CIRCULAR

Article 24defines the distribution power system

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

Pursuant to the Electricity Law dated December 3, 2004;

Pursuant to Decree No. 105/2005/NĐ-CP dated August 17, 2005 of the Government detailing and guiding the implementation of certain provisions of the Electricity Law;

Based on Decision No. 26/2006/QD-TTg dated January 26, 2006, of the Government Chairman regarding the approval of the roadmap, conditions for the formation and development of various levels of electricity market in Vietnam;

The Ministry of Industry and Trade stipulates the distribution power system as follows:

PART I

GENERAL PROVISIONS

Article 1. Scope of application

This Circular stipulates on:

1. Operating standards for the distribution power system.

2. Investment in developing the distribution grid.

3. Forecasting electricity demand.

4. Conditions and procedures for connecting to the distribution grid.

5. Dispatching and operating the distribution power system.

6. Measuring electricity at points of delivery between the distribution grid and power plants connected to the distribution grid that do not participate in competitive power generation markets and customers using the distribution grid.

Article 2. Applicability

This Circular applies to the following subjects:

1. Distribution utility;

2. Customer using the distribution grid;

3. Vietnam Electricity Corporation.

Article 3. Explanation of Terms

Strategic multi-purpose hydropower plant

1. Voltage level is one of the values of the nominal voltage used in the power system, including:

a) Low voltage is the nominal voltage below 1000V;

b) Medium voltage is the nominal voltage from 1000V to 35kV;

c) High voltage is the nominal voltage above 35kV up to 220kV;

d) Extra-high voltage is the nominal voltage above 220kV.

2. Current transformer (CT) is a device that transforms current, expanding the range of measuring current and energy for the electrical metering system.

3. Voltage transformer (VT) is a device that transforms voltage, expanding the range of measuring voltage and energy for the electrical metering system.

4. Available generating capacity of a generator is the maximum actual generating capacity of a generator that can operate stably and continuously over a defined period of time.

5. Voltage fluctuation is the variation in amplitude of voltage compared to the nominal voltage over a time longer than one (01) minute.

6. Point of interconnection is the point where customer equipment, grids, and power plants connect to the distribution grid.

7. Distribution utility is an electric power entity licensed to operate in the distribution sector, receiving electricity directly from the transmission grid to sell to electricity users or other distribution and retail entities.

8. Distribution and retail electricity entity is an electric power entity licensed to operate in the distribution and retail sector, purchasing wholesale electricity from distribution utilities to sell retail electricity to electricity users.

9. Transmission utility is a power company licensed to operate in the electricity transmission sector, responsible for managing and operating the national transmission grid.

10. System operator and electricity market operator is an entity commanding and controlling the process of power generation, transmission, and distribution in the national power system, managing and coordinating transactions of electricity purchase and sale and ancillary services on the electricity market.

11. Ground fault factor is the ratio between the value of the phase voltage that has not experienced a ground fault after a ground fault occurs and the value of that phase before the ground fault occurs (applicable to single-phase or two-phase ground faults).

12. Distribution power system is a power system consisting of the distribution grid and power plants connected to the distribution grid.

13. Metering system is a system comprising metering devices and circuits integrated to measure and determine the amount of electrical energy transmitted through a metering point.

14. SCADA system (Supervisory Control And Data Acquisition) is a system for collecting data to serve the monitoring, control, and operation of the power system.

15. Electricity user is an organization or individual purchasing electricity from the distribution grid for use, without reselling it to other organizations or individuals.

16. Customer using the distribution grid is an organization or individual with electrical equipment and grid connected to the distribution grid to use distribution services, including:

a) Electricity user;

b) Organization or individual owning power plants connected to the distribution grid;

c) Distribution and retail electricity entity.

17. Customer using the distribution grid with its own substation is a customer with its own substation and grid connected to the distribution grid at medium voltage and 110kV levels.

18. Large customer using the distribution grid is a customer using the distribution grid owning power plants with installed capacity and electricity users with consumption scale as specified by the Electricity Regulatory Authority. 19. Distribution grid

is part of the grid consisting of lines and substations with voltage levels up to 35kV, lines and substations with 110kV voltage level for distribution purposes. 20. Transmission grid

is part of the grid consisting of lines and substations with voltage levels from 220kV upwards, lines and substations with 110kV voltage level for transmission purposes to receive power from power plants into the national power system. 22. Planned power outage is the interruption of power supply to electricity users to carry out planned maintenance, repair, major overhaul, construction of power facilities; load adjustment and limitation due to planned power shortage announced by the system operator and electricity market operator.

23. Short-term voltage flicker level (P st

) is the value measured over a ten (10) minute period using standard measuring equipment according to IEC868. st95%

is the threshold value of P_{such that within 95% of the measurement time (at least one week) and 95% of the measurement locations, P}does not exceed this value.

"5. The pre-tax weighted average cost of capital i (%) is determined according to the formula below:_{24. Long-term voltage flicker level (P} lt_{such that within 95% of the measurement time (at least one week) and 95% of the measurement locations, P} calculated from twelve consecutive results of P_{such that within 95% of the measurement time (at least one week) and 95% of the measurement locations, P} measurements (over a two (02) hour period), according to the formula

lt95%_{25. Grid collapse}) is a failure causing disconnection between power plants and substations leading to partial or total blackout of the regional or national power system._{such that within 95% of the measurement time (at least one week) and 95% of the measurement locations, P} 26. Operational boundary

 

"5. The pre-tax weighted average cost of capital i (%) is determined according to the formula below:_{is the boundary defining the operational responsibility for the grid or electrical equipment between the distribution utility and the customer using the distribution grid or other distribution utilities.} lt_{25. Grid collapse} calculated from twelve consecutive results of P_{25. Grid collapse} measurements (over a two (02) hour period), according to the formula

27. Shedding load is the incident causing the disconnection between power plants and substations, leading to partial or complete power outage in the regional or national electricity system.

26. Operational Boundary is the boundary defining the operational responsibility for the power grid or electrical equipment between the Distribution Unit and the Customer using the distribution network or with other Distribution Units.

27. Load Shedding are ||| The process of disconnecting loads from the power grid when there is an incident in the power system or during short-term local overload to ensure safe operation of the power system, carried out through an automatic load shedding system or dispatch orders.

28. Harmonic waves are sine voltage and current waves with frequencies that are multiples of the fundamental frequency.

29. Disconnection at point of interconnection is the act of disconnecting the distribution network or electrical equipment of customers using the distribution network from the distribution network at the point of interconnection.

30. Measuring devices are devices including meters, current transformers, voltage transformers, and auxiliary devices for measuring electricity consumption.

31. Interconnection agreement is the written agreement between the Distribution Company and the customer using the distribution network with its own substation to connect the customer's electrical equipment to the distribution network.

32. IEC Standards are electrical engineering standards issued by the International Electrotechnical Commission.

33. Measurement Point is the physical location on the circuit where electricity purchase and sale quantities are measured and determined.

Chapter II

DISTRIBUTION SYSTEM OPERATING STANDARDS

Section 1

TECHNICAL STANDARDS

Article 4. Frequency

The rated frequency in the national power system is 50Hz. Under normal conditions, the system frequency fluctuates within ±0.2Hz of the rated frequency. In cases where the system has not stabilized, the system frequency can fluctuate within ±0.5Hz of the rated frequency. ±Article 5. Voltage ±1. Rated Voltage

The rated voltages in the distribution system include 110kV, 35kV, 22kV, 15kV, 10kV, 6kV, and 0.4kV.

2. During normal operation, the allowable voltage fluctuations at the point of interconnection compared to the rated voltage are as follows:

a) At the point of interconnection with customers consuming electricity is ±10%.

b) At the point of interconnection with power plants is +10% and -5%.

3. During single fault conditions or during the recovery process to stable operation following a fault, voltage fluctuations at the point of interconnection with customers directly affected by the fault are allowed within ±5% of the rated voltage. ±5%;

4. During severe transmission system faults or fault recovery, voltage fluctuations are allowed within ±10% of the rated voltage.

5. In cases where customers using the distribution network require higher voltage quality than specified, customers using the distribution network may agree on different voltage fluctuation values at the point of interconnection from those stipulated in Clause 2 of this Article.

Article 6. Phase Balance ± In normal operating conditions, the inverse sequence component of phase voltage does not exceed 3% of the rated voltage for the 110kV level or 5% of the rated voltage for medium and low voltage levels.

Article 7. Harmonic Waves

1. Total harmonic distortion (THD) is the ratio of the effective value of the harmonic voltage to the effective value of the fundamental voltage, expressed in percentage (%), according to the formula below: THD

Total harmonic distortion of voltage;

Harmonic voltage component at the i-th order

Fundamental frequency voltage component (50Hz)

 

Where:

 

 

110kV

Medium and low voltage

3. Permitting peak transient voltage anomalies on the distribution network for a short period exceeding the total harmonic distortion level specified in Clause 2 of this Article but not causing damage to the customer's distribution network equipment.

Article 8. Voltage Fluctuation

1. Under normal operating conditions, the level of voltage fluctuation at all connection points shall not exceed the limits specified in Table 2 as follows Table 2: Level of Voltage Fluctuation:

Permitted Voltage Fluctuation Level

Article 9. Short Circuit Current and Fault Clearance Time_{such that within 95% of the measurement time (at least one week) and 95% of the measurement locations, P}1. The maximum allowable short circuit current and fault clearance time are specified in Table 3 as follows:_{25. Grid collapse}Table 3: Maximum Allowable Short Circuit Current and Fault Clearance Time

Maximum Short Circuit Current (kA)

Fault Clearance Time (ms)

Equipment Endurance Time

The neutral grounding system in the distribution network is specified in Table 4 as follows:

Grounding System

Neutral Point

Direct Grounding

Isolated Neutral or Grounded Through Impedance

Table 4: 15, 22 kV

 

 

Article 11. Coefficient Article 12. Reliability Indices of the Distribution Network 1. The reliability indices of the distribution network include:

a) The average duration index of power outages in the distribution network (System Average Interruption Duration Index - SAIDI);

Section 2

b) The average frequency index of power outages in the distribution network (System Average Interruption Frequency Index - SAIFI);

c) The average frequency index of momentary power outages in the distribution network (Momentary Average Interruption Frequency Index - MAIFI).

2. The reliability indices of the distribution network are calculated as follows:

a) SAIDI is calculated by dividing the total outage duration of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in a quarter by the total number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in that quarter, according to the following formula:

: Duration of outage i lasting more than 5 minutes in quarter j;

: Number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit affected by outage i in quarter j;

n: number of outages lasting more than 5 minutes in quarter j;

K: Total number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in quarter j.

 

Where:

T_{ANNEX I.A[31]}b) SAIFI is calculated by dividing the total number of outages of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in a quarter by the total number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in that quarter, according to the following formula:

ảo_{ANNEX I.A[31]}K: Total number of customers in quarter j of the distribution unit.

c) MAIFI is calculated by dividing the total number of momentary outages of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in a quarter by the total number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in that quarter, according to the following formula:

m: number of momentary outages in quarter j;

b) SAIFI is calculated by dividing the total number of outages experienced by electricity users and distribution and retail electricity units purchasing electricity from the distribution unit in the quarter by the total number of electricity users and distribution and retail electricity units purchasing electricity from the distribution unit in that quarter, according to the following formula:

Where:

c) MAIFI is calculated by dividing the total number of momentary outages of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in a quarter by the total number of electricity customers and electricity distribution and retail units purchasing electricity from the distribution unit in that quarter, according to the following formula:

K: Total number of customers in quarter j of the Distribution Unit.

c) MAIFI is calculated by dividing the total number of momentary outages experienced by electricity users and distribution and retail electricity units purchasing electricity from the distribution unit in the quarter by the total number of electricity users and distribution and retail electricity units purchasing electricity from the distribution unit in that quarter, according to the following formula:

 

Where:

m: Number of momentary outages in quarter j;

m: number of momentary outages in quarter j;

Article 13. Cases of power supply interruption not considered when calculating reliability indices

1. Customers request disconnection of power supply.

2. Equipment of customers using distribution networks does not meet technical standards and safety requirements for resuming power supply.

3. Due to equipment failure of customers using distribution networks.

4. Due to power outage from transmission networks.

5. Shedding load according to dispatch orders of system operation units and electricity market.

6. Disconnecting power when there is a risk of serious safety hazard to people and equipment during system operation.

7. Due to violations of laws on electricity activities and electricity usage by customers using distribution networks as stipulated in Article 6 of Decision No. 39/2005/QD-BCN dated December 23, 2005 of the Ministry of Industry regarding conditions, procedures, and formalities for interrupting and reducing power supply levels (hereinafter referred to as Decision No. 39/2005/QD-BCN). Decision No. 39/2005/QD-BCN 8. Due to force majeure events beyond the control of distribution companies as stipulated in Decision No. 39/2005/QD-BCN.).

Article 14. Procedure for approving annual reliability standards for distribution networks

1. Before September 15 each year, Vietnam Electricity Corporation shall be responsible for compiling reliability calculations for the following year of distribution companies to submit to the Electricity Regulatory Authority for consideration and approval.

2. Before October 15 each year, the Electricity Regulatory Authority shall approve reliability targets for distribution networks of each distribution company as a basis for calculating distribution electricity prices for distribution companies.

1. Before the first day of the first month of each quarter, distribution companies shall be responsible for reporting in writing to the Electricity Regulatory Authority on the implementation of power supply reliability targets of distribution networks in the previous quarter.

Article 15. Reporting System

2. The Electricity Regulatory Authority shall specify the format of reports on the reliability of distribution companies.

STANDARDS FOR ELECTRIC ENERGY LOSSES

Section 3

Article 16. Losses

of electric energy in distribution networks Electric energy losses in distribution networks include:

1. Technical losses: losses caused by technical power losses on lines and electrical equipment in distribution networks.

2. Non-technical losses: losses due to electricity theft, metering errors, or management errors in the electricity metering system.

Article 17. Procedure for approving electric energy loss targets for distribution networks

1. Before September 15 each year, Vietnam Electricity Corporation shall be responsible for compiling electric energy loss calculations for the following year of distribution companies to submit to the Electricity Regulatory Authority for consideration and approval.

2. Before October 15 each year, the Electricity Regulatory Authority shall approve electric energy loss targets for distribution networks of distribution companies as a basis for calculating distribution electricity prices for distribution companies.

QUALITY SERVICE STANDARDS

Section 4

Article 18. Types of quality service standards

Types of quality service standards include:

1. Time

for considering and signing connection agreements and implementing new connections or adjusting existing connections for customers. 2. Quality of written responses to customer complaints.

The content of written responses to customer complaints includes:

a) Clearly stating whether the complaint is accepted or not;

b) Clearly explaining the resolution plan in case the complaint is accepted;

c) In cases where the complaint is not accepted, the distribution company must clearly state the reasons and guide customers according to specific situations;

d) Providing all necessary information to help customers evaluate the resolution plan;

e) Written response within the time specified in point b, Clause 2, Article 19 of this Circular.

3. Quality of telephone responses to customer complaints is evaluated based on the criteria:

a) Ratio of customer calls satisfactorily answered;

b) Response time for calls within the time specified in point c, Clause 2, Article 19 of this Circular.

b) Response time for calls within the timeframe stipulated in point c, Clause 2, Article 19 of this Circular.

Article 19. Quality Standards for Distribution Network Services

1. The distribution unit must organize, maintain, and update information systems to record all complaints from customers in writing or via telephone.

2. The quality standards for services are defined as follows:

a) Time for reviewing and signing agreements on connection from the date of receiving complete and valid connection application files as stipulated at Article 47 ||| and Article 48 this Circular;

b) Quality of written responses:

- Over eighty-five percent (85%) of written explanations for power supply interruptions to customers within twenty-four (24) hours from the time of interruption;

- Over ninety-five percent (95%) of written responses to written complaints (fax or official letters) within five (05) working days.

c) Quality of telephone complaint responses: Over eighty-five percent (85%) of customer calls are responded to within thirty (30) seconds.

Article 20. Reporting on Service Quality Standards

By March 31 each year, the distribution unit is responsible for reporting to the Electricity Regulatory Authority on the results of implementing service quality standards, including the following contents:

1. Results of implementing service quality indicators in the previous year as prescribed in Article 19 of this Circular.

2. Explanation of reasons in cases where service quality standards are not met.

3. Plan to improve service quality standards.

Chapter III

FORECAST OF DISTRIBUTION SYSTEM LOAD REQUIREMENTS

Article 21. General Provisions

1. Forecasting the load requirements of the distribution system is forecasting the entire load supplied by the distribution system, excluding loads with their own power supply sources. The forecast of the load requirements of the distribution system serves as the basis for planning annual investment development of the distribution network, operation plans, and operational methods of the distribution system.

2. The forecast of the load requirements of the distribution system includes forecasts of load requirements for the coming year, month, and week.

3. Responsibilities for forecasting the load requirements of the distribution system:

a) The distribution unit is responsible for forecasting the load requirements of the distribution system under its management jurisdiction and at all points of connection with the transmission grid.

b) The distribution and retail units, customers using the distribution network with their own substation, and customers using the distribution network owning power generation units are responsible for providing the distribution unit with forecast data on their load requirements, including comprehensive load requirement forecasts for the entire unit and load requirements at each point of connection.

Article 22. Annual Load Requirement Forecast

1. Information and data used for annual load requirement forecasting include:

a) Forecast data on load requirements in the approved provincial, central city, district, and county power development master plans;

b) Factors such as electricity prices, population growth rates, economic development trends in the distribution unit's area, and other relevant socio-economic factors;

c) Trends in load requirements over the past five (05) years;

d) Forecasts of demand growth for existing loads in the coming years;

đ) Power needs of new loads, projects, industrial zones, and clusters that have planned investments and schedules for commissioning;

e) Energy-saving programs, load management programs, and measures to reduce power losses;

g) Capacity and volume of power purchased and sold at each point of connection with the distribution network of another distribution unit;

h) Capacity and volume of imported and exported power (if applicable);

i) Social factors and events affecting load requirements. 2. Results of annual load requirement forecasting

a) For the first year

- Forecast data on monthly energy consumption and maximum capacity for the entire distribution unit and at each point of connection with the transmission grid;

- Typical daily load profile charts for the entire distribution unit and at each point of connection with the transmission grid.

b) For the next four (04) years

- Forecast data on annual energy consumption and maximum capacity for the entire distribution unit and at each point of connection with the transmission grid;

- Typical annual daily load profile charts for the entire distribution unit and at each point of connection with the transmission grid.

3. Responsibility for providing information for load requirement forecasting

a) Customers using the distribution network with their own substation must provide the following information:

- Current typical daily load profile chart;

- Expected maximum capacity and registered monthly energy consumption for the upcoming year; expected maximum capacity and registered annual energy consumption for the next four (04) years;

- Additional parameters about the distribution network, circuit breakers, and protection layout diagrams for equipment directly connected or impacting the distribution network.

b) Customers using the distribution network owning power generation units must provide the following information:

- Forecast of monthly power generation capacity and volume that can be fed into the distribution network;

- Technical specifications of new power generation units and schedule for commissioning in the next five (05) years.

c) The distribution and retail units must provide the following information:

- Total number of customers categorized by type;

- Forecast of power capacity and energy consumption requirements for each customer type in the next five (05) years;

- Typical monthly daily load profile charts at the point of connection for the upcoming year;

- Additional parameters about the network, circuit breakers, and protection layout diagrams for equipment directly connected or impacting the distribution network.

d) Other distribution units connected to the distribution network must provide information on expected maximum capacity and volume of power exchange at the point of connection for each month of the upcoming year; expected maximum capacity and volume of power exchange at the point of connection for each year during the next four (04) years.

a) Before June 1 each year, entities specified in Clause 3 of this Article must provide information to the distribution unit for forecasting load requirements for the upcoming year and the next four (04) years.

4. Procedure

a) Before June 1st each year, entities specified in Clause 3 of this Article must provide information to the Distribution Unit to forecast electricity load demand for the upcoming year and the subsequent four (04) years;

b) Before July 1st each year, the Electricity Distribution Unit must complete the annual load demand forecast results as stipulated in Clause 2 of this Article to provide to the System Operation Unit and the Electricity Market.

Article 23. Monthly Load Demand Forecast

1. Information and data used for monthly load demand forecasting:

a) Annual load demand forecast results;

b) Statistics on electricity consumption, daily peak power and night peak power in the corresponding month of the previous year;

c) Other necessary information.

2. Results of the monthly load demand forecast:

a) Maximum capacity and weekly electricity consumption of the entire Electricity Distribution Unit and at each point of connection with the transmission grid;

b) Maximum capacity and weekly electricity exchange at points of international electricity trade through the Electricity Distribution Unit's grid;

c) Maximum capacity and weekly electricity exchange of large customers using the distribution grid;

d) Typical daily profile chart of the entire Electricity Distribution Unit on a weekly basis.

3. Large customers using the distribution grid must provide the Electricity Distribution Unit with forecasts of upcoming month's electricity consumption and maximum capacity at each point of connection under the following circumstances:

a) A difference in electricity consumption capacity exceeding 2 MW compared to the corresponding month's figures in the annual load demand forecast;

b) A difference in power generation capacity of customer-owned power plants exceeding 1 MW compared to the expected power generation capacity of the corresponding month in the annual load demand forecast.

4. Procedure for implementation:

a) Before the 15th day of each month, large customers using the distribution grid must provide the Electricity Distribution Unit with the information as stipulated in Clause 3 of this Article to serve the upcoming month's load demand forecast;

b) Before the 20th day of each month, the Electricity Distribution Unit must complete the upcoming month's load demand forecast and notify the System Operation Unit and the Electricity Market.

Article 24. Weekly Load Demand Forecast

1. The results of the weekly load demand forecast include the following parameters:

a) Maximum capacity and daily electricity consumption of the entire Electricity Distribution Unit and at each point of connection with the transmission grid;

b) Maximum capacity and daily electricity exchange at points of international electricity trade through the Electricity Distribution Unit's grid;

c) Daily load profile chart for the week of the entire Electricity Distribution Unit.

2. By 11:00 AM every Thursday, the Electricity Distribution Unit is responsible for completing and providing to the System Operation Unit and the Electricity Market the forecast of load demand for the next two (02) weeks to establish operational methods for the next two (02) weeks.

Article 25. Load Research

1. The Electricity Distribution Unit is responsible for conducting load research to support load demand forecasting and retail electricity price calculation.

2. The Electricity Regulatory Authority is responsible for drafting Circulars specifying the contents, procedures, and processes of load research to be submitted to the Minister of Industry and Trade for issuance.

Chapter IV

DEVELOPMENT INVESTMENT PLAN FOR DISTRIBUTION GRID

Article 26. Principles ) are determined according to the following formula:

1. Each year, the Electricity Distribution Unit is responsible for developing the annual development investment plan for the distribution grid and considering the subsequent four (04) years within its management scope.

2. The annual development investment plan for the distribution grid is based on the following foundations:

a) Annual load demand forecast results;

b) Consistent with the approved provincial power development planning and signed interconnection agreements.

Article 27. Requirements for the annual investment plan to develop the distribution network

1. Ensure power supply for the current load demand of existing customers and new customers; connect new power sources to the distribution network.

2. Meet the operational standards of the distribution network system as stipulated in Chapter II of this Circular.

3. Propose a list and schedule for putting into operation distribution network projects that need investment in the coming year and the total investment volume according to project categories for the next four (04) years.

4. Propose a list of transmission network projects that need investment and upgrading to meet the requirements for the progress of distribution network projects in the investment development plan for the distribution network.

Article 28. Contents of the investment plan to develop the distribution network

The investment plan to develop the distribution network includes the following contents:

1. Evaluation of the current status of the distribution network.

2. Forecast of electricity load demand for the next year at each point of connection with the transmission network and forecast of electricity load demand according to load components of the entire distribution unit for the next four (04) years.

3. Evaluation of the implementation of investment in distribution network projects that have been approved.

4. List of new connections with large customers using the distribution network, including the proposed connection points that have been agreed upon.

5. Calculations and analyses, selection of optimal grid configuration, including:

a) Calculation of distribution network operation mode;

b) Voltage loss calculation;

c) Short-circuit calculation to the medium-voltage busbar of 110kV substations;

d) Energy loss calculation on the distribution network;

đ) Reactive power compensation calculation;

e) Plan to implement reactive power compensation on the distribution network.

6. List of new distribution line and substation construction projects or those requiring renovation for the coming year and the total investment volume for new construction and renovation of the distribution network according to voltage levels and project categories for the next four (04) years as specified in Appendix 1 of this Circular.

7. Summary of capital investment for new construction and renovation of the distribution network according to voltage levels.

Article 29. Procedure for preparing, reviewing, and approving the investment plan to develop the distribution network

1. The dossier for the annual investment plan to develop the distribution network for review and approval includes:

a) Approval request;

b) Annual investment plan to develop the distribution network according to the contents stipulated in Article 28 of this Circular.

2. Each year, the Distribution Unit must submit the dossier for the investment plan to develop the distribution network within its management scope to the Vietnam Electricity Corporation for consolidation and preparation of the national distribution network investment plan for the following year.

3. Before August 31 each year, the Vietnam Electricity Corporation is responsible for submitting the national investment plan to develop the distribution network and that of each Distribution Unit for the following year to the Electricity Regulatory Authority.

4. Before September 30 each year, the Electricity Regulatory Authority reviews and approves the national investment plan to develop the distribution network and that of each Distribution Unit as a basis for calculating and establishing electricity sales prices.

Chapter V

CONNECTION TO THE DISTRIBUTION NETWORK

Section 1

GENERAL PRINCIPLES

Article 30. Point of Interconnection

1. The point of interconnection is:

a) The connection point between the customer's equipment, distribution network, and power plant to be connected to the distribution network of the Distribution Unit;

b) The connection point between the equipment and networks of two Distribution Units;

c) The connection point between the customer's equipment and network to be connected to the distribution network of the Distribution and Retail Unit.

2. The point of interconnection must be described in detail through drawings, diagrams, and relevant explanations in the interconnection agreement or power purchase and sale contract.

Article 31. Boundaries for Asset Division and Operation Management

1. The boundary for asset division between the Distribution Unit or the Distribution and Retail Unit and the customer using the distribution network is the point of interconnection.

2. Assets of each party at the asset division boundary must be listed in detail along with relevant drawings and diagrams in the interconnection agreement or power purchase and sale contract.

3. The party owning the assets has the responsibility to invest in construction and manage and operate them according to legal standards and regulations, except where otherwise agreed.

Article 32. Compliance with Power Development Planning

1. The plan for connecting new electrical equipment, networks, and power plants to the distribution network must comply with the approved power development planning.

2. The Distribution Unit has the responsibility to notify customers using the distribution network when their proposed interconnection plan does not conform to the approved power development planning.

3. In cases where the interconnection plan to the 110kV voltage level or the interconnection of a new power plant does not conform to the approved power development planning, the investor proposing the interconnection plan must prepare a report to submit to the People's Committee of the province for review by the Electricity Regulatory Authority and approval by the Minister of Industry and Trade to adjust the provincial power development planning.

4. In cases where the interconnection plan to the medium voltage level does not conform to the approved power development planning, the investor proposing the interconnection plan must prepare a proposal to adjust and supplement the planning for review by the Department of Industry and Trade and approval by the People's Committee of the province to adjust the district or county power development planning.

Article 33. Responsibilities for Implementation Coordination

1. The Distribution Unit has the responsibility to coordinate the implementation of the interconnection plan when the customer submits a valid interconnection application. The interconnection and adjustment thereof must meet the operational standards at the interconnection point as stipulated in Section 2 of this Chapter.

2. If the equipment at the customer's interconnection point does not meet technical standards and distribution network operational standards, the Distribution Unit has the responsibility to notify and coordinate with the customer to take corrective measures. The customer using the distribution network must bear all costs for implementing these corrective measures.

Section 2

TECHNICAL REQUIREMENTS AT THE POINT OF INTERCONNECTION

Article 34. Requirements for Phase Balance

Under normal operating conditions, the customer using the distribution network must ensure that their equipment does not cause more than 3% of the rated voltage for the 110kV voltage level or more than 5% of the rated voltage for voltages below 110kV of reverse sequence components of phase voltage at the interconnection point.

Article 35. Requirements for Harmonic Currents

1. The maximum allowable value (in terms of the absolute value of current or % of load current at the point of connection) of the total harmonic distortion caused by high-order harmonics, depending on the voltage level, is specified as follows:

a) For connections to low-voltage distribution systems with power up to 10kW:

- Customers connecting to a single-phase low-voltage distribution system: the value of high-order harmonic current shall not exceed 5A;

- Customers connecting to a three-phase low-voltage distribution system: the value of high-order harmonic current shall not exceed 14A.

b) For connections to medium-voltage distribution systems or connections with power above 10kW but less than 50kW: the value of high-order harmonic current shall not exceed 20% of the load current;

c) For connections to high-voltage distribution systems or connections with power of 50kW or more: the value of high-order harmonic current shall not exceed 12% of the load current.

2. The total harmonic distortion measured by the Distribution Unit at the customer's point of connection using the IEC1000-4-7 standard, over a period of at least 24 hours with a sampling interval of 10 minutes, must be within the allowed limit. Within six (06) months from the date of detection that the customer's equipment does not meet the values specified in Clause 1 of this Article, the customer must take corrective measures to achieve the total harmonic distortion within the allowable limits.

Article 36. Requirements for Voltage Fluctuations

The maximum allowable level of voltage fluctuations at the point of connection to the distribution network must comply with the provisions of Article 8 of this Circular.

Article 37. Grounding Requirements

1. Customers using the distribution network must use neutral grounding systems in their networks as stipulated in Article 10 of this Circular, except where otherwise agreed.

2. In cases where customers are supplied electricity from multiple sources, customers are responsible for installing appropriate protective devices to prevent and limit currents flowing through the neutral point to ground.

Article 38. Power Factor Requirements

Customers using electricity for production, business, and services with a maximum usage capacity of 80kW or transformer capacity of 100kVA or more are responsible for maintaining the power factor (cos φ) at the point of connection at no less than 0.85, except where otherwise agreed.9. Travel distance is the distance traveled without using mechanical means (cars, motorcycles, motorboats) to reach locations for implementing technical forest management measures and patrolling to protect forests.Article 39. Requirements for Low-Frequency Relay Systems

In necessary cases, customers using distribution networks with their own substations connected to the 110kV voltage level are responsible for investing in and installing low-frequency relays to automatically shed loads according to calculations by the Distribution Unit. Requirements for low-frequency relays must be clearly stated in the Connection Agreement.

Article 40. Information System Requirements

1. Customers using distribution networks who own power plants connected to the distribution network with a capacity of 10MW or more and 110kV substations are responsible for installing information systems within their management scope and connecting these systems to the Distribution Unit's information system to facilitate communication and data transmission during system operation. Customer equipment must be compatible with the existing information system of the Distribution Unit.

2. Customers not falling under the provisions of Clause 1 of this Article have the right to agree on the installation of information systems but must clearly state this in the Connection Agreement.

3. The Distribution Unit is responsible for investing in and managing information systems within its distribution network management scope to support distribution network operations.

4. The Distribution Unit is responsible for providing customers using distribution networks with requirements for information data, data transmission, and interface information, and coordinating with customers in testing, inspecting, and connecting customer information and data systems to the existing information and data systems within the management scope.

4. The Distribution Unit is responsible for providing electricity users with requirements for data information, data transmission, and necessary interface information, and coordinating with customers in testing, inspecting, and connecting the customer's information and data systems to the existing information and data systems within its management scope.

Article 41. Requirements for the SCADA System/DMS

1. Power plants connected to the distribution grid with a capacity of 10 MW or more and 110 kV substations must be equipped with a distributed control system (DCS) or remote terminal unit (RTU) with two (02) independent ports and directly connected to the SCADA/DMS system of the Distribution Unit.

2. For power plants with a capacity less than 10 MW directly connected to the 110 kV grid, the requirements for the SCADA/DMS system shall be agreed upon between the parties based on specific cases and must be clearly stated in the interconnection agreement.

3. Customers using the distribution grid are responsible for investing, installing, and connecting the data transmission line of the SCADA/DMS system from the grid under their management to the SCADA/DMS system of the Distribution Unit.

4. The customer's SCADA/DMS system must have technical characteristics compatible and ensure connection with the SCADA/DMS system of the Distribution Unit.

5. The connection of the customer's SCADA/DMS system with the existing SCADA/DMS system of the Distribution Unit must be carried out by both parties. The Distribution Unit is responsible for providing the transmission line to the point of interconnection and integrating the parameters of the customer's SCADA/DMS system with the Distribution Unit's SCADA/DMS system.

6. In case the SCADA/DMS system of the Distribution Unit undergoes technological changes approved by the competent authority after the signing of the interconnection agreement, leading to the need to change or upgrade the customer's SCADA/DMS system, the Distribution Unit and the customer are responsible for coordinating to implement necessary adjustments so that the customer's equipment is compatible with the changes in the SCADA/DMS system. The customer is responsible for investing in and upgrading the SCADA/DMS system to ensure connection with the Distribution Unit's SCADA/DMS system.

7. The list of data and technical standards for devices within the DCS/RTU system is specified in the Technical Requirements and Operation Management Regulations for the SCADA/DMS System.

8. The Electricity Regulatory Authority is responsible for organizing, developing, and promulgating the Technical Requirements and Operation Management Regulations for the SCADA/DMS System.

Article 42. Requirements for Protection Systems

1. The relay protection systems of substations and 110 kV transmission lines must comply with the technical requirements for relay protection and automation systems in power plants and substations issued by the Electricity Regulatory Authority.

2. The Distribution Unit and customers using the distribution grid with their own substation must agree on the requirements for the protection system in the Interconnection Agreement.

3. The dispatching level has the right to control the distribution grid and is responsible for issuing relay setting sheets within the distribution grid and approving related setting values for customer protection relay equipment concerning the distribution grid.

4. Customers using the distribution grid with their own substation must cooperate with the Distribution Unit to design, install, test, and operate the protection system on their grid to meet the technical standards and requirements regarding response time, sensitivity, and selectivity in dealing with faults to minimize impact on the distribution grid.

5. Customers using the distribution grid with their own substation may not arbitrarily install equipment to limit short-circuit current at the busbar connected to the distribution grid, except where there is a separate agreement with the Distribution Unit.

6. The Distribution Unit must provide customers using the distribution grid with their own substation with the parameters of the relay protection system on the distribution grid in the Interconnection Agreement.

Article 43. Requirements for Generator Sets Connected to Distribution Grids

Generator sets connected to distribution grids must meet the following requirements:

1. The circuit breaker of the generator set at the connection point must be capable of interrupting the maximum allowable short-circuit current and isolating the generator from the distribution grid under all operating conditions.

2. It must be able to continuously supply rated active power within the frequency range of 49Hz to 51Hz. Within the frequency range of 47Hz to 49Hz, the reduction in power must not exceed the value calculated according to the system frequency reduction requirement ratio, consistent with the characteristic curve of the relationship between active power and frequency of the generator set. In cases where the frequency is below 47Hz or above 51Hz, the Customer using the distribution grid with a generator set has the right to decide whether to disconnect or not disconnect the generator set from the distribution network.

3. Under normal operating conditions, the generator set connected to the distribution grid must be able to supply reactive power according to the generator set's power characteristics and maintain voltage deviation within the range specified in Article 5 of this Circular.

4. Power plants connected to the distribution grid that can provide reactive power must ensure the following conditions:

a) The ability to continuously adjust the reactive power supplied to the distribution grid to regulate the voltage on the distribution grid;

b) A self-excitation system ensuring stable output voltage within the operating range of generator sets connected to the distribution grid.

5. Generator sets connected to the distribution grid must be able to withstand the level of asymmetrical voltage drop in the system as stipulated in Article 6 of this Circular and withstand zero-sequence and negative-sequence components of current not less than the time required to clear phase-to-phase and phase-to-ground faults near the generator by protective devices associated with the connection point.

6. In cases where the connection point is equipped with automatic reclosing equipment, the relay protection system of the power plant must be coordinated with the automatic reclosing equipment of the Distribution Unit and must be designed to immediately disconnect the generator set from the distribution grid after the first operation of the circuit breaker, automatic reclosing equipment, or sectionalizer of the distribution grid, and maintain isolation of the generator set from the distribution grid until the distribution grid is fully restored.

7. In addition to the technical requirements stipulated in this Article, generator sets connected to the distribution grid must also comply with the provisions of Articles 34, 35, 36, 40, and 41 of this Circular.

Article 44. Technical Requirements at the Connection Point Between Electricity Consumers and Distribution and Retail Units

Electricity consumers and Distribution and Retail Units have the responsibility to:

1. Ensure that distribution grid equipment meets the operational standards prescribed in Section 1, Chapter II of this Circular.

2. Ensure that technical requirements at the connection point comply with the provisions of Articles 34, 35, 36, 37, and 38 of this Circular.

Section 3

PROCEDURE AND PROCEDURES FOR CONNECTION AGREEMENTS

Article 45. Application Documents for Connection

1. For low-voltage connections, when there is a need for new connection to the distribution grid or modification of existing connections, electricity consumers must submit the documents specified in Appendices 2A and 2B to the Distribution Unit and follow the provisions of Article 48 of this Circular.

2. For medium-voltage and 110kV connections, when there is a need for new connection to the distribution grid or modification of existing connections, electricity consumers must submit the following documents to the Distribution Unit:

a) Connection application forms in accordance with the templates specified in Appendices 2C to 2D of this Circular;

b) Principle diagrams of major electrical equipment after the connection point;

c) Technical documentation on the equipment intended for connection or anticipated changes at the current connection point, expected completion date of the project, economic and technical data of the new connection project or modified connection.

Article 46. Procedures for Negotiating Connection to Medium Voltage and 110kV Levels at medium voltage and 110kV levels

1. Upon receiving the connection application file, the Distribution Unit shall be responsible for checking and notifying in writing about the completeness and validity of the file.

2. After receiving a complete and valid connection application file, the Distribution Unit shall be responsible for performing the following tasks:

a) Reviewing requirements related to the expected electrical equipment at the connection point;

b) Evaluating the impact of connecting the customer's equipment, power grid, and power plant on the distribution network's load-carrying capacity of existing transmission lines and substations; the impact on short-circuit current, the impact on the quality of the distribution network's electricity after the connection; coordination work among protection systems;

c) Drafting and agreeing upon a single-line diagram with technical parameters of the equipment and layout plan of the customer's power grid connection to the distribution network as the official diagram used in the Connection Agreement;

d) Drafting the Connection Agreement according to the contents stipulated in Appendix 3 of this Circular and sending it to the customer requesting the connection.

3. The customer requesting the connection shall be responsible for providing the Distribution Unit with necessary information to serve the review and agreement on the connection plan and signing the Connection Agreement with the Distribution Unit.

4. In case the connection plan cannot be agreed upon, the Distribution Unit shall be responsible for notifying the customer in writing and reporting to the Electricity Regulatory Authority regarding the reasons for the disagreement on the connection plan.

Article 47. Time Limit for Reviewing and Signing the Connection Agreement

The time limit for negotiating and signing the Connection Agreement is specified in Table 5 as follows:

Table 5. Time limit for reviewing and signing the Connection Agreement

Article 48. Procedures for Supplying Electricity to Customers Connecting to Low Voltage Level

1. For cases supplying electricity for living purposes, within seven (07) working days from the date of receiving all valid customer files, the Distribution Unit or the Distribution and Retail Electricity Unit must sign and send the electricity supply contract to the customer.

2. For cases supplying electricity for non-living purposes, within ten (10) working days from the date of receiving all valid customer files, the Distribution Unit or the Distribution and Retail Electricity Unit shall be responsible for inspecting, surveying, and drafting an electricity supply plan for the customer requesting supply.

3. In case electricity cannot be supplied to the customer, the Distribution Unit or the Distribution and Retail Electricity Unit shall be responsible for notifying the customer and must clearly state the reason with confirmation from the competent state management agency.

4. The Electricity Regulatory Authority shall be responsible for organizing, developing, and promulgating regulations on procedures for supplying electricity to customers connecting to low voltage level.

Section 4

 IMPLEMENTING CONNECTION

Article 49. Right to access equipment at the connection point

1. The electricity distribution unit has the right to access the equipment at the connection point during construction, installation, replacement, removal, inspection, testing, maintenance, and operation of such equipment.

2. Customers have the right to access the equipment within their management scope at the connection point during construction, installation, replacement, removal, inspection, testing, maintenance, and operation of such equipment.

Article 50. Provision of documents for energization conditions at the connection point

1. Prior to the expected energization date of the connection point, the customer requesting connection must provide the electricity distribution unit with two (02) sets of documents for comprehensive inspection of the energization conditions at the connection point (in Vietnamese or English for technical documents confirmed by the customer requesting connection and certified copies of legal documents), including:

a) Approved technical design documents and any amendments or supplements compared to the initial design, including general descriptions, main electrical connection diagrams, layout plans of electrical equipment, protection and control system principle diagrams, related diagrams, and technical specifications of major electrical equipment;

b) Operation and management guidelines for the equipment provided by the manufacturer;

c) Partial and final acceptance certificates for the connected equipment of the power plant, transmission lines, and substations to the distribution network in compliance with Vietnamese technical standards or internationally recognized standards accepted by Vietnam, and meeting the technical requirements for connected equipment stipulated from Article 34 to Article 44 of this Circular;

d) Scheduled test run and operation plan.

2. Unless otherwise agreed, the customer requesting connection shall be responsible for providing all the documents specified in Clause 1 of this Article within the permitted time frame as follows:

a) At least two (02) months before the expected first trial operation of the power plant;

b) At least one (01) month before the expected first trial operation of the transmission lines and substations (excluding the final acceptance certificate for the transmission lines and substations).

3. Within twenty (20) working days from receipt of all documents, the electricity distribution unit shall be responsible for transferring to the customer requesting connection the following documents:

a) Equipment numbering diagram;

b) Requirements for customer relay protection settings from the connection point towards the customer; setting sheets for relays and related setting values for relay protection devices of the customer requesting connection issued by the dispatching authority with grid control rights;

c) Requirements for testing and calibrating equipment;

d) Requirements for receiving dispatch orders;

đ) Requirements for establishing communication systems for dispatching purposes;

e) Requirements for collecting and transmitting SCADA/DMS system data (if applicable);

g) Automatic control methods (if applicable);

h) Start-up procedures (for power plants);

i) List of relevant procedures concerning national power system operations, distribution system operations, and coordinated operations;

k) List of relevant staff and engineers managing the power system along with contact phone numbers and fax numbers.

4. At least ten (10) working days prior to the expected energization date of the connection point, the customer requesting connection must provide the electricity distribution unit with the following contents:

a) Test run schedule (for power plants) and energization operation schedule for electrical equipment;

b) Agreement on the division of responsibilities between both parties regarding the management and operation of the connected equipment;

c) Internal regulations for safe operation of the connected equipment;

d) List of customer operators including names, professional positions, responsibilities, along with contact phone numbers and fax numbers.

Article 51. Inspection of Conditions for Energizing Connection Points

1. The customer requesting connection shall be responsible for agreeing with the Distribution Unit on the date to conduct actual inspection at the connection point.

2. In case the Distribution Unit notifies that the connection point or equipment related to the connection point of the customer requesting connection does not meet the conditions for energization, the customer requesting connection must adjust, supplement, or replace the equipment according to the requirements and re-agree with the Distribution Unit on the time for the next inspection.

3. The Distribution Unit and the customer requesting connection must jointly sign the report confirming the conditions for energizing the connection point and agree on the energization time of the connection point.

Article 52. Energizing the Connection Point

1. Prior to energizing the connection point, the customer requesting connection must complete and provide to the Distribution Unit the following documents confirming that the project meets legal and technical procedures:

a) Equipment within the energization range has been tested and inspected to meet operational standards;

b) The electricity metering system has been completed, and the meter readings have been confirmed;

c) An electricity purchase and sale contract has been signed;

d) Primary equipment has been numbered correctly according to the primary diagram issued by the control authority;

đ) Protective relays and automatic devices have been set correctly according to the requirements of the control authority;

e) Operation personnel have been trained adequately and hold operation certificates issued by the System and Electricity Market Operation Unit including their names, professional positions, and responsibilities;

g) Dispatch communication means (direct communication, dial-up telephone, fax) are functioning properly;

h) Integration with the SCADA/DMS system has been completed.

2. The Distribution Unit is responsible for establishing and registering the energization method of the connection point with the control authority of the distribution network.

3. The Distribution Unit and the Customer using the distribution network are responsible for implementing the energization of the connection point according to the method approved by the control authority.

Article 53. Procedure for Testing and Commissioning Equipment After the Connection Point

1. During the testing period to commission the equipment after the connection point of the customer requesting connection, the customer must assign operation personnel to stand by and notify the Distribution Unit of the list of standby personnel along with their contact numbers and fax numbers for coordination when necessary.

2. During the acceptance trial run, the customer requesting connection is responsible for coordinating with the Distribution Unit to ensure operational parameters comply with technical requirements at the connection point within the limits specified in Section 2 of this Chapter.

3. At the end of the acceptance trial run, the customer requesting connection must confirm the actual operational parameters at the connection point of electrical equipment, transmission lines, substations, and generating units. If the operational parameters at the connection point fail to meet the technical requirements stipulated in Section 2 of this Chapter due to the distribution network or the customer's electrical equipment, the Distribution Unit has the right to disconnect the customer's power plant or distribution network from the distribution system and request the customer to take corrective measures.

4. The distribution network, power plant, and electrical equipment after the connection point of the customer requesting connection may only be officially put into operation after partial and full acceptance trial runs and meeting the technical requirements at the connection point specified in Section 2 of this Chapter. During the acceptance trial run and official operation, the Customer using the distribution network must comply with the National Power System Dispatch Procedures and other relevant procedures.

Article 54. Inspection and Supervision of Operation of Connecting Equipment

1. Customers using distribution networks shall be responsible for operating equipment to ensure operational standards and technical requirements at the point of connection within the limits prescribed in this Circular. In case the operational parameters of the customer's electrical equipment do not meet the operational standards and technical requirements at the point of connection, the Distribution Unit has the right to request the customer to retest the equipment under their management to determine the cause and take corrective measures.

2. In case both parties cannot agree on the results of inspection and the cause of violation, both parties must agree on the scope of inspection for the customer to hire an independent third party to conduct retesting. If the inspection results from the third party show that the violations are caused by the customer's equipment and the customer does not accept the remedial solutions, the Distribution Unit has the right to disconnect the customer's equipment from the distribution network.

3. Customers using distribution networks must bear the costs of additional inspections and tests if the inspection results show that the customer's equipment violates the operational standards and technical requirements at the point of connection. The Distribution Unit must bear the costs of additional inspections and tests if the inspection results show that the customer's equipment does not violate the operational standards and technical requirements at the point of connection.

4. Prior to inspecting connecting equipment to determine violations of operational standards at the point of connection, is an electricity unit licensed to operate in the field of distribution and sale of electricity, including: customers using distribution networks must be notified in advance of the inspection time and list of inspectors. In cases where the inspection may cause power outages for customers, the Distribution Unit must notify customers using distribution networks at least fifteen (15) days in advance. Customers using distribution networks with their own substations have the responsibility to cooperate and provide all necessary conditions for the inspection work.

5. During the inspection process, is an electricity unit licensed to operate in the field of distribution and sale of electricity, including: it is permitted to install electricity metering devices and inspection equipment at the connecting equipment but must not affect the safe operation of power plants, distribution networks, and electrical equipment of customers using distribution networks.

6. During operation, if there is a risk of unsafe operation of the power system due to equipment owned by the customer at the point of connection, the Distribution Unit must immediately notify the customer using distribution networks with their own substation and request a timeframe for rectification to eliminate the risk of unsafe operation of the power system. If the technical cause remains unresolved after the requested rectification period, the Distribution Unit has the right to disconnect the point of connection and notify the customer. The customer must retest the equipment after the point of connection according to the provisions of Article 53 of this Circular.

Article 55. Replacement of Equipment at the Point of Connection

1. In case customers using distribution networks with their own substations plan to replace, upgrade connecting equipment, or install new electrical equipment that may affect the performance and operating mode of the distribution network, they must notify and negotiate with the Distribution Unit about these changes and the contents of the changes must be supplemented in the Connection Agreement.

2. In case the proposal of the customer is not approved, the Distribution Unit must notify the customer in writing of any additional requirements for the new equipment planned to be changed.

3. All replaced equipment at the point of connection must be inspected, tested, and accepted according to the provisions from Article 49 to Article 53 of this Circular.

Article 56. Connection to Low Voltage Distribution Grid

1. For electricity supply for living purposes, within seven (07) working days from the date of receiving complete valid customer files, the Distribution and Retail Electricity Unit shall complete the installation and acceptance of the electricity metering system and provide electricity to customers.

2. For electricity supply other than for living purposes, within five (05) working days from the date of on-site inspection of the connection point according to Article 48 of this Circular, the Distribution and Retail Electricity Unit shall complete the installation and acceptance of the electricity metering system and provide electricity to customers.

Section 5

DISCONNECTION AND RECONNECTION

Article 57. General Provisions

1. Cases of disconnection include:

a) Voluntary disconnection is disconnection at the request of the distribution network user, including permanent and temporary disconnections.

b) Mandatory disconnection is disconnection in cases where the distribution network user violates the Connection Agreement, power purchase contract, or upon the request of the competent authority when the distribution network user breaches legal provisions.

2. The distribution network user must bear all costs for disconnection and reconnection.

Article 58. Voluntary Disconnection

1. Permanent disconnection

a) The cases of permanent disconnection of the distribution network user from the distribution system and the responsibilities of the relevant parties must be stipulated in the Connection Agreement and power purchase contract;

b) When there is a need for permanent disconnection from the distribution system, the distribution network user must notify the Distribution Unit in writing at least one (01) month before the planned permanent disconnection date. In case the distribution network user owns generating units connected to the distribution grid, they must notify the Distribution Unit and related dispatch levels in writing at least three (03) months before the planned permanent disconnection date.

2. Temporary disconnection

The distribution network user is responsible for agreeing with the Distribution Unit on the time and duration of temporary disconnection from the distribution system.

Article 59. Mandatory Disconnection

The Distribution Unit has the right to disconnect the distribution network user from the distribution system in the following cases:

1. At the request of the competent state authority for disconnection.

2. Cases of mandatory disconnection stipulated in the power purchase contract or connection agreement.

Article 60. Reconnection

The Distribution Unit is responsible for reconnecting the distribution network user under the following circumstances:

1. Upon the request of the competent authority for reconnection or when the causes leading to disconnection have been eliminated, the consequences have been remedied, and the related costs have been paid by the customer.

2. Upon the request of the distribution network user for reconnection and the related costs have been paid by the customer in the case of temporary disconnection.

Chapter VI

DISTRIBUTION SYSTEM OPERATION

Section 1

RESPONSIBILITIES FOR OPERATION

Article 61. Responsibilities of is an electricity unit licensed to operate in the field of distribution and sale of electricity, including:

1. Managing and operating equipment and power grids within their jurisdiction.

2. Establishing annual, monthly, weekly, and daily operation plans, maintenance plans, and repair plans for electrical equipment and power grids according to the provisions set out in Sections 2 and 3 of this Chapter.

3. Operating and maintaining the voltage quality of distribution networks and ensuring electricity supply to customers in compliance with the operational standards stipulated in Chapter II of this Circular.

4. Investing in, installing, managing, and operating the SCADA/DMS system and relay protection systems to ensure stable, reliable, and continuous operation within their jurisdiction. Formulating methods and calculating relay protection systems for customer distribution network protection at connection points to ensure selectivity, sensitivity, and fault isolation capability.

5. Adhering to dispatch orders from the System Operation Unit and Electricity Market Units except when compliance poses a threat to human life, equipment, or when such orders violate established regulations.

6. Operating distribution systems in accordance with the Transmission System Regulations and National System Dispatch Procedures.

7. Coordinating with other Distribution Units and customers with their own substations during the operation of equipment at connection points with their own networks.

8. Complying with legal provisions on electrical safety and protecting power grid and facility corridors.

Article 62. Responsibilities of Customers Using Distribution Networks

1. Customers using distribution networks with their own substations shall be responsible for:

a) Operating electrical equipment and distribution networks within their jurisdiction in compliance with the standards set out in Section 2 of Chapter V of this Circular;

b) Adhering to command rights, dispatch orders, and operations of the Distribution Unit according to the National System Dispatch Procedures;

c) Providing accurate and timely information to the Distribution Unit for the establishment of operation plans, maintenance plans, and repair plans for distribution systems;

d) Cooperating with the Distribution Unit to maintain the quality of electric energy and economically operate the distribution system as agreed upon with the Distribution Unit.

2. Customers using distribution networks who own power plants connected to distribution networks shall be responsible for:

a) Implementing the provisions of Clause 1 of this Article;

b) Ensuring the operation of power plants in accordance with the interconnection agreement and power purchase contract;

c) Providing accurate and timely operation plans and data for power plants to the Distribution Unit.

3. Customers using distribution networks connected to low-voltage levels shall be responsible for operating electrical equipment and distribution networks in compliance with the standards set out in Section 2 of Chapter V of this Circular;

Section 2

MAINTENANCE AND REPAIR PLAN DISTRIBUTION SYSTEM

Article 63. General Provisions on Maintenance and Repair of distribution systems

1. The Distribution Unit shall be responsible for establishing annual, monthly, and weekly maintenance and repair plans for distribution systems including distribution network maintenance and repair plans and power plants with installed capacity up to 30 MW connected to distribution networks to serve the planning of distribution system operations.

2. The maintenance and repair plan for distribution systems must take into account the maintenance and repair plans for distribution networks and power plants of customers with their own substations, Distribution Units, and Retail Electricity Units, and must meet the following requirements:

a) Ensuring safe, stable, and reliable power supply;

b) Optimizing the coordination of maintenance and repair of power sources and distribution networks.

3. In cases where the planned maintenance and repair of distribution systems cannot be implemented, customers with their own substations and Distribution and Retail Electricity Units must notify and coordinate with the Distribution Unit to adjust accordingly.

Article 64. Annual Maintenance and Repair Plan

1. Before July 1st each year, customers using distribution networks with their own substations and electricity distribution and retail units shall provide the electricity distribution unit with information on the maintenance and repair plan for the next two (02) years, including:

a) List of power lines and electrical equipment related to the connection point with the distribution network of the electricity distribution unit that are planned for maintenance and repair;

b) Reasons for maintenance and repair;

c) Scope of power supply interruption due to maintenance and repair work;

d) Amount of electricity and calculated load capacity interrupted from power supply;

đ) Amount of electricity and calculated generation capacity not fed into the distribution network of the power plant.

2. Before August 1st each year, the electricity distribution unit must complete the draft maintenance and repair plan for the next two (02) years based on considering the following factors:

a) Results of load demand forecasting;

b) Maintenance and repair plans of customers using distribution networks with their own substations, distribution and retail units, and any requests to change the maintenance schedule (if any);

c) Requirements for transmission network maintenance and repair;

d) Coordination of maintenance and repair plans of customers using distribution networks with their own substations, distribution and retail units, in accordance with actual operating conditions to optimize technical and economic operation of the distribution system;

đ) Other relevant requirements for maintenance and repair.

3. In case of disagreement with the electricity distribution unit's maintenance and repair plan, before August 15th each year, customers using distribution networks with their own substations, distribution and retail units have the right to submit a written request to the electricity distribution unit to adjust the annual maintenance and repair plan. The electricity distribution unit has the responsibility to review and adjust the annual maintenance and repair plan in accordance with the customer's request. If it is not possible to adjust the maintenance and repair plan according to the customer's request, the electricity distribution unit must notify the customer in writing and specify the reasons.

4. Before October 1st each year, the electricity distribution unit must complete and publish the maintenance and repair plan for the next two (02) years on its website, including the following contents:

a) List of electrical equipment and power lines to be maintained and repaired;

b) Reasons for maintaining and repairing the equipment and power lines;

c) Main content of the work;

d) Estimated maintenance and repair time;

đ) Other relevant requirements for maintenance and repair work.

Article 65. Monthly Maintenance and Repair Plan

1. In case the monthly maintenance and repair plan differs from the published annual maintenance and repair plan, customers using distribution networks with their own substations, distribution and retail units must provide the electricity distribution unit with the information specified in Clause 1 of Article 64 of this Circular before the 15th of each month.

2. Before the 20th of each month, the electricity distribution unit must complete the draft monthly maintenance and repair plan based on considering the following factors:

a) Published annual maintenance and repair plan;

b) Results of load demand forecasting for the upcoming month;

c) Requests to adjust the maintenance and repair plan from customers using distribution networks with their own substations and distribution and retail units;

d) Requirements for maintenance and repair on the transmission network.

3. Before the 25th of each month, the electricity distribution unit must complete and publish the maintenance and repair plan for the upcoming month on its website, including the following contents:

a) Names of electrical equipment and power lines to be maintained and repaired;

b) Reasons for maintaining and repairing the equipment and power lines;

c) Main content of the work;

d) Estimated start and end times for maintenance and repair work;

đ) Other relevant requirements for maintenance and repair work;

e) Estimated power capacity and electricity not supplied due to maintenance and repair.

Article 66. Weekly Maintenance and Repair Plan

1. Each week, the Electricity Distribution Unit shall be responsible for establishing a maintenance and repair plan for the third week from the week the plan is established, based on the following grounds for the next two (02) weeks:

a) The approved monthly operation plan;

b) The load forecast results for the next two (02) weeks;

c) The updated power source and grid maintenance and repair plan;

d) Customer requests to adjust the maintenance and repair plan for customers using distribution networks with their own substations and electricity distribution and retail units.

2. In case there are changes compared to the monthly maintenance and repair plan, large customers using distribution networks, electricity distribution and retail units must provide the Electricity Distribution Unit with the information specified in Clause 1 of Article 64 of this Circular before 16:30 on Tuesday of the two (02) weeks prior.

3. In case there is a need for maintenance and repair work within the scope of the distribution network under their management, before 16:30 on Tuesday each week, customers using distribution networks with their own substations connected at medium voltage level shall be responsible for registering the maintenance and repair plan with the Electricity Distribution Unit to coordinate the establishment of the next week's maintenance and repair plan, including the following information:

a) List of equipment requiring separation for maintenance and repair;

b) Reasons for separating the equipment;

c) Estimated start and end times of the maintenance and repair work.

4. Before 16:30 on Thursday each week, based on the monthly maintenance and repair plan and the information provided by customers using distribution networks, the Electricity Distribution Unit must complete and publish the maintenance and repair plan for the next two (02) weeks on its website, including the following contents:

a) Names of electrical equipment and power lines to be maintained and repaired;

b) Reasons for maintaining and repairing the equipment and power lines;

c) Main content of the work;

d) Estimated start and end times for maintenance and repair work;

đ) Other relevant requirements for maintenance and repair work;

e) Scope of power supply interruption due to maintenance and repair work;

g) Estimated power capacity and energy not supplied due to maintenance and repair.

5. Before 16:30 on Friday each week, based on the weekly maintenance and repair plan published by the Electricity Distribution Unit, electricity distribution and retail units shall be responsible for establishing the maintenance and repair plan for low-voltage distribution networks within their management scope and notifying affected customers according to Decision No. 39/2005/QD-BCN.

Section 3

OPERATING PLAN

Article 67. Annual Operation Plan

1. The Electricity Distribution Unit shall be responsible for establishing the annual operation plan for the distribution system, including the following main contents:

a) Forecast of electricity demand for the upcoming year;

b) The annual maintenance and repair plan;

c) Estimated electricity generation volume for the upcoming year of power plants with installed capacity of 30 MW or less connected to the distribution network.

2. By December 1st each year, the Electricity Distribution Unit shall be responsible for completing the annual operation plan and publishing it on its website, while simultaneously notifying the annual operation plan of the 110kV grid, power generating units connected to the distribution network, and connection points with the transmission network to the System Operator and Electricity Market, Transmission Company, and other related Electricity Distribution Units for coordination in implementation.

Article 68. Monthly Operation Plan

1. The electricity distribution unit shall be responsible for establishing the monthly operation plan for the distribution power system based on the annual operation plan of the distribution power system that has been published, including the following contents:

a) Forecast of electricity demand for the upcoming month;

b) Maintenance and repair plan for the upcoming month;

c) Estimated amount of electricity generation for the upcoming month from each power plant with installed capacity of 30 MW or less connected to the distribution power grid.

2. Before the 25th of each month, the electricity distribution unit shall complete the monthly operation plan and publish it on its electronic information website, while also notifying the operation plan for the medium voltage and 110kV power grids, power generating units connected to the distribution power grid, and connection points with the transmission power grid to the system operation unit and electricity market, the transmission power unit, and other relevant distribution units for coordination and implementation.

Article 69. Weekly Operation Plan

1. The electricity distribution unit shall be responsible for establishing the operation plan for the distribution power system for the next two (02) weeks based on the published monthly operation plan, including the following contents:

a) Forecast of electricity demand for the next two (02) weeks;

b) Maintenance and repair plan for the next two (02) weeks;

c) Estimated time and scope of power supply interruption for the next two (02) weeks;

d) Estimated production volume and generation capacity for the next two (02) weeks from each power plant with installed capacity of 30 MW or less connected to the distribution power grid.

2. By 15:00 hours on Thursday of each week, the electricity distribution unit shall complete the operation plan for the next two (02) weeks and publish it on its electronic information website, while also notifying the operation plan for the medium voltage and 110kV power grids, power generating units connected to the distribution power grid, and connection points with the transmission power grid to the system operation unit and electricity market, the transmission power unit, and major customers using the distribution power grid for coordination and implementation.

3. By 15:00 hours on Friday of each week, based on the weekly operation plan, the electricity distribution unit and the distribution and retail electricity unit shall complete the operation plan for the low-voltage power grid and notify affected customers within their management area.

Article 70. Daily Operation Method

1. Each day, based on the published weekly operation plan, the electricity distribution unit shall establish the daily operation method, including the following contents:

a) List of power sources and power grids under maintenance and repair;

b) Estimated time and scope of power supply interruption for the next day;

c) Estimated hourly production volume and generation capacity for the next day from each power plant with installed capacity of 30 MW or less connected to the distribution power grid.

2. By 15:00 hours each day, the electricity distribution unit shall complete and publish the daily operation method on its electronic information website.

Article 71. Operation of the Distribution Power System

1. The electricity distribution unit shall operate the distribution power system according to the published daily operation method, complying with the National Power System Dispatching Procedures and related regulations.

2. Customers using the distribution power grid with their own substation shall be responsible for complying with the dispatch orders of the dispatch authority controlling the distribution power grid, coordinating and providing information to the electricity distribution unit to serve the dispatch of the distribution power system.

Section 4

EMERGENCY OPERATION

Article 72. Emergency Situations Emergency Situations

1. An emergency situation on the distribution power system is a situation where there is a total or partial blackout of the transmission power system or the distribution power system, affecting normal operation or causing widespread power outages in the distribution power system.

2. Emergency situations include:

a) A complete or partial collapse of the transmission power system leading to an impact on the normal operation mode of the distribution power system;

b) An incident on the transmission power system resulting in a part of the distribution power system operating in an isolated islanding condition;

c) An incident on the distribution power line or substation transformer at 110kV voltage level causing widespread power outages in the distribution power system.

Article 73. Operation of the Distribution Power System in Case of Incidents or Complete or Partial Collapse of the Transmission Power System

1. In case an incident on the transmission power system affects normal operation or causes a power outage on the distribution power grid, the Distribution Power Unit shall be responsible for:

a) Immediately contacting the System Operation Unit and Electricity Market Operator, and the Transmission Power Unit to obtain information about the expected duration of the power outage and the scope of impact on the load of the distribution power system due to this incident;

b) Applying load control measures and other operational measures to minimize the impact range caused by the incident on the transmission power system.

2. In case a complete or partial collapse of the transmission power system affects normal operation or causes a power outage on the distribution power grid, the Distribution Power Unit shall be responsible for:

a) Adhering to the Black Start Procedure and National Power System Restoration Process and the Transmission System Regulations;

b) Isolating the distribution power grid under its management into separate load zones according to the National Power System Dispatching Procedures;

c) Restoring loads in priority order in accordance with the method approved by the System Operation Unit and Electricity Market Operator within the distribution power grid managed by the Distribution Power Unit;

d) Maintaining direct communication with the System Operation Unit and Electricity Market Operator until the power system is fully restored.

3. The Distribution Power Unit and large customers using the distribution power grid must maintain contact information, assign technical experts, and notify the relevant parties of the names, positions, and authorities of these experts to coordinate operations throughout the process of handling and restoring emergency situations.

Article 74. Operation of the Distribution Power System in the event of islanding

1. In case a part of the distribution power system is isolated, the Distribution Power Unit must consider and decide on the operation of power plants connected to this part of the distribution power grid. The Distribution Power Unit must command the dispatch of power plants to operate in isolation mode and ensure readiness to synchronize with the power system upon instruction from the System Operation Unit and Electricity Market Operator.

2. In case a power plant is designed to operate independently in isolation mode and has reached an agreement with the Distribution Power Unit, the power plant connected to the distribution power grid can operate in isolation mode using the self-use system and supply power to other customer loads or equipment under the following conditions:

a) The power plant is fully equipped with protective relay systems and control methods for units both in isolation mode and when connected to the distribution power system;

b) Ensuring the ability to identify and isolate incidents during isolation operation to protect the units and the distribution power grid of other customers using the isolated part of the distribution power grid;

c) Ensuring the neutral grounding standard of the isolated part of the distribution power grid.

3. In case the isolated part of the distribution power system does not have the capability to synchronize with the recovered part of the power system, the Distribution Power Unit must disconnect power plants connected to the isolated part of the distribution power grid to restore power supply to the isolated area from the recovered power system, then restore the operation of the disconnected power plants.

Article 75. Operation of the distribution power system in case of serious incidents on the distribution grid

In case of incidents on transmission lines or distribution substations at 110kV voltage level causing widespread power outages in the distribution power system, the Distribution Power Unit shall be responsible for:

1. Promptly isolating and handling the incident in accordance with the National Power System Incident Handling Procedures.

2. Notifying incident information to the System Operation Unit and electricity market, Transmission Power Unit, and major customers affected by the incident.

3. Changing connection methods to ensure maximum power supply capability to the distribution power system's load during the incident period.

Article 76. Restoration of the distribution power system

1. When the distribution power system collapses, operates in island mode, or experiences significant incidents on the distribution grid, the Distribution Power Unit shall coordinate with the System Operation Unit and electricity market, Transmission Power Unit, major customers using the distribution grid, and related units to restore the distribution power system to normal operation as soon as possible.

2. The Distribution Power Unit shall divide load zones suitable for black start capabilities of power plants, report to the System Operation Unit and electricity market, and ensure rapid restoration of the distribution power system.

3. Power plants connected to the distribution grid in island and synchronous operation modes must follow the dispatch orders of the Distribution Power Unit.

4. In cases where the distribution grid does not have power plants capable of self-starting for island operation, the distribution grid can only be restored from the transmission system, the Distribution Power Unit must implement the restoration of the distribution power system according to the orders of the System Operation Unit and electricity market. The Distribution Power Unit must restore loads in priority order and according to the approved plan.

5. The Distribution Power Unit shall notify major customers using the distribution grid to coordinate during the process of handling incidents and restoring the distribution power system.

Section 5

LOAD CONTROL AND VOLTAGE

Article 77. Load Control

Load control includes measures to stop, reduce power supply, shed load, or control the active power consumption of electrical loads according to voluntary registrations by electricity users participating in demand management programs to avoid grid collapse or overload.

Article 78. Stoppage and Reduction of Power Supply

1. The Distribution Power Unit shall implement stoppage and reduction of power supply according to the plan in compliance with the weekly operation plan published as stipulated in Article 69 3. For discounting transferable instruments and other securities:

2. The Distribution Power Unit may stop power supply outside the plan in the following cases:

a) At the request of the System Operation Unit and electricity market to ensure power supply security;

b) Occurrence of incidents or threats of incidents causing severe safety risks to people, equipment, and the power system;

c) In cases of force majeure on the distribution grid.

3. In cases of stoppage and reduction of power supply, the Distribution Power Unit or the Distribution and Retail Power Unit must follow the notification procedures to affected electricity users as prescribed in Decision No. 39/2005/QĐ-BCN.

Article 79. Development of Load Shedding Plans

1. The electricity distribution unit shall be responsible for developing load shedding plans within its management scope based on:

a) Requirements for safe operation of the power system;

b) Power supply interruption plans due to threats to power supply security by the system operator and the electricity market;

c) Priority order of loads;

d) Measures to minimize impacts on customers using the distribution network with the same priority level of power supply.

2. The load shedding plan must include levels of capacity, order of implementation, and time for load shedding.

3. By 15:00 on each Thursday, the electricity distribution unit shall complete and publish the load shedding plan for the next two (02) weeks.

Article 80. Measures for Load Shedding

1. Automatic load shedding is the shedding of loads by frequency relays to selectively cut off loads at medium voltage levels to maintain frequency within permissible limits and prevent widespread blackouts.

2. Directed load shedding is the shedding of loads upon request of the system operator and the electricity market or the electricity distribution unit in cases of insufficient power sources or system failures to ensure power supply security. The Distribution Unit, in cases of insufficient power sources or incidents on the electricity system to ensure power supply security.

Article 81. Implementation of Load Shedding

1. The electricity distribution unit must implement load shedding according to the published load shedding plan.

2. In cases of directed load shedding by the system operator and the electricity market or to protect the distribution network, the electricity distribution and retail units must notify customers using electricity in accordance with Decision No. 39/2005/QD-BCN.

3. After automatic load shedding or directed load shedding by the system operator and the electricity market, the electricity distribution unit shall be responsible for:

a) Reporting to the system operator and the electricity market about the capacity, time, area of loads shed, and levels of load shedding according to the set values of frequency relay actions;

b) Restoring shed loads upon orders from the system operator and the electricity market.

4. In cases where customer-managed loads are subject to automatic load shedding or directed load shedding from the electricity distribution unit, customers using the distribution network shall be responsible for:

a) Reporting to the electricity distribution unit about the capacity, time, area of loads shed, and levels of load shedding according to the set values of frequency relay actions;

b) Restoring shed loads upon orders from the electricity distribution unit.

Article 82. Voltage Control Implementation

1. The electricity distribution unit shall be responsible for calculating voltages at nodes on the distribution network within its management scope under various operating modes and coordinating with customers using the distribution network to maintain voltage quality through reactive power control measures and transformer tap adjustments.

2. Customers using the distribution network shall be responsible for coordinating operations with the electricity distribution unit to maintain voltage on the distribution system as agreed.

Article 83. Remote Monitoring and Control

1. The electricity distribution unit and large customers using the distribution network shall agree on monitoring and control methods.

2. The electricity distribution unit shall be responsible for installing remote measurement stations and necessary integrated equipment to monitor the customer's power grid when both parties have an agreement. In such cases, the electricity distribution unit must install necessary remote control stations, including control parts for circuit breakers and have the authority to control circuit breakers within the customer's power grid.

3. Large customers using the distribution network shall be responsible for cooperating with the electricity distribution unit in the installation and operation of remote control and monitoring systems.

Section 6

INFORMATION EXCHANGE IN OPERATIONS AND REPORTING REGIMES

Article 84. Forms of Information Exchange

1. Electricity distribution units, Large Consumers using distribution networks, and other electricity distribution units must agree on a unified form of information exchange to ensure continuous and smooth communication operations 24/7.

2. Electricity distribution units and Large Consumers using distribution networks must designate staff responsible for operational communication and exchange lists of such staff and operation personnel.

Article 85. Operational Information Exchange Industry and operation

1. The electricity distribution unit is responsible for notifying Large Consumers using distribution networks when it observes that the operation mode of the distribution network may affect the operation mode of the distribution network or generator sets of consumers, including the following information:

a) The operation mode of the distribution network system and possible impacts on the distribution network or generator sets of consumers;

b) Causes leading to impacts on the distribution network or generator sets of consumers.

2. Large Consumers using distribution networks are responsible for immediately notifying the electricity distribution unit when they observe that their operation mode of the distribution network or generator sets may affect the distribution network, including the following information:

a) Causes leading to changes in the operation mode of the distribution network of consumers;

b) Possible impacts on the distribution network of the electricity distribution unit.

Article 86. Notification of Abnormal Situations

1. An abnormal situation is a situation where the distribution network system experiences an incident, a threat of an incident, or operating parameters fall outside the permissible range.

2. When an abnormal situation occurs in the distribution network system, the electricity distribution unit is responsible for:

a) Immediately notifying Large Consumers using distribution networks that may be affected by the incident;

b) Supplementing and clarifying the information provided to Large Consumers using distribution networks that own power plants upon request.

3. Large Consumers using distribution networks are responsible for immediately notifying the electricity distribution unit when an abnormal situation on their distribution network affects the distribution network system.

Article 87. Notification of Serious Incidents

1. A serious incident is an incident leading to the disconnection of transmission lines or distribution substations at 110kV voltage level from operation, causing widespread power outages in the distribution network system.

2. The electricity distribution unit or Large Consumers using distribution networks are responsible for immediately reporting information about incidents on their distribution networks after a serious incident occurs.

3. Notifications about serious incidents include the following main contents:

a) Date and time of the incident;

b) Duration of the incident;

c) Location of the incident and affected areas;

d) Equipment involved in the incident;

e) Brief description of the incident;

f) Cause of the incident (if known);

g) Anticipated time to resolve the incident;

h) Load shedding measures implemented (if any).

4. The electricity distribution unit or Large Consumers using distribution networks are responsible for supplementing and clarifying the contents in the serious incident notification upon request.

5. The electricity distribution unit is responsible for reporting serious incidents in writing to the Department of Industry and Trade where the incident occurred according to the contents stipulated in Clause 3 of this Article.

Article 88. Report on Operation Results of distribution systems

1. The electricity distribution unit shall regularly report on the implementation status and operation results of the distribution system annually and monthly. Such reports shall evaluate the implementation of the operational standards stipulated in Chapter II of this Circular; assess the operation results of the distribution system; the overload situation, equipment failures and their causes, and propose measures to ensure safe, reliable, and efficient grid operation.

2. Before January 31 each year, the electricity distribution unit must prepare a report on the operation results of the distribution system for the previous year; before the 5th day of each month, it must prepare a report on the operation results of the distribution system for the previous month and submit these reports to the Electricity Regulatory Authority and the System and Electricity Market Operator.

3. In case of emergency, the electricity distribution unit shall report the operation results of the distribution system according to the requirements of the Electricity Regulatory Authority.

Section 7

COORDINATION IN OPERATION

Article 89. Responsibilities for Coordination in Operation

1. The electricity distribution unit and customers using the distribution network with their own substation shall agree on responsibilities and control scope for equipment on the distribution network between both parties; appoint responsible persons for coordinating safe network and equipment operation.

2. The electricity distribution unit and customers using the distribution network with their own substation shall cooperate to establish and maintain necessary safety measures when performing work or testing within their management area.

3. The electricity distribution unit and customers using the distribution network with their own substation shall develop coordination procedures to ensure safety for personnel and equipment during operation and testing, including the following contents:

a) Principles and coordination procedures;

b) Responsibilities and authorities in controlling, operating, and testing the distribution system.

4. The electricity distribution unit and customers using the distribution network with their own substation shall be responsible for coordinating operations and storing, managing, updating, and exchanging related documents.

Article 90. Implementation Coordination in Operation

1. When performing work or operations on the network, the electricity distribution unit and customers using the distribution network with their own substation must comply with safety coordination regulations and other relevant dispatching and safe operation regulations.

2. The electricity distribution unit and customers using the distribution network with their own substation have the responsibility to coordinate the installation of warning signs, alarm devices, and safety instructions, providing appropriate tools at the work site to ensure safety.

3. The inspection, supervision, and control of equipment at the interface of operation boundaries must be carried out by persons designated by the electricity distribution unit and customers using the distribution network with their own substation.

Section 8

TESTING ON THE DISTRIBUTION SYSTEM

Article 91. General Requirements for Testing on the Distribution System

1. Testing on the distribution system includes testing on the network of the electricity distribution unit and the network, power plant, or electrical equipment of customers using the distribution network.

2. Testing can only be conducted within the working capacity of electrical equipment or power generation units and during the announced testing period, with the presence of representatives from all relevant parties and must follow current procedures and regulations.

3. The electricity distribution unit and customers using the distribution network must ensure that testing does not pose a danger to personnel or equipment on the distribution system.

4. Testing of electrical equipment at the point of interconnection with the transmission network must comply with Transmission System Regulations.

5. The party requesting testing shall bear the testing costs if the test results show that the distribution network or power generation unit meets the operational standards stipulated in this Circular or the parameters agreed upon in the interconnection agreement. If the test results show that the distribution network or power generation unit does not meet the operational standards stipulated in this Circular or does not match the parameters agreed upon in the interconnection agreement, then the owner of the distribution network or power generation unit that fails to meet the operational standards shall pay the testing costs.

Article 92. Cases for conducting equipment testing on distribution networks

1. Periodic testing of equipment on distribution networks.

2. Unscheduled testing of equipment on distribution networks in the following cases:

a) To ensure the safety and reliability of the distribution network;

b) When customers using the distribution network complain about violations of power quality on the distribution network as stipulated in Chapter II of this Circular or in the Interconnection Agreement;

c) At the request of the Distribution Unit when it notices that the customer's equipment on the distribution network adversely affects the distribution network.

Article 93. Cases for conducting generator testing

1. The Distribution Unit has the right to test each generator connected to the distribution network not more than two (02) times per year, except in the following cases:

a) Test results determine that one or more operational characteristics of the generator do not match the characteristics recorded in the Interconnection Agreement;

b) When the Distribution Unit and the customer owning the power plant do not agree on the parameters and operational characteristics of the generator in the test results;

c) At the request of the customer owning the power plant;

d) Testing for fuel conversion.

2. Customers using the distribution network who own power plants have the right to request testing in the following cases:

a) To recheck the operational characteristics of the generator after each occurrence of damage related to the generator;

b) To test the generator after installation, major repairs, replacement, improvement, or reassembly.

Article 94. Responsibilities in testing equipment on distribution networks

1. The Distribution Unit is responsible for:

a) Conducting periodic testing of equipment on distribution networks within its operational management scope;

b) Conducting unscheduled testing on the distribution network when necessary to ensure safe and stable operation of the distribution network;

c) Conducting testing on the customer’s grid according to the request of the customer using the distribution network;

d) Coordinating with Transmission Units and other Distribution Units to conduct equipment tests at relevant interconnection points;

đ) Notifying in writing the customer using the distribution network and related units about the testing schedule.

2. Customers using the distribution network are responsible for:

a) Conducting grid and generator testing within their management scope;

b) Coordinating with the Distribution Unit in testing electrical equipment at the interconnection point with the distribution network;

c) Notifying in writing the Distribution Unit about the testing schedule;

d) Organizing regular testing and maintenance of electrical equipment connected to the distribution network, and annually submitting test records to the Distribution Unit for monitoring.

Article 95. Procedures and formalities for testing upon request is an electricity unit licensed to operate in the field of distribution and sale of electricity, including:

1. When there is a need for testing, the Distribution Unit is responsible for notifying in writing the large customers using the distribution network that will be interrupted or reduced in power supply due to testing at least fifteen (15) days before the planned testing date. The notification includes the following contents:

a) Purpose of testing;

b) Location of testing;

c) Expected testing time;

d) Items and sequence of planned testing;

đ) Plan for interruption or reduction in power supply due to testing requirements (if applicable). ||| electricity due to test requirements (if applicable).

2. In cases where testing is conducted within the management scope of large customers using the distribution network, if they disagree with the testing notification from the Distribution Unit, within seven (07) days from the receipt of the notification, the customer must notify again and propose a solution to reach an agreement with the Distribution Unit to adjust the testing plan.

Article 96. Procedure and Formalities for Testing at the Request of Large Customers Using Distribution Grids

1. When there is a need for testing, large customers using distribution grids must submit a written request for testing to the Distribution Unit, including the following contents:

a) a) Purpose of the test;

b) Reason for requesting the test;

c) Location and items to be tested;

d) Anticipated time to conduct the test.

2. In cases where the test involves generator sets, customers must provide the following additional information:

a) The history of the generator set;

b) Characteristics of the generator set;

c) Expected operating mode of the generator set during the test period.

3. Within seven (07) days from the date of receipt of the test request, the Distribution Unit shall be responsible for reviewing and requesting the customer to supplement necessary information.

4. Within fourteen (14) days from the date of receipt of a valid test request, the Distribution Unit shall be responsible for notifying the requesting customer and related units in writing about the test plan.

5. The Distribution Unit shall be responsible for notifying the requesting customer in writing of the test results after completing the test.

Article 97. Responsibilities After Testing

1. The Distribution Unit must adjust and upgrade equipment on the distribution grid if the test results show that the equipment on the distribution grid under the management and operation of the Distribution Unit does not meet the technical standards specified in Section 2 Chapter II of this Circular.

2. Large customers using distribution grids must adjust and upgrade their equipment within the agreed timeframe with the Distribution Unit if the test results show that their equipment does not meet the technical standards specified in Section 2 Chapter V of this Circular or the requirements in the Interconnection Agreement.

Chapter VII

MEASUREMENT OF ELECTRIC ENERGY

Section 1

GENERAL PROVISIONS ON ELECTRIC ENERGY MEASUREMENT

Article 98. Principles for Determining the Main Measurement Location

1. The main measurement location shall coincide or be adjacent to the interconnection point.

2. In cases where it is not possible to arrange the electric energy measurement system according to the provisions of Clause 1 of this Article or the main measurement location cannot ensure accurate measurement of the exchanged energy, the Distribution Unit and the Customer using the distribution grid or another Distribution Unit must agree on an alternative measurement location, while determining the method to convert the measured energy from the alternative location back to the interconnection point.

Article 99. Determination of Measurement Locations for High Voltage and Medium Voltage Levels

1. In cases where the Customer using the distribution grid is a Distribution and Retail Electricity Company and an Electricity User

a) For interconnection points at the 110kV voltage level, at each interconnection point, the main measurement location and one (01) backup measurement location must be determined;

b) For interconnection points at voltage levels from 1000V to 35kV, the Distribution Unit and the Customer using the distribution grid may agree on a backup measurement location if deemed necessary;

c) Interconnection points belonging to the substation of the Distribution Unit:

- The main measurement location is determined at the outgoing lines of the Distribution Unit's power station, except in cases of other agreements;

- The backup measurement location is determined through agreement between the Distribution Unit and the Customer using the distribution grid; d) Interconnection points belonging to the substation of the Customer using the distribution grid:

- The main measurement location is determined at the main circuit breaker or the high-voltage side terminal of the transformer directly connected to the distribution grid, except in cases of other agreements;

- The backup measurement location is determined through agreement between the Distribution Unit and the Customer using the distribution grid.

đ) In cases where the interconnection point differs from the provisions in points c and d of this clause, the main measurement location and the backup measurement location are determined through agreement between the Distribution Unit and the Customer using the distribution grid.

2. In cases where the Customer using the distribution grid owns generator sets:

a) For power plants interconnected at the 110kV voltage level, at each interconnection point, the main measurement location and two (02) backup measurement locations must be determined;

b) For power plants interconnected at voltage levels from 1000V to 35kV, at each interconnection point, the main measurement location and one (01) backup measurement location must be determined;

c) Interconnection points belonging to the substation of the Customer using the distribution grid with generator sets:

- The main measurement location is determined at the main circuit breaker or the high-voltage side terminal of the transformer directly connected to the distribution grid, except in cases of other agreements;

- The first backup measurement location is determined at the outgoing lines of the substation of the power plant, except in cases of other agreements;;

- The second backup measurement location, in cases of interconnection at the 110kV voltage level, is determined through agreement between the Distribution Unit and the Customer using the distribution grid with generator sets. d) Interconnection points not belonging to the substation of the Customer using the distribution grid with generator sets:

- If the substation of the Customer with generator sets interconnected to the distribution grid has only one connection line to the interconnection point and there is no power flowing around the busbar of the Customer's substation, then the main measurement location coincides or is adjacent to the interconnection point; If the Customer with generator sets has two (02) or more connection lines and there is power flowing around the busbar of the Customer's substation, the main measurement location is determined according to the provisions of point a of Clause 1 of this Article;

- Backup measurement locations are determined through agreement between the Distribution Unit and the Customer using the distribution grid with generator sets.

đ) In cases where the interconnection point differs from the provisions in points c and d of this clause, the main measurement location and the backup measurement locations are determined through agreement between the Distribution Unit and the Customer using the distribution grid with generator sets. 3. Interconnection points between two Distribution Units:

đ) In cases where the interconnection point differs from the provisions in points c and d of this clause, the main measurement location and the backup measurement locations are determined through agreement between the Distribution Unit and the Customer using the distribution grid with generator sets. For electricity distribution network users with generating sets connected through two (02) or more lines and having power flow through the customer's transformer busbar, the primary metering location shall be selected in accordance with the provisions of point a, Clause 1 of this Article;

- Backup metering locations are determined by agreement between the Distribution Unit and electricity distribution network users with generating sets.

d) In cases where the connection point differs from the provisions of points c and d of this Clause, the primary metering location and backup metering locations shall be determined by agreement between the Distribution Unit and electricity distribution network users with generating sets.

3. Connection Point Between Two Distribution Units:

The primary metering position and the backup metering position shall be determined by agreement between the Electricity Distribution Units.

4. Point of interconnection between the Electricity Distribution Unit and the Electricity Retailer and the Electricity Consumer:

The primary metering position and the backup metering position (if any) shall be determined by agreement between the two parties.

Article 100. Determination of Metering Position for Consumers Using Low-Voltage Distribution Grids

The metering position for consumers using low-voltage distribution grids shall be determined at the point of connection of the consumer to the distribution grid, except where otherwise agreed.

Article 101. Electrical Energy Metering System

1. The electrical energy metering system must be installed at the primary metering position to accurately and fully measure the quantities of electricity received and delivered through the point of interconnection and to eliminate factors affecting the measurement results from the loop structure of the power system.

2. The backup electrical energy metering system shall be installed at the backup metering position to perform the following functions:

a) To replace the metering system at the primary metering position, serving as the basis for calculating the quantities of electricity bought and sold in cases where the metering system at the primary metering position operates inaccurately or experiences a fault;

b) To assist in monitoring and checking the measurement results of the metering system at the primary metering position when the metering system at the primary metering position is operating normally;

c) To combine with the metering system at the primary metering position and other backup metering systems to calculate the quantity of electricity received and delivered in certain special cases.

Section 2

TECHNICAL REQUIREMENTS FOR THE ELECTRICAL ENERGY METERING SYSTEM

Article 102. Configuration of the Electrical Energy Metering System

1. A complete configuration for the electrical energy metering system includes:

a) Current transformers;

b) Voltage transformers;

c) Electrical energy meters;

d) Electrical circuits and secondary cables;

đ) Data collection devices and data transmission lines;

e) Safety protection devices, sealing positions, and lead seals;

g) Auxiliary equipment, switching devices, isolation devices for testing, voltage transformer logic devices, and devices for measuring voltage and current.

2. The specific configuration of a metering system shall be determined based on the voltage level and the characteristics of the metering position.

Article 103. Electrical Energy Metering System for 110kV Voltage Level

1. Requirements for electrical energy meters:

a) Three-phase four-wire type;

b) Electronic integrated function and programmable type;

c) Multiple tariff rates;

d) Bidirectional active and reactive energy measurement according to four quadrants separately;

đ) Maximum power measurement function and load profile recording;

e) Suitable protocols for local and remote data collection and reading;

g) Powered from the secondary voltage measurement system and must ensure continued operation when losing one or two phase voltages;

h) Multiple password levels;

i) Sealing positions and lead seals ensuring that the terminals cannot be accessed or the settings changed without breaking the seal;

k) Data storage function for at least 60 days with a recording cycle not exceeding 30 minutes;

l) For the primary metering position, the active energy meter must meet accuracy class 0.2 according to IEC 62053-22 standard and accuracy class 2.0 according to IEC 62053-23 standard if measuring reactive energy or equivalent standards;

m) For the backup metering position, the active energy meter must meet accuracy class 0.5 according to IEC 62053-22 standard and accuracy class 2.0 according to IEC 62053-23 standard if measuring reactive energy or equivalent standards.

2. Requirements for current transformers used for electrical energy metering:

a) Secondary windings dedicated for the electrical energy meter;

b) Rated secondary current value of 1A or 5A;

c) Sealing positions at the terminal box cover of the secondary winding dedicated for the electrical energy meter ensuring that the circuit cannot be affected without breaking the seal;

d) Primary current transformers for metering must meet accuracy class 0.2 according to IEC 60044-1 standard or equivalent standards;

đ) Backup current transformers for metering must meet accuracy class 0.5 according to IEC 60044-1 standard or equivalent standards.

3. Requirements for voltage transformers used for electrical energy metering:

a) Secondary windings dedicated for the electrical energy meter;

b) Rated secondary system voltage of 100V or 110V;

c) Sealing positions at the terminal box cover of the secondary winding dedicated for the electrical energy meter ensuring that the circuit cannot be affected;

d) Primary voltage transformers for metering must meet accuracy class 0.2 according to IEC 60044-2 standard for inductive voltage transformers, IEC 60044-5 standard for capacitive voltage transformers or equivalent standards;

đ) Backup voltage transformers for metering must meet accuracy class 0.5 according to IEC 60044-2 standard for inductive voltage transformers, IEC 60044-5 standard for capacitive voltage transformers or equivalent standards.

Article 104. Measurement systems for voltage levels from 1000V to 35kV

1. Requirements for electrical energy meters:

a) Shall comply with the requirements stipulated in Points a, b, c, d, đ, g, h, i, k, Clause 1, Article 103 of this Circular;

b) For main measurement systems, active energy meters must achieve accuracy class 0.5 according to IEC 62053-22 standard and accuracy class 2.0 according to IEC 62053-23 standard if measuring reactive energy or other equivalent standards;

c) The accuracy class of backup measurement systems (if any) shall be determined by agreement between the Distribution Unit and the Customer using the distribution network;

2. Requirements for current transformers used for electrical energy metering:

a) Shall have separate secondary winding coils for measurement devices and active energy meters;

b) Rated secondary current value of 1A or 5A;

c) Shall have sealable positions on the cover of the secondary winding coil connection box for measurement devices and active energy meters to ensure that the electrical circuit cannot be affected without breaking the seal;

d) Current transformers for main measurements must achieve accuracy class 0.5 according to IEC 60044-1 standard or other equivalent standards;

e) The accuracy class of current transformers for backup measurements (if any) shall be determined by agreement between the Distribution Unit and the Customer using the distribution network;

3. Requirements for voltage transformers used for measuring active energy

a) Shall have separate secondary winding coils for measurement devices and active energy meters;

b) Rated secondary system voltage of 100V or 110V;

c) Shall have sealable positions on the cover of the secondary winding coil connection box for measurement devices and active energy meters to ensure that the electrical circuit cannot be affected;

d) Voltage transformers for main measurements must achieve accuracy class 0.5 according to IEC 60044-2 standard for induction type voltage transformers, IEC 60044-5 standard for capacitor type voltage transformers, or other equivalent standards;

e) The accuracy class of voltage transformers for backup measurements (if any) shall be determined by agreement between the Distribution Unit and the Customer using the distribution network;

Article 105. Low-voltage measurement systems

1. Requirements for electrical energy meters:

a) Shall be three-phase four-wire or three-phase three-wire type for three-phase meters and single-phase two-wire type for single-phase meters;

b) Shall have sealable positions, lead seals ensuring that the terminals and settings inside the meter cannot be accessed or changed without breaking the seal;

c) For three-phase meters, active energy meters must achieve accuracy class 1.0 according to IEC 62053-21 standard for electronic type meters, IEC 62053-11 standard for induction type meters, or other equivalent standards. For single-phase meters, active energy meters must achieve accuracy class 2.0 according to IEC 62053-21 standard for electronic type meters, IEC 62053-11 standard for induction type meters, or other equivalent standards;

2. Requirements for current transformers when used for low-voltage energy measurement:

a) Shall have separate secondary winding coils for measurement devices and active energy meters;

b) Rated secondary current value of 1A or 5A;

c) Shall have sealable positions on the cover of the secondary winding coil connection box for measurement devices and active energy meters to ensure that the electrical circuit cannot be affected without breaking the seal;

d) Must achieve accuracy class 0.5 according to IEC 60044-1 standard or other equivalent standards;

Article 106. Technical requirements for measurement circuits

1. The secondary cables of the measurement circuit must follow the shortest path, have the least number of connection points through terminal blocks, and must have conditions to implement sealing and lead sealing of the measurement circuit at connection points;

2. For 110kV measurement systems, the secondary windings of CTs, VTs, and secondary cables connected to the main system's active energy meters shall not be used for any other purpose and must be completely independent of the backup measurement system. The secondary cables of the main measurement system must run separately and connect directly from the CT, VT connection box to the meter cabinet without passing through terminal blocks in intermediate cabinets;

3. In cases where the meter is supplied with voltage from one of the VTs through a voltage switching device, the terminals of the voltage switching device must ensure sealing and lead sealing conditions, and the active energy meter must be programmed to record the switching time and duration;

4. The load of the secondary circuit of CTs, VTs including active energy meters shall not exceed the rated load of CTs, VTs;

5. In cases where the current circuit of the backup measurement system shares with other measurement devices, it must ensure that it does not affect the accuracy of the measurement system and has conditions to implement sealing and lead sealing of the entire current circuit, measurement devices, and active energy meters;

6. Test connection boxes must be installed to serve testing of measurement devices and have conditions for sealing and lead sealing.

Article 107. Technical requirements for sealing lead seals and security

1. The entire electricity metering system including the CT, VT terminal box, electricity consumption meter, clamps, connectors, current circuit, voltage circuit, auxiliary equipment, logic conversion circuit, meter cabinet, communication network must be sealed with lead seals to prevent unauthorized interference.

2. For electronic electricity consumption meters, the meter software must have password protection with different levels of access rights.

3. In cases where the Electricity Distribution Unit installs and operates automatic data collection systems, the following requirements must be met:

a) Data on electricity consumption after being read and transmitted to the server at the measurement point must be encrypted to prevent unauthorized changes;

b) Management software for reading, transmitting, and consolidating electricity consumption data must be secured with multiple password levels to ensure the confidentiality, accuracy, and reliability of the measurement data.

Section 3

INVESTMENT, INSTALLATION AND MANAGEMENT OF ELECTRICITY METERING SYSTEMS

Article 108. Responsibilities for investment and installation of electricity metering systems

1. At connection points between the Electricity Distribution Unit and other Electricity Distribution and Retail Units, and electricity users

a) The Electricity Distribution Unit shall be responsible for:

- Investing in and installing primary metering systems, backup metering systems, data collection systems at measurement points, and related data collection devices if necessary;

- Ensuring that the measurement points comply with agreed-upon measurement locations among relevant units;

- Ensuring that the installed metering and data collection systems meet technical requirements and are consistent with the agreed-upon metering system design and relevant legal regulations on measurement;

- Taking the lead in performing the following tasks:

+ Testing and initial calibration of metering equipment, programming, and setting working parameters of electricity meters within the metering systems;

+ Implementing measures to seal metering equipment including meters, CTs, VTs, measuring circuits, clamps, intermediate cabinets to ensure the security of the metering system;

+ Developing acceptance plans for metering systems and coordinating with relevant units.

b) Electricity users and Electricity Distribution and Retail Units shall cooperate with the Electricity Distribution Unit to install and inspect the entire metering system when the measurement point falls within the user's power grid range.

2. At connection points between the Electricity Distribution Unit and power plants

a) Users of distribution grids who own generating units shall be responsible for investing in and installing metering systems according to the provisions set out in point a, Clause 1 of this Article;

b) The Electricity Distribution Unit shall coordinate with users of distribution grids who own generating units during the installation and inspection of the entire metering system.

3. At connection points between two Electricity Distribution Units

The responsibility for investing in metering systems at connection points shall be carried out according to agreements between the Electricity Distribution Units.

4. At connection points between Electricity Distribution and Retail Units and electricity users

a) Electricity Distribution and Retail Units shall be responsible for investing in and installing electricity metering systems according to the provisions set out in point a, Clause 1 of this Article;

b) Electricity users shall cooperate with Electricity Distribution and Retail Units to install and inspect the entire metering system when the measurement point falls within the user's power grid range.

Article 109. Responsibility for managing and operating the metering system

1. The investment unit or owner of the metering system shall be responsible for managing, operating, and performing regular inspection, calibration, and maintenance work on the metering system.

2. The electricity distribution unit must agree with the electricity distribution network users and other electricity distribution units connected to its network to coordinate in managing, operating, maintaining, and replacing the metering systems to ensure that the metering systems operate accurately, stably, reliably, and securely.

3. During the management and operation process, the electricity distribution unit and the electricity distribution network users have the responsibility to continuously monitor and inspect the operational status of the metering system. In case of detecting any abnormalities or incidents within the metering system, they must immediately notify the relevant parties to cooperate in handling them.

Article 110. Responsibility for establishing procedures for managing and operating the metering system

The Electricity Regulatory Authority is responsible for organizing, developing, and promulgating the Procedures for Metering System Handover and Operation.

Chapter VIII

EXEMPTION FROM IMPLEMENTATION

Article 111. Cases eligible for exemption from implementation

Units subject to this Circular are entitled to submit applications for exemption from implementation in the following cases:

1. Đã có hợp đồng được ký trước thời điểm Thông tư này có hiệu lực mà hợp đồng có nội dung khác với quy định tại Thông tư này.

2. Việc áp dụng Thông tư này làm tăng chi phí quá mức và không hợp lý cho đơn vị đó.

3. Đơn vị chứng minh được việc được hưởng miễn trừ phù hợp với các nguyên tắc của Thông tư này.

Điều 112. Thẩm quyền và căn cứ quyết định miễn trừ thực hiện

1. Cục Điều tiết điện lực có trách nhiệm xem xét và chấp thuận các trường hợp miễn trừ thực hiện theo quy định tại Điều 111 Thông tư này.

2. Các căn cứ để xem xét miễn trừ thực hiện bao gồm:

a) Quyền của các bên trong các hợp đồng mua bán điện, Thỏa thuận đấu nối đã được ký kết trước khi Thông tư này có hiệu lực;

b) Chi phí phát sinh cho các đơn vị có liên quan để đáp ứng các quy định của Thông tư này;

c) Ý kiến của Đơn vị vận hành hệ thống điện và thị trường điện về ảnh hưởng của việc miễn trừ thực hiện tới việc đảm bảo các tiêu chuẩn vận hành được quy định tại Chương II Thông tư này;

d) Phạm vi và thời hạn đề nghị được hưởng miễn trừ thực hiện;

đ) Các căn cứ khác liên quan đến việc hưởng miễn trừ (nếu có).

Điều 113. Hồ sơ đề nghị miễn trừ thực hiện

Hồ sơ đề nghị miễn trừ thực hiện bao gồm:

1. Văn bản đề nghị hưởng miễn trừ phải kèm theo các nội dung quy định tại khoản 2 Điều 112 Thông tư này.

2. Bản sao hợp lệ Giấy phép hoạt động điện lực đối với Đơn vị điện lực.

3. Giải trình chi tiết ảnh hưởng đến vận hành của hệ thống điện và các cam kết nếu được miễn trừ thực hiện.

Điều 114. Thủ tục thẩm định hồ sơ đề nghị miễn trừ thực hiện

1. Trong thời hạn bảy (07) ngày kể từ ngày tiếp nhận hồ sơ đề nghị miễn trừ thực hiện, Cục Điều tiết điện lực có trách nhiệm thông báo bằng văn bản cho đơn vị nộp hồ sơ về tính hợp lệ của hồ sơ. Trong trường hợp hồ sơ chưa hợp lệ, Cục Điều tiết điện lực có trách nhiệm thông báo những nội dung cần bổ sung.

2. Trong thời hạn ba mươi (30) ngày làm việc kể từ khi nhận đủ hồ sơ hợp lệ, Cục Điều tiết điện lực phải hoàn thành thẩm định hồ sơ đề nghị miễn trừ thực hiện và có trách nhiệm ban hành văn bản cho phép miễn trừ thực hiện. Trường hợp không chấp thuận đề nghị miễn trừ thực hiện, Cục Điều tiết điện lực phải có văn bản thông báo cho đơn vị đề nghị, nêu rõ lý do không chấp thuận.

3. Trường hợp đề nghị miễn trừ thực hiện có nhiều tình tiết phức tạp, liên quan tới nhiều đơn vị khác, cho phép gia hạn thời gian thẩm định nhưng không quá mười lăm (15) ngày làm việc.

4. Đơn vị nộp hồ sơ phải nộp chi phí thẩm định đề nghị miễn trừ thực hiện theo quy định.

Điều 115. Trách nhiệm cung cấp thông tin

Đơn vị phân phối điện, Đơn vị vận hành hệ thống điện và thị trường điện và các đơn vị liên quan có trách nhiệm cung cấp thông tin và có ý kiến bằng văn bản về đề nghị được miễn trừ thực hiện theo yêu cầu của Cục Điều tiết điện lực.

Điều 116. Rút đề nghị miễn trừ thực hiện

Trường hợp rút đề nghị được miễn trừ thực hiện, đơn vị nộp hồ sơ đề nghị miễn trừ thực hiện phải thông báo bằng văn bản tới Cục Điều tiết điện lực.

Điều 117. Bãi bỏ Quyết định cho phép miễn trừ thực hiện

Cục Điều tiết điện lực có quyền bãi bỏ Quyết định cho phép miễn trừ thực hiện trong các trường hợp sau:

1. Phát hiện có sự gian dối trong việc đề nghị được miễn trừ thực hiện.

2. Đơn vị được miễn trừ thực hiện không thực hiện hoặc thực hiện không đúng các điều kiện, nghĩa vụ đã cam kết và thời gian thực hiện quy định tại Quyết định cho phép miễn trừ thực hiện.

3. Các điều kiện cho phép miễn trừ thực hiện không còn tồn tại.

Chương IX

GIẢI QUYẾT TRANH CHẤP VÀ XỬ LÝ VI PHẠM

Điều 118. Giải quyết tranh chấp

Trường hợp xảy ra tranh chấp giữa các đơn vị liên quan đến việc thực hiện Thông tư này, các đơn vị có quyền trình vụ việc lên Cục Điều tiết điện lực để giải quyết theo quy định về trình tự, thủ tục giải quyết tranh chấp trong hoạt động điện lực do Bộ Công Thương ban hành.

Điều 119. Xử lý vi phạm

1. Khi phát hiện hành vi vi phạm các quy định tại Thông tư này, các tổ chức, cá nhân có quyền trình báo Cục Điều tiết điện lực.

2. Trình báo về hành vi vi phạm phải nêu rõ các thông tin sau đây:

a) Tổ chức, cá nhân vi phạm quy định của Thông tư này;

b) Hành vi vi phạm;

c) Thời gian vi phạm;

d) Các tổ chức, cá nhân bị ảnh hưởng do hành vi vi phạm;

đ) Các thông tin khác có liên quan (nếu có).

3. Cục Điều tiết điện lực có quyền yêu cầu các bên có liên quan cung cấp thông tin về hành vi vi phạm trong quá trình kiểm tra và xử lý vi phạm.

Chương X

TỔ CHỨC THỰC HIỆN

Điều 120. Thời hạn đáp ứng các tiêu chuẩn của Quy định hệ thống điện phân phối

1. Trong thời hạn một (01) năm kể từ ngày Thông tư này có hiệu lực, Khách hàng sử dụng lưới điện phân phối có trách nhiệm đầu tư nâng cấp các trang thiết bị để đáp ứng các tiêu chuẩn được quy định tại Thông tư này.

2. Trong thời hạn hai (02) năm, kể từ ngày Thông tư này có hiệu lực, đối với khu vực lưới điện phân phối hiện tại chưa đáp ứng các tiêu chuẩn quy định tại Thông tư này, Đơn vị phân phối điện có trách nhiệm đầu tư, nâng cấp lưới điện để đáp ứng các tiêu chuẩn được quy định tại Thông tư này.

Điều 121. Tổ chức thực hiện

1. Cục Điều tiết điện lực có trách nhiệm phổ biến, hướng dẫn và kiểm tra việc thực hiện Thông tư này.

2. Trong quá trình thực hiện nếu có vướng mắc, các đơn vị phải báo cáo Cục Điều tiết điện lực để xem xét và đề xuất Bộ Công Thương sửa đổi, bổ sung Thông tư.

Điều 122. Hiệu lực thi hành

1. Thông tư này có hiệu lực thi hành kể từ ngày 15 tháng 9 năm 2010.

2. Bãi bỏ Quyết định số 37/2006/QĐ-BCN ngày 16 tháng 10 năm 2006 của Bộ trưởng Bộ Công nghiệp ban hành Quy định đấu nối vào hệ thống điện quốc gia./.