schedules as prescribed herein and in the national electricity system dispatch procedure issued by the Ministry of Industry and Trade.

2. The electricity transmission system must be dispatched and controlled in accordance with the dispatch procedure, the incident handling procedure and the operating procedure of the national electricity system issued by the Ministry of Industry and Trade and the provisions prescribed herein to ensure safe, reliable, stable and economical operation.

3. Inspect and go through the diagram of protection of electrical equipment of the customer using transmission grid in case such diagram has impact on transmission grid protection system.

4. Establish and maintain stable, reliable and constant operation of communication system, data transmission system, SCADA/EMS and remote control system serving operation and dispatching.

5. Dispatch and operate generating sets, transmission grids as prescribed in this Chapter and the national electricity system dispatch procedure issued by the Ministry of Industry and Trade.

6. Preside over negotiation on plans for maintenance and repair of generating sets and electrical grids with the transmission network operator and the customer using transmission grid.

7. Inspect and supervise installation and setting of parameters of protective, automation, control, governor, excitation systems, connect AGC of the transmission network operator and the customer using transmission grid meeting requirements prescribed herein and requirements of the dispatch level to ensure safe and reliable operation of the transmission electricity system. Report non-compliance cases to the Electricity Regulatory Authority for handling measures.

8. Request inspection and additional tests of the equipment under management of the transmission network operator or the customer using transmission grid.

9. Cooperate with the transmission network operator in the establishment of national transmission grid protection diagrams and maintaining operational characteristics of protective equipment aligned with the protection diagram.

10. Share and provide necessary information to the transmission network operator and customer using transmission grid serving operation of the electricity transmission system.

Article 68. Responsibility of transmission network operator

1. Manage and operate transmission grid within management ensuring satisfaction of operational and technical requirements as prescribed herein, comply with the national electricity system dispatch procedure, operating procedure, and incident handling procedure issued by the Ministry of Industry and Trade and other relevant law provisions.

2. Provide technical parameters of equipment to the dispatch level. Unless the maintenance or repair is planned or has an incident, the transmission network operator must ensure that all of its equipment is readily available for operation according to dispatch instruction of the dispatch level. The transmission network operator shall provide the dispatch level with information concerning changes of readiness of the equipment and reasons for changes.

3. Establish protection, automation and control systems in accordance with applicable industry standards, requirements prescribed herein and requirements of the dispatch level to ensure stable and reliable operation of the electricity transmission system.

4. Establish transmission grid protection diagrams and maintain operational characteristics of protective equipment.

5. Maintain operation of the transmission grid in a safe and reliable manner, restore the transmission grid after the incident.

6. Comply with technical regulations and standards on operation of the transmission grid; regulations on electricity safety, electrical grid and work protection corridors according to laws.

7. Cooperate with the dispatch level during the formulation of the plan for operation, maintenance and repair of electrical grids, establishment of protection diagrams, communication system, SCADA system serving operation of the national electricity system.

8. Provide necessary information to the dispatch level and customer using transmission grid serving operation of the electricity transmission system.

Article 69. Responsibility of generating units

1. Manage and operate power plants and electrical grids within management ensuring satisfaction of operational and technical requirements as prescribed herein, comply with the national electricity system dispatch procedure, operating procedure, and incident handling procedure issued by the Ministry of Industry and Trade and other relevant law provisions.

2. Provide the dispatch level with information concerning readiness of generating sets including generating capacity, time of starting and stopping generating sets. In case of changes in level of readiness of generating sets, the generating units shall be responsible for providing such changes and the reasons to the dispatch level.

3. Maintain reliable and stable operation of the governor and excitation systems, connection of AGC and other technical requirements related to the equipment at connection points as prescribed herein to ensure adequate supply of power at the request of the electricity system and market operator aligned with the PPA and connection agreement. Do not change settings of the governor, excitation system, connection of AGC and other relevant technical requirements without consent of the electricity system and market operator. Carry out necessary trial operation and tests at the request of the electricity system and market operator.

4. In case of overhauling a generating set, the generating unit shall be responsible for carrying out the tests to assess the operation of the excitation and governor system of generating sets and sending test results to the electricity system and market operator. Subject matters and requirements of tests are conformable with the testing and monitoring procedure issued by the Electricity Regulatory Authority.

5. Establish protection, automation and control systems in accordance with applicable industry standards, requirements prescribed herein and requirements of the dispatch level to ensure stable and reliable operation of the national electricity system.

6. Invest, install, maintain, manage and operate DCS, RTU/Gateway and communication systems within management and data transmission lines to ensure reliable and constant transmission of information and data to the SCADA system, communication and control systems of the dispatch level. Do not separate equipment from operation without consent of the dispatch level.

10. Provide necessary information to the dispatch level and customer using transmission grid serving operation of the electricity transmission system.

Article 70. Responsibility of electricity distribution units, electricity retailers

1. Manage and operate electrical grids within management ensuring satisfaction of operational and technical requirements as prescribed herein, comply with the national electricity system dispatch procedure, operating procedure, and incident handling procedure issued by the Ministry of Industry and Trade and other relevant law provisions.

2. Provide technical parameters of equipment to the dispatch level. Unless the maintenance or repair is planned or has an incident, the transmission network operator must ensure that all of its equipment is readily available for operation according to dispatch instruction of the dispatch level. The transmission network operator shall provide the dispatch level with information concerning changes of readiness of the equipment and reasons for changes.

3. Establish protection, automation and control systems in accordance with applicable industry standards, requirements prescribed herein and requirements of the dispatch level to ensure stable and reliable operation of the electricity transmission system.

4. Operate compensate equipment in the distribution grid to meet demands for reactive power.

5. Maintain operation of protection system, readiness of automatic load shedding system at the request of the dispatch level.

6. Formulate and provide load forecasting figures to the electricity system and market operator as prescribed in Chapter III herein.

7. Invest, install, maintain, manage and operate DCS, RTU/Gateway and communication systems within management and data transmission lines to ensure reliable and constant transmission of information and data to the SCADA system, communication and control systems of the dispatch level. Do not separate equipment from operation without consent of the dispatch level.

8. Provide necessary information to the dispatch level and transmission network operator serving operation of the electricity transmission system.

Article 71. Responsibility of electricity customers

1. Manage and operate electrical equipment, electrical grids within management ensuring satisfaction of operational and technical requirements as prescribed herein, comply with the national electricity system dispatch procedure, operating procedure, and incident handling procedure issued by the Ministry of Industry and Trade and other relevant law provisions.

2. Comply with load profile and assure power factor as stated in the signed PPA.

3. Install, manage and operate the protective relay, automation and control system within management to ensure stable and reliable operation of the national electricity system. Do not change settings of the protective relay, automation and control system and other relevant technical requirements within management without consent of the dispatch level. Carry out necessary tests as requested by the dispatch level.

4. Formulate and provide load forecasting figures to the electricity system and market operator as prescribed in Chapter III herein.

5. Invest, install, maintain, manage and operate DCS, RTU/Gateway and communication systems within management and data transmission lines to ensure reliable and constant transmission of information and data to the SCADA system, communication and control systems of the dispatch level. Do not separate equipment from operation without consent of the dispatch level.

6. Provide necessary information to the dispatch level and transmission network operator serving operation of the electricity transmission system.

Section 3. ANCILLARY SERVICES

Article 72. Types of ancillary services

Types of ancillary services used to adjust frequency and voltage during operation of the electricity transmission system:

1. Frequency regulation

2. Spinning reserve

3. Quick-start

4. Voltage adjustment

5. Must-run operation reserves to ensure electricity system security

6. Black start

Article 73. Technical requirements of ancillary services

1. Frequency regulation Generating sets providing frequency regulation service must be capable of increasing or reducing capacity meeting changes of electricity system frequency or other automatic signals stipulated by the electricity system and market operator. Generating sets must be capable of changing at least 4% of rate power within 10 seconds and maintaining such changes for a minimum of 10 minutes.

2. Spinning reserve: Generating sets providing spinning reserves must be capable of increasing to a rate power according to frequency signal or other automatic signals stipulated by the system and market operator within 25 seconds and maintain such rate power for a minimum of 30 minutes.

3. Quick-start: Generating sets providing quick-start reserve must be capable of increasing to the rated power within 25 minutes and maintain such rated power for a minimum of eight hours

4. Voltage adjustment: Generating sets providing voltage adjustment must be capable of changing reactive power outside the band prescribed in Clause 2, Article 38 herein, meeting requirements of the electricity system and market operator.

5. Must-run operation reserves to ensure electricity system security: Generating sets providing must-run operation to ensure electricity system security must be capable of increasing to a rated power within one hour and maintaining such rated power for a minimum of eight hours (excluding the time of starting).

6. Black start: Generating sets providing black start must be capable of self-starting in a cold state without power supply from the national electricity system and capable of supplying electricity to transmission grids, distribution grids after successfully started.

Article 74. Principles of determining demand for ancillary services

1. General principles of determining demand for ancillary services:

a) Maintain electrical energy and capacity reserves of the electricity system in accordance with operation and electricity system security standards;

b) Ensure minimum expenses in accordance with conditions and obligations of the national electricity system.

2. Principles of determining demand for ancillary services

a) Frequency regulating reserve is the amount of necessary available capacity in the national electricity system readily available for being mobilized, dispatched to control primary frequency for a specified period of time in order to maintain electricity system frequency within permissible band;

b) Spinning reserve is the amount of necessary available capacity in the national electricity system readily available for being mobilized, dispatched in order to restore electricity system frequency to permissible band after a single fault;

c) Quick-start: Quick-start reserve must be capable of compensating difference between appropriate reserve power determined in Article 93 herein and reserve power stipulated in Article 94 herein;

d) Voltage adjustment: Voltage adjustment must ensure efficient mobilization of reactive power to maintain voltage at busbars on transmission grids meeting standards in normal operation mode;

dd) Must-run operation reserves to ensure electricity system security: The electricity system and market operator shall be responsible for calculating and comparing operation modes with and without obligations on the simulation modeling of the electricity system and market with account taken of following cases:

- Ensure satisfaction of requirements for electrical energy and capacity of electrical grid connecting the countries in the region;

- Maintain standards on voltage and stability of the national or regional electricity systems.

e) Black start: Function of the black start is to ensure efficient mobilization of power and be readily available when the electricity system has a wide-area outage. The electricity system and market operator shall be responsible for calculating and analyzing incidents likely to separate the transmission grid into isolated regions for calculation and determination of requirements of black start services in the electricity transmission system.

3. Before November 01 annually, the electricity system and market operator shall be responsible for calculating demand for ancillary services of the national electricity system, reporting to Vietnam Electricity before submission to the Electricity Regulatory Authority for approval.

Article 75. Registration of ancillary services

1. Apart from the black start service, the generating units shall be responsible for registering supply of ancillary services of individual generating sets with the electricity system and market operator in accordance with technical requirements and demand for ancillary services prescribed in Article 73 and Article 74 herein.

2. For a power plant to be energized and put into operation, the generating unit shall be responsible for registering supply of ancillary services of individual generating sets within three months before the generating set operates commercially.

3. Generating units must make notification to the electricity system and market operator of any changes to the equipment which may affect supply of ancillary services.

Section 4. MAINTENANCE AND REPAIR OF ELECTRICITY TRANSMISSION SYSTEM

Article 76. General provisions on maintenance and repair of electricity transmission system

1. The electricity system and market operator shall be responsible for formulating plans for maintenance and repair of the electricity transmission system including plans for maintenance and repair of transmission grids, power plants with installed capacity over 30 MW and power plants connecting to transmission grids.

2. Plans for maintenance and repair of electricity transmission system shall be formulated on the basis of registration of the plan for operation, maintenance and repair of electrical grids, power plants of the transmission network operator, the customer using transmission grid and calculated in the entire national electricity system in following principles:

a) Ensure safe, stable, reliable and economical operation of the entire national electricity system;

b) Balance source power and loads, have sufficient reserve power, electrical power and necessary ancillary services in operation modes of the national electricity system;

c) Optimize coordination in the maintenance and repair of equipment, electrical grids and power plants with hydrographical condition obligations, requirements for supply of lowland water, flood prevention and supply of primary fuel for power generation ;

d) Short-term maintenance and repair plans must be formulated based on long-term maintenance and repair plans;

dd) Ensure possible highest reserve electrical energy and capacity of the national electricity system in peak hours. Prioritize maintenance and repair during the period of low loads of the national electricity system;

e) Minimize suspension and reduction of power supply from the national electricity system; minimize maintenance and repair during the period of time when political, cultural and social events take place.

3. The electricity system and market operator shall assess level of impact of the plan for maintenance and repair of the electricity transmission system by the transmission network operator and the customer using transmission grid on electricity system security as prescribed from Article 92 to Article 95 herein.

4. The transmission network operator and the customer using transmission grid must comply with the plan for maintenance and repair of the electricity transmission system formulated and announced by the electricity system and market operator.

5. The plan for maintenance and repair of electricity transmission system includes:

a) Annual maintenance and repair plan: The plan shall be formulated for the next year (year N+1) with account taken of the year thereafter (year N+2) serving the formulation of annual electricity system operation plan and medium-term assessment of electricity system security;

b) Monthly maintenance and repair plan: The plan shall be formulated and updated on a monthly basis with account taken of the month thereafter on the basis of the approved annual maintenance and repair plan;

c) Weekly maintenance and repair schedule: The schedule shall be formulated for the next week with account taken of the week thereafter on the basis of the approved monthly maintenance and repair plan;

d) Daily maintenance and repair schedule: Determine the maintenance and repair tasks to be performed next day.

6. The time of registration for the plan for maintenance and repair of the electricity transmission system must be compliant with the regulation on time of registration of electricity transmission system operation plan.

7. The plan for maintenance and repair of electricity transmission system includes:

a) Name of equipment that needs maintenance and report;

b) Requirements and subject matters of maintenance and report;

c) Expected time for starting and completing maintenance and repair tasks;

d) Other relevant equipment.

Article 77. Establishment of plan for maintenance and repair of electricity transmission system

1. The plan for maintenance and repair of electricity transmission system must be in coordination with schedule of maintenance and repair of equipment, electrical grids, power plants to minimize negative impact on national electricity system security.

2. Annually, the transmission network operator and the customer using transmission grid must register the plan for maintenance and repair of electrical grids, power plants with the electricity system and market operator.

3. Based on the registration information provided, the electricity system and market operator shall be responsible for formulating the plan for maintenance and repair of generating sets, transmission grids and relevant connection equipment in accordance with the provisions prescribed in Article 76 herein.

4. The electricity system and market operator must cooperate with relevant units in formulating the plan for maintenance and repair plan of equipment ensuring electricity supply security of the national electricity system.

5. After the plan for maintenance and repair of electricity transmission system is completed, the electricity system and market operator shall make publish on its website following information on a regular basis:

a) Annual maintenance and repair plan: Annually published;

b) Monthly maintenance and repair plan: Published on a monthly basis;

c) Weekly maintenance and repair schedule: Published on a weekly basis;

d) Daily maintenance and repair schedule: Published on a daily basis;

Article 78. Order of priority on separation of equipment for maintenance and repair

1. During the formulation of the plan for maintenance and repair of equipment as prescribed in Article 77 herein, the electricity system and market operator may reject requests for separation of equipment for maintenance and repair when finding that the separation of equipment will affect electricity system security.

2. Before rejecting requests for separation of equipment for maintenance and repair, the electricity system and market operator shall establish the plan for maintenance and repair of electricity transmission system in order of priority as follows:

a) Separation of equipment for maintenance and repair of power source is more prioritized than the transmission grid;

b) Separation of equipment for maintenance and repair of power sources shall be prioritized according to the principle of minimizing expenses for purchase of power for the entire system;

c) If two or more requests for separation of equipment for maintenance and repair of power sources affect generating costs, any request that comes first shall be given higher priority.

3. Based on order of priority as prescribed in Clause 2 of this Article, the electricity system and market operator has the right to reject requests for separation of equipment for maintenance and repair until electricity system security is ensured.

Article 79. Registration for separation of equipment for maintenance and repair

1. Registration for separation of equipment in operation for maintenance and repair by the transmission network operator and the customer using transmission grid is classified as follows:

a) Registration of maintenance and repair according to the plan is the registration of separation of equipment for maintenance and repair on the basis of the plan for maintenance and repair of electricity transmission system formulated and published by the electricity system and market operator.

b) Registration of maintenance and repair outside the plan is the registration of separation of equipment for maintenance and repair outside the plan for maintenance and repair of electricity transmission system formulated and published by the electricity system and market operator.

c) Registration of unscheduled maintenance and repair is the registration for separation of equipment in operation in the state of possible hazards.

2. Separation of equipment for repair includes:

a) Name of equipment;

b) Main tasks;

c) Expected time for task performance;

d) Expected time for inspection and trial operation;

dd) Expected time for separating and bringing equipment back to work;

e) Other equipment that needs isolation;

g) Other necessary information.

3. If a decline in electricity system security results in a change to the schedule for separation of equipment for repair, the transmission network operator or the customer using transmission grid must re-register with the electricity system and market operator at least 48 hours before the equipment is separated from operation, including for repair inside and outside the plan.

4. In case of a threat to human life or safety of equipment, the transmission network operator or the customer using transmission grid may separate such equipment to prevent danger to people and equipment. The transmission network operator or the customer using transmission grid must make an immediate notification of separation of equipment to the electricity system and market operator.

5. Upon receipt of notice of the decline in electricity system security prescribed in Article 65 herein, the transmission network operator or the customer using transmission grid may bring the equipment under maintenance and repair back to normal operation in the earliest time possible versus the approved plan, ensuring no later than 48 hours since receipt of the request from the electricity system and market operator. In this case, the transmission network operator or the customer using transmission grid must make a written notice to the electricity system and market operator at least four hours before the equipment is expected to be brought back to operation.

Article 80. Separation of equipment in operation for urgent repair

If the equipment in operation is likely to threaten human life or safety, the operator from the transmission network operator or the customer using transmission grid has the right to separate the equipment immediately from the electricity transmission system and take full responsibility for the separation.

Article 81. Reports on urgent separation of equipment for repair

In case of urgent separation of equipment, relevant units shall be responsible for making reports as follows:

1. The transmission network operator and the customer using transmission grid shall be responsible for making updates and immediate notice to the electricity system and market operator of changes of equipment status and related information.

2. In case the urgent separation of equipment causes suspension or reduction of power supply on a large scale, within 24 hours, the electricity system and market operator shall report reasons for separation of equipment, the causes and scope of impact to the Electricity Regulatory Authority.

Section 5. ELECTRICITY SYSTEM SCHEDULING AND DISPATCHING

Article 82. Day-ahead mobilization schedules

1. The purpose of day-ahead mobilization scheduling is to update and adjust the schedule of mobilizing generating sets and ancillary services in the day-ahead transaction cycles.

2. Day-ahead mobilization schedules are formulated in accordance with the competitive electricity market operation procedure and the national electricity system dispatch procedure issued by the Ministry of Industry and Trade with account taken of obligations for electricity system security.

3. The electricity system and market operator shall be responsible for calculating and formulating day-ahead mobilization schedules, and publishing results on its website in accordance with electricity market operation time table.

Article 83. Obligations for system security

1. To formulate mobilization and dispatching schedules in accordance with principles of safe operation prescribed in Article 60 and Article 62 herein, the electricity system and market operator must determine obligations for electricity system security in the model of calculation and formulation of mobilization schedules.

2. The electricity system and market operator shall be responsible for studying and determining the lists of obligations for electricity system security serving the formulation of mobilization and dispatching schedules including:

a) Transmission grid obligations;

b) Generating sets’ generating capability obligations;

c) Requirements for ancillary services;

d) Necessary obligations to ensure electricity supply security as prescribed in Article 60 and Article 62 herein.

3. The electricity system and market operator must make public announcement of the grounds for determination of the obligations for electricity system security at least one week in advance and updates must be constantly made.

4. If necessary, the electricity system and market operator may change obligations for electricity system security during real-time dispatching to ensure safe operation of the electricity system.

5. During the process of real-time dispatching, the electricity system and market operator shall announce day-ahead mobilization schedules, obligations for electricity system security affecting day-ahead mobilization schedules, mobilization schedules in transaction cycles and methods of real time dispatching along with explanations of any changes.

Article 84. Real-time dispatching

1. The purpose of real-time dispatching

a) Ensure real-time dispatching of generating sets and ancillary services is carried out in an apparent way for the parties involved in the electricity market;

b) Ensure the electricity system operates in a safe, stable and reliable manner as prescribed.

2. Principles of real-time dispatching

a) The electricity system and market operator shall be responsible for operating and dispatching electricity system in real time, issuing dispatch instruction and complying with relevant procedures and regulations. The schedules of real-time mobilization of generating sets must meet obligations for electricity system security and minimize expenses for the entire system;

b) The real-time dispatching of electricity system must be based on day-ahead mobilization schedules and schedules for real-time mobilization of generating sets. In case of emergency, to ensure electricity system security, the electricity system and market operator has the right to operate the electricity system not in accordance with the schedules of real-time mobilization of generating sets. Such changes must be recorded in the operation diary and reported to relevant parties;

c) The units involved in the electricity market must comply with dispatch instruction of the electricity system and market operator;

d) Dispatch instructions must be recorded in the dispatch diary, tape recorder and database of the electricity system operation management software;

dd) After the real-time operation, the electricity system and market operator must publish information concerning dispatch instruction, operation of electricity system on its website.

Article 85. Methods of real-time operation of electricity system

1. Operation method in a normal and warning mode

The system and market operator shall be responsible for ensuring supply - demand balance in real time by issuing dispatch instruction and operation actions based on day-ahead transaction cycle mobilization schedules;

2. Operation in an emergency mode

a) If the measures prescribed in Point b, Clause 1, this Article have been taken but the electricity system fails to return to normal operation, the electricity system and market operator shall be responsible for mobilizing generating sets to provide quick-start reserve services based on day-ahead transaction cycle mobilization schedules and ensure minimization of expenses for the entire system;

b) The electricity system and market operator shall be responsible for publishing mobilization schedules of ancillary services on its website according to the regulation on competitive electricity market operation.

Section 6. COORDINATION IN OPERATION, EXCHANGE OF INFORMATION AND OPERATIONAL REPORTING MODES

Article 86. General responsibility for operation coordination

1. The transmission network operator and the customer using transmission grid must reach an agreement on responsibility and scope of operation of the equipment on the transmission grid between the two parties;

2. The transmission network operator and the customer using transmission grid must coordinate and share information, establish and maintain communication and implement necessary safety measures during trial operation within management.

3. The transmission network operator and the customer using transmission grid shall construct operation coordination procedure to ensure safety of people and equipment in the operation, maintenance and repair.

4. When carrying out the tasks on the electrical grid, the transmission network operator and customer using transmission grid must comply with regulations on safety operation coordination and other regulations.

5. The transmission network operator and the customer using transmission grid shall be responsible for coordinating installation of signs, warning equipment and safety instructions.

6. Inspection, monitoring and control of connection equipment at borders of assets shall be carried out by operators of the transmission network operator and customer using transmission grid.

7. Relevant units shall be responsible for coordinating safe operation to ensure compliance with regulations on safe operation of transmission grid, electrical equipment connecting to the transmission grid.

Article 87. Exchange of information

1. The electricity system and market operator shall be responsible for handling incidents which affect safe and reliable operation of the national electricity transmission system.

2. The transmission network operator and the customer using transmission grid shall be responsible for making notification to the electricity system and market operator, the dispatch level and relevant units of any events or incidents within management which may affect safe and reliable operation of the national electricity system.

3. Upon receipt of notification as prescribed in Clause 2, this Article, the electricity system and market operator, the dispatch level shall cooperate with the transmission network operator and the customer using transmission grid in investigating and verifying the causes and putting forward handling measures. The transmission network operator and the customer using transmission grid shall provide relevant information, answer questions and requests made by the electricity system and market operator and the dispatch level. The customer using transmission grid shall provide incident-related information to the transmission network operator for analysis and handling of the incident within management of the customer.

4. Requirements for content of notifications, reports or other information as prescribed in Clause 2 and Clause 3, this Article include:

a) Name and position of the person who gives the notification, makes the report or answers the questions, time of notification, reporting or answering the questions;

b) Information concerning operation, incidents or risks;

c) Verbal or oral reports on the incident or answers to the questions. Reports on incidents or answers to questions must include:

- Information concerning the causes, effects or damage caused by the incident, accidents or casualties; remedial measures and results of implementation of such measures;

- If an incident can be remedied immediately, the report is made orally;

- If the incident happens in a factory, the report must be made by such factory. If an incident happens in the electricity system connecting to the national transmission grid, the customer using transmission grid shall make a report on such incident or answer the questions; if an incident happens on the national transmission grid, the transmission network operator shall make the report or answer the questions.

Article 88. Confidentiality

All the information concerning the operation process or incident handling shall be provided to a third party in following cases:

1. Cases stipulated by laws.

2. As agreed between the customers using transmission grid or agreed by the dispatch level.

3. Third party is the customer who is connected to the national transmission grid and provided with information by the dispatch level.

Article 89. Reporting of incidents in national electricity system

1. The dispatch level, the transmission network operator and the customer using transmission grid shall be responsible for performing the reporting of incidents according to the incident handling procedure issued by the Ministry of Industry and Trade.

2. In addition to the reporting of incidents in the national electricity system as prescribed in Clause 1, this Article, the electricity system and market operator and the dispatch level shall be responsible for performing the reporting of incidents as follows:

a) For a lasting incident on the electricity transmission system from 220 kV and over that causes damage to the equipment or an incident occurring to the national electricity system that causes extensive outage in a province, a central-affiliated city or an incident that results in load shedding with capacity from 200 MW and over, report the incident to the Electricity Regulatory Authority via texting or email after the element of incident in the national electricity system is isolated.

b) Within 36 hours since the incident happens, the dispatch level shall send the report to the Electricity Regulatory Authority according to the form in Annex 3 enclosed with the incident handling procedure issued by the Ministry of Industry and Trade;

c) Before 20^th every month, the electricity system and market operator shall make a review report of incidents according to the form in Annex 4 enclosed with the incident handling procedure issued by the Ministry of Industry and Trade (for incidents subject to analysis and scrutiny) and incidents of last month to the Electricity Regulatory Authority by post or via email in following cases:

- Lasting incidents on 500 kV electrical grid;

- Lasting incidents on 220 kV, 110 kV electrical grids and power plants cause extensive outage in a province, central-affiliated city or a district of Hanoi Capital and Ho Chi Minh City or a load shedding with capacity from 200 MW and on or have direct impact on the operation of the power plant involved in the competitive electricity market.

Article 90. Reporting of performance of transmission grid

1. The transmission network operator shall be responsible for making regular reports on following matters:

a) Operation of transmission grid;

b) Assessment of implementation of operation standards prescribed in Chapter II herein;

c) Overloads, incidents and causes, proposal for measures to ensure safe and reliable operation of the electrical grid;

d) Performance quality assessment indices prescribed in Article 98 herein and explanations of reasons for not meeting the indices;

dd) Connection of SCADA of transformers to the dispatch level.

2. Regular reports

a) Before January 15 annually, the transmission network operator shall be responsible for reporting operation of transmission grids from last year including matters prescribed in Clause 1, this Article to the Electricity Regulatory Authority and the electricity system and market operator.

b) Before 15^th every month , the transmission network operator shall be responsible for reporting operation of transmission grids from last month including matters prescribed in Clause 1, this Article to the Electricity Regulatory Authority and the electricity system and market operator.

3. The transmission network operator shall be responsible for making irregular reports on operation of transmission grids at the request of the Electricity Regulatory Authority, the Service of Industry and Trade, Vietnam Electricity and the electricity system and market operator.

Article 91. Reporting of operation plan and result of operation of national electricity system

1. The electricity system and market operator shall be responsible for making regular reports to the Electricity Regulatory Authority on the national electricity system operation plans next year, next month and next week including plans for maintenance and repair of equipment and assessment of electricity system security as prescribed herein.

2. The electricity system and market operator shall be responsible for making regular reports on operation of the national electricity system on an annual, monthly basis including following matters:

a) Structure of mobilization of power supplies, total installed and available capacity of power supplies; progress of operation of new power supplies and electrical grids;

b) Assessment of implementation of operation standards prescribed in Chapter II herein;

c) Assessment of demand for loads and consumption of power, tolerance of load forecasting;

d) Assessment of result of operation of transmission grids, incidents and causes, proposal for measures to ensure safe and reliable operation of the electrical system;

dd) Performance quality assessment indices prescribed in Article 97 herein and explanation of reasons for not meeting the indices;

e) Statistical figures about supply of fuel, hydrographical conditions of hydroelectric reservoirs, mobilization of power plants; incidents to power supplies and electrical grids;

g) Connection of SCADA of power plants and transformers within control authority.

3. Regular reports

a) Before January 31 annually, the electricity system and market operator shall be responsible for reporting operation of the national electricity system from last year including matters prescribed in Clause 2, this Article to the Electricity Regulatory Authority.

b) Before 25^th every month, the electricity system and market operator shall be responsible for reporting operation of the national electricity system from last month including matters prescribed in Clause 2, this Article to the Electricity Regulatory Authority.

4. The electricity system and market operator shall be responsible for making irregular reports on operation of national electricity system to the Electricity Regulatory Authority.

Chapter VII

ASSESSMENT OF ELECTRICITY SYSTEM SECURITY

Article 92. General provisions on assessment of electricity system security

1. The electricity system and market operator shall be responsible for carrying out the assessment of electricity system security serving the formulation of national electricity system operation plan next year, next month, next week, formulation of day, hour-ahead mobilization schedules and real-time dispatching.

2. The transmission network operator and the customer using transmission grid shall be responsible for providing full information concerning the assessment of electricity system security to the electricity system and market operator. The information includes: Load forecasts, operation plan, plan for maintenance and repair of electrical grids, power plants, transmission capacity on transmission grids, available and announced capacity of generating sets, energy obligations and other necessary relevant information.

3. Assessment of electricity system security includes calculation, analysis and announcement of total expected available capacity, load forecasts of the electricity system, assessment of reliability and readiness of the electricity system to meet demand for load forecasts, warnings on electricity system security and other requirements for electricity system security. Assessment of electricity system security includes medium- and short-term assessment stipulated as follows:

a) Medium-term assessment includes:

- Annual assessment: To be carried out to assess ability to ensure national electricity system security for the next year (year N+1) and the year thereafter (year N+2). Unit of calculation is month;

- Assessment of electricity system security for the next 12 months: To be carried out from July to end of June in the next year (year N+1) to assess ability to ensure national electricity system security for the next 12 months. Unit of calculation is month;

- Monthly assessment: To be carried out to assess ability to ensure national electricity system security for the remaining months of the year. Unit of calculation is month;

- Weekly assessment: To be carried out to assess ability to ensure national electricity system security for the remaining weeks of current month and weeks of next month. Unit of calculation is week;

b) Short-term assessment: To be carried out to assess ability to ensure national electricity system security for the next two weeks. Unit of calculation is hour;

4. Result of assessment of electricity system security is grounds for relevant units to take initiative in the formulation of the plan for power generation, maintenance and repair of equipment, participation in adjusting supply and demand balance of the electricity system.

5. To serve the assessment of electricity system security, the transmission network operator and the customer using transmission grid must register the plan for maintenance and repair of electrical grids, electrical equipment and power supplies with the electricity system and market operator.

6. If the plan for maintenance and repair of electrical grids and power supplies is found to have threaten electricity system security, the electricity system and market operator has the right to refuse such plan and specify the reasons for refusal.

7. The refusal shall be based on the determination of impacts of the plan on electricity system security.

Article 93. Reserve capacity and electrical energy of electricity system

1. The electricity system and market operator shall be responsible for calculating and determining reserve capacity and electrical energy of the national electricity system during the calculation of ancillary services and assessment of electricity system security.

2. During the formulation of the method for calculation of reserve capacity and electrical power, the electricity system and market operator must ensure following principles:

a) Determination of appropriate reserve capacity

- Reserve capacity is the difference between total forecast available generating capacity of a generating set in the electricity system and forecast maximum capacity of loads of electricity system at the same time;

- Optimal reserve capacity is reached when the marginal cost of shortage of electrical energy caused by the incident to power supplies, changes to primary fuel and sudden increase of loads is equal to the marginal cost of mobilizing quick-start reserve to make up for such shortage;

- Appropriate reserve capacity is the optimal reserve capacity with account taken of changes of loads and generating set obligations in the electricity system.

b) Determination of appropriate reserve electrical energy

- Reserve electrical energy is the difference between total forecast available electrical energy of a generating set in the electricity system and forecast electrical energy of loads of the electricity system at the same time;

- Optimal reserve electrical energy is reached when the marginal cost of shortage of electrical energy caused by the incident to power supplies, changes to primary fuel and sudden increase of loads is equal to the marginal cost of mobilizing quick-start reserve to make up for such shortage;

- Appropriate reserve electrical energy is the optimal reserve electrical energy with account taken of changes of loads and generating set obligations in the electricity system;

3. Input elements used for the calculation of reserve capacity and electrical energy in following cases:

a) Calculation of reserve capacity serving the formulation of plan for mobilization of quick-start reserve including:

- Registered generating capacity of generating sets of a power plant that has signed a long-term PPA;

- Failure rate of each generating set shall be determined based on statistical figures or calculations made by the electricity system and market operator for such generating sets;

- Load forecasts calculated by the electricity system and market operator are prescribed in Chapter III herein;

- The cost of shortage of electrical energy shall be determined through probability and statistics in case the demand for loads is greater than total available capacity of power supplies and value of lost load calculated by the electricity system and market operator.

b) Calculation of reserve capacity serving plans for temporary suspension and reduction of power supply and load shedding including:

- Announced available generating capacity of generating sets of a power plant;

- Failure rate of each generating set shall be determined based on statistical figures or calculations made by the electricity system and market operator for such generating sets;

- Load forecasts calculated by the electricity system and market operator are prescribed in Chapter III herein;

- The cost of shortage of electrical energy shall be determined through probability and statistics in case the demand for loads is greater than total available capacity of power supplies and value of lost load calculated by the electricity system and market operator.

c) Calculation of reserve electrical energy serving the formulation of the plan for mobilization of must-run operation reserve to ensure electricity system security, including:

- Registered capacity of generating sets of a thermo power plant that executes a long-term PPA or the contract for fast-start reserve service with corresponding failure rate;

- Failure rate of each generating set shall be determined based on statistical figures or calculations made by the electricity system and market operator for such generating sets;

- Forecast changes to electrical production of thermo power plants shall be based on past figures or actual hydrographical figures;

- Load forecasts calculated by the electricity system and market operator are prescribed in Chapter III herein;

- The cost of shortage of electrical energy shall be determined through probability and statistics in case the demand for loads is greater than total available capacity and value of lost load calculated by the electricity system and market operator.

d) Calculation of reserve electrical energy serving plans for temporary suspension and reduction of power supply and load shedding including:

- Announced electrical energy of generating sets of a power plant over stages;

- Failure rate of each generating set shall be determined based on statistical figures or calculations made by the electricity system and market operator for such generating sets;

- Forecast changes to electrical production of thermo power plants shall be based on past figures or actual hydrographical figures;

- Load forecasts calculated by the electricity system and market operator are prescribed in Chapter III herein;

- The cost of shortage of electrical energy shall be determined through probability and statistics in case the demand for loads is greater than total available capacity and value of lost load calculated by the electricity system and market operator.

4. Annually, the electricity system and market operator shall be responsible for calculating reserve capacity and electrical energy ensuring appropriate reserve capacity and electrical energy and provisions laid down herein, reporting to the Electricity Regulatory Authority for approval.

5. During the assessment and grant of approval for reserve capacity and electrical energy, the Electricity Regulatory Authority shall be responsible for collecting suggestions from relevant parties on following issues:

a) Impacts of cost of ancillary services;

b) Impacts on requirements for operation of the electricity system;

c) Impacts on quality of power supply;

d) Assessment of the correlation between cost of power supply and quality of power supply.

Article 94. Assessment of medium-term assessment of electricity system security

1. Annually, the electricity system and market operator shall carry out calculation and announcement of result of assessment of electricity system security.

2. In June annually, the electricity system and market operator shall carry out calculation and announcement of assessment of electricity system security for the next 12 months.

3. Every month, the electricity system and market operator shall carry out calculation and announcement of monthly assessment of electricity system security.

4. Every week, the electricity system and market operator shall carry out calculation and announcement of weekly assessment of electricity system security.

5. Input information for medium-term assessment of system security:

a) Load forecasts of national and regional electricity systems including maximum capacity and consumed electrical production;

b) Weekly load profile of national and regional electricity systems;

c) Plans for maintenance and repair of power supplies and electrical grids;

d) Approved weekly electrical energy of hydroelectric reservoirs;

dd) Incidents to generating sets and transmission grids;

e) Requirements for ancillary services of the national electricity system;

g) Electrical grid obligations.

6. The generating units shall be responsible for providing the electricity system and market operator with the input information serving the medium-term assessment of electricity system security including:

a) Expected plan for maintenance and repair;

b) Weekly available capacity of generating sets;

c) Weekly energy obligations (if any) of generating sets. This information shall be provided according to the form published on the electricity system and market operator’s website.

7. The transmission network operator shall be responsible for providing the electricity system and market operator with the expected plan for maintenance and repair of transmission grids and input information serving the medium-term assessment of electricity system security. If the plan for maintenance and repair of transmission grid has effect on power generating capacity of generating sets, the electricity system and market operator has the right to make adjustment to the power generating capacity of such generating sets and making notification of changes and obligations of transmission grids to generating units.

8. Electricity distribution units shall be responsible for providing load forecasts at 110 kV transformers on the distribution grids to the electricity system and market operator.

9. The information concerning medium-term assessment of electricity system security published by the electricity system and market operator includes:

a) Total available capacity and electrical energy with account taken of energy obligations of generating sets, plans for maintenance and repair of transmission grids and generating sets;

b) Requirements for ancillary services of the national electricity system;

c) Reserve capacity and electrical energy of the national electricity system

d) Expected obligations of transmission grids;

dd) Warnings about decline in electricity supply security (if any).

10. Upon finding that reserve capacity and electrical energy is lower than the approved reserve level as prescribed in Article 93 herein, the electricity system and market operator has the right to reject plans for maintenance and repair by electricity transmission units and generating units.

11. In case of rejection, within seven days since receipt of the rejection, the affected units may submit a modification plan to the electricity system and market operator for consideration.

12. The electricity system and market operator shall be responsible for making calculations and regular updates on medium-term assessment of electricity system security. When reserve capacity, electrical energy and electricity system security level is met, the electricity system and market operator shall grant approval for the modification plan.

Article 95. Assessment of short-term assessment of electricity system security

1. Prescribed time for short-term assessment of electricity system security is the next 14 days since 24:00 on the day of announcement of short-term assessment to 24:00 on the next 14^th day. The unit of calculation if hour.

2. Every day, the electricity system and market operator shall be responsible for making public announcement of short-term assessment of electricity system security.

3. Input information for short-term assessment of system security:

a) Load forecasts of national and regional electricity systems including maximum capacity and consumed electrical production;

b) Plans for maintenance and repair of power supplies and electrical grids;

c) Failure rate of generating sets and transmission grids;

d) Requirements for ancillary services of the national electricity system;

dd) Electrical grid obligations.

4. The generating units shall be responsible for providing the electricity system and market operator with the input information serving short-term assessment of electricity system security including:

a) Plans for maintenance and repair of equipment;

b) Available capacity of generating sets in each transaction cycle;

c) Announced capacity of generating sets in each transaction cycle;

d) Time for starting and stopping slow-start generating sets;

dd) Lowest stable generating capacity of generating sets.

5. The transmission network operator shall be responsible for making notification to the electricity system and market operator for making updates on the plan for maintenance and repair of transmission grids. If the plan for maintenance and repair of transmission grid has effect on power generating capacity of generating sets, the electricity system and market operator has the right to make adjustment to the power generating capacity of such generating sets and making notification of changes and obligations of transmission grids to generating units.

6. Electricity distribution units shall be responsible for providing load forecasts at 110 kV transformers on the distribution grids to the electricity system and market operator.

7. The information concerning medium-term assessment of electricity system security published by the electricity system and market operator includes:

a) Total available capacity and electrical energy with account taken of plans for maintenance and repair of transmission grids;

b) Load forecasts in national electricity system

c) Requirements for ancillary services;

d) Reserve capacity and electrical energy of electricity system;

dd) Expected obligations of transmission grids;

e) Warnings about decline in electricity supply security (if any).

8. Upon finding that reserve capacity and electrical energy level or local electricity system security is not ensured, the electricity system and market operator has the right to reject plans for maintenance and repair by electricity transmission units and generating units.

9. In case of rejection, within seven days since receipt of the rejection, affected units may submit a modification plan to the electricity system and market operator for consideration.

10. The electricity system and market operator shall be responsible for maintaining updates on short-term assessment of electricity system security. When reserve capacity, electrical energy and local electricity system security level is met, the electricity system and market operator shall grant approval for the modification plan.

Chapter VIII

ASSESSMENT OF QUALITY OF OPERATION OF ELECTRICITY TRANSMISSION SYSTEM

Article 96. General requirements

1. On a monthly and annual basis, the electricity system and market operator and the transmission network operator shall be responsible for reporting operation of the national electricity system, transmission grids and implementation of operation quality standards to the Electricity Regulatory Authority.

2. Performance indicators prescribed in this Chapter is one of the performance indicators for the Electricity Regulatory Authority to assess quality of dispatching and operation of the electricity transmission system by the electricity system and market operator and transmission network operator. If the performance indicator of the year N+1 is lower than that of the year N, the electricity system and market operator and the electricity transmission unit shall be responsible for making explanations and taking measures to improve the performance indicators for the next year.

Article 97. Performance indicators of electricity system and market operator

On a monthly and annual basis, the electricity system and market operator shall be responsible for reporting and publish following performance indicators on the website of the Electricity Regulatory Authority:

1. Number of times the national electricity system frequency exceeds permissible frequency band and the time for restoration to normal operation modes in case of incidents as prescribed in Article 4 herein.

2. Electrical grid readiness index, voltage deviation index and frequency deviation index.

3. Total monthly expense for ancillary services.

4. Mobilized capacity and actual mobilization time of each ancillary service.

5. Number of times and period of time when types of ancillary services fail to meet requirements for reserve capacity and electrical energy as prescribed in Article 93 herein.

6. Tolerance of annual, monthly, weekly and daily load forecasts compared with actual loads.

Article 98. Performance indicators of transmission network operator

1. On a monthly basis, the electricity system and market operator shall be responsible for reporting and publish following performance indicators on the website on the Electricity Regulatory Authority:

a) Statistical report on overloads of equipment on transmission grid (overload level and time);

b) Statistical report on outage of transmission grid including:

- Number of times of suspension and reduction of power supply with and without plans;

- Time for starting and stopping suspension and reduction of power supply.

c) Statistical report on busbars on transmission grids of voltage failing to meet the standards as prescribed in Article 6 herein, including:

- Statistical report on over-voltage, low voltage compared with the provisions laid down in Article 6 herein;

- Time of starting and ending each violation of the voltage standard;

- Highest and lowest voltage when the voltage standard is violated;

- Irregular events when the voltage standard is violated.

d) Issues concerning reliability of transmission grids as prescribed in Article 14 herein;

dd) Monthly loss of electrical energy on transmission grid by voltage level;

e) List of incidents leading to violation of transmission grid operation standards as prescribed in Chapter II herein. Make reports and explanation of causes of violation and proposals for changes to meet operation technical standards.

2. On an annual basis, the electricity system and market operator shall be responsible for reporting and publishing following performance indicators on the website of the Electricity Regulatory Authority:

a) Ratio of investment and construction by voltage level compared with approved annual plan for development of transmission grids;

b) Total number of overloaded equipment on transmission grid in the year;

c) Total number of suspension and reduction of power supply with and without plans on transmission lines and transformers;

d) Total number of times and total period of time of violation of the voltage standard as prescribed in Article 6 herein;

dd) Issues concerning reliability of transmission grids as prescribed in Article 14 herein;

e) Loss of electrical energy on transmission grid by voltage level;

g) Total number of irregular incidents leading to violation of transmission grid operation standards.

Chapter IX

SETTLEMENT OF DISPUTES AND HANDLING OF VIOLATION

Article 99. Settlement of disputes

1. A dispute between relevant units may be settled among themselves within 60 days through negotiation.

2. If the dispute cannot be settled after the time limit as prescribed in Clause of this Article, the relevant units  may bring the case to the Electricity Regulatory Authority for handling according to laws.

3. The decision on dispute settlement by the Electricity Regulatory Authority is final except for disputes related to agreement or contract signed between the parties.

Article 100. Handling of violation

1. Every organization and individual has the right to report violating acts to the Electricity Regulatory Authority as prescribed herein.

2. A report on a violation must include following information:

a) Reporting date;

b) Name and address of organization and/or individual that makes the report;

c) Name and address of organization and/or individual that commits acts showing signs of violation;

d) Description of behaviors showing signs of violation;

dd) Reasons for detecting signs of violation (if any);

e) Other relevant information (if any).

The specimen report prescribed in the procedure for verification and punishment of administrative violations in the area of electricity within competence of head of the Electricity Regulatory Authority.

3. The Electricity Regulatory Authority has the right to request relevant parties to provide information concerning violating acts during the verification and punishment of violation.

Chapter X

IMPLEMENTATION

Article 101. Implementation

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

2. In case of necessity, the Electricity Regulatory Authority shall formulate and issue detailed instructions on technical requirements, connection requirements and methods of forecasting generating capacity and electrical energy of solar power plants, wind power plants connecting to transmission grids in accordance with the provisions prescribed herein and technical characteristics of power plants.

3. The Vietnam Electricity shall be responsible for directing subsidiaries to implement this Circular. Within six months since this Circular is issued, the Vietnam Electricity shall construct and submit technical regulations as instructions on the implementation of this Circular to Electricity Regulatory Authority for promulgation, including:

a) Procedure for national electricity system load forecasting;

b) Procedure for formulation of plans for maintenance and repair of electrical grids and power plants in the national electricity system;

c) Procedure for medium and short-term assessment of electricity system security;

d) Procedure for formulation of national electricity system operation plan;

dd) Procedure for determination and operation of ancillary services;

e) Technical requirements for protective relay and automation system in power plants and transformers;

g) Regulations on technical and operational requirements of SCADA;

h) Procedure for trial operation and monitoring;

i) Procedure for load shedding in the national electricity system.

4. The transmission network operator and customer using transmission grids shall be responsible for formulating plans for investment, upgrading and renovation of electrical grids, electrical equipment within management to ensure satisfaction of technical and operational requirements as prescribed herein.

Article 102. Effect

1. This Circular takes effect since January 16, 2017. The Minister of Industry and Trade’s Circular No. 12/2010/TT-BCT dated April 15, 2010 stipulating electricity transmission system shall become invalid since the effective date of this Circular.

2. For any contract for procurement and installation of equipment that was signed before June 01, 2010 with terms and conditions other than the provisions prescribed in the Circular No. 12/2010/TT-BCT dated April 15, 2010 or before the effective date of this Circular with terms and conditions other than the provisions prescribed herein, the transmission network operator and the customer using transmission grids shall be allowed to continue the implementation of the signed contract.

3. Difficulties that arise during the implementation of this Circular should be reported to the Electricity Regulatory Authority or the Ministry of Industry and Trade for consideration and handling./