CIRCULAR NO 252016TT BCT DATED NOVEMBER 30, 2016, REGULATIONS ON ELECTRICITY TRANSMISSION SYSTEM

THE MINISTRY OF INDUSTRY
AND TRADE
--------

SOCIALIST REPUBLIC OF VIETNAM
Independence – Freedom - Happiness
----------------

No. 25/2016/TT-BCT

Hanoi, November 30, 2016

CIRCULAR
REGULATIONS ON ELECTRICITY TRANSMISSION SYSTEM
Pursuant to the Government's Decree No. 95/2012/ND-CP dated November 12, 2012, defining the
functions, tasks, powers and organizational structure of the Ministry of Industry and Trade;
Pursuant to the Law on Electricity dated December 03, 2004 and the Law on Amendments to a
number of articles of the Law on Electricity;
Pursuant to the Government's Decree No. 137/2013/ND-CP dated October 21, 2013 detailing the
implementation of a number of articles of the Law on Electricity and the Law on Amendments to the
Law on Electricity;
At the request of general director of Electricity Regulatory Authority,
The Minister of Industry and Trade promulgates the Circular stipulating electricity transmission
system.
Chapter I

GENERAL PROVISIONS
Article 1. Governing scope
This Circular stipulates:
1. Requirements of operation of the electricity transmission system
2. Load forecasts

3. Transmission grid development plan
4. Technical requirements and procedures for connection to transmission grid.
5. Assessment of electricity system security
6. Operation of electricity transmission system
Article 2. Regulated entities
1. This Circular applies to:
a) Transmission network operator;
b) Electricity system and market operator;
c) Electricity wholesalers;
d) Electricity distribution units;
dd) Electricity retailers;
e) Generating units;
g) Electricity customers receiving electricity from transmission grid (hereinafter referred to as
“electricity customers”);
h) Vietnam Electricity;
i) Other organizations, individuals.
2. Generating sets of a power plant with total installed capacity greater than 30 MW connected to
distribution grid must meet technical requirements of equipment connected to transmission grid and
other relevant requirements prescribed herein.
Article 3. Interpretation of terms
In this Circular, some terms are construed as follows:
1. AGC (Automatic Generation Control) is an automatic equipment system for adjusting active power
of generating sets to maintain stability of electricity system frequency within permissible scope
according to operating principles of generating sets.
2. Electricity system security is the ability of the system to supply power to meet demands for loads at
a certain point of time or for a specified period with account taken of electricity system obligations.


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

generating set within permissible limits.
4. Voltage level is one of nominal voltage values of a system, including:
a) Low voltage: nominal voltage level to 01 kV;
b) Medium voltage: nominal voltage level over 01 kV to 35 kV;
c) High voltage: nominal voltage level over 35 kV to 220 kV;
d) Ultra- high voltage: nominal voltage level over 220 kV.
5. Dispatching level with control authority (hereinafter referred to as “the dispatch level”) is a
dispatching level that has the right to direct and dispatch the electricity system under the dispatching
hierarchy prescribed in the Dispatch Procedure of national electricity system promulgated by the
Ministry of Industry and Trade.
6. Available capacity of a generating set is the maximum generating capacity of the generating set for
a specified period of time.
7. Governor deadband is a frequency band within which any change of electricity system frequency
shall not result in reactions or impacts of the governor for adjusting primary frequency.
8. Spinning reserve is the ability of a generating set operating in the national electricity system to
increase or decrease generating capacity to restore electricity system frequency to permissible scope
after a single fault and restore reserve capacity of frequency control.
9. Primary frequency adjustment is the process of adjusting electricity system frequency immediately
by a large number of generating sets equipped with a governor.
10. Secondary frequency adjustment is the adjustment process following the primary frequency
adjustment carried out through the impact of AGC system on some generating sets specified in the
system or load shedding system under the frequency or dispatching instructions
11. Electricity system dispatching is activities of directing and controlling the process of power
generation, transmission and distribution in the national electricity system according to the defined
procedures, technical regulations and operation modes.
12. Electricity wholesaler is the electricity unit that is granted the operation licence in electricity
wholesaling. According to level of competitive electricity market, an electricity wholesaler shall be one
of the following units:
a) Electric Power Trading Company;
b) Power Corporations;

c) Other electricity wholesalers which are established according to individual levels of competitive
electricity market.
13. Generating unit is an electricity unit which is granted the operation licence in power generation,
possesses one or several power plants connected to the transmission grid or a power plant of over 30
MW in installed capacity connected to distribution grid.
14. Electricity distributor means the electricity unit that is granted the operation licence in electricity
distribution, including:
a) Power Corporations;
b) Electricity companies of provinces, central-affiliated cities (hereinafter referred to as “provincial
electricity companies”) affiliated to Power Corporations.
15. Electricity retailer is an electricity unit that is granted the operation licence in electricity retailing.
16. Transmission network operator is the electricity unit that is granted the operation licence in
electricity transmission responsible for management and operation of national transmission grid.
17. Electricity system and market operator (the national electricity system dispatch center) is the unit
responsible for directing and controlling the process of power generation, transmission and distribution
in the national electricity system and conducting transactions in electricity market.
18. Reliability of a protection system includes:
a) Impact reliability of the protection system is the factor indicating ability of the protection system to
work properly on an incident within the determined scope of protection;
b) Non-impact reliability of the protection system is the factor indicating ability of the protection system
to avoid malfunctioning at the normal operation mode or any incident arising beyond the determined
scope of protection.


19. Governor is a device used to regulate rotating speed of the turbine of a generating set according to
frequency changes to restore frequency to nominal electricity system frequency.
20. EMS (Energy Management System) is an energy management software system to optimize
operation of the electricity system.
21. DCS (Distributed Control System) is a system of control equipment in a power plant or power
station connected to the network on the principle of distributed control to increase reliability and restrict

effects caused by breakdown of control elements in the power plant or power station.
22. Electricity system is a system of generating equipment, electricity network and utilities connected
to each other.
23. The national electricity system is an electricity system which is managed in a uniform manner
across the country.
24. Electricity transmission system is an electricity system including a transmission grid and power
plants connected to the transmission grid.
25. SCADA (Supervisory Control and Data Acquisition) is a data collection system serving monitoring,
control and operation of the electricity system.
26. Earth-fault factor is the ratio between the voltage on a healthy phase during a fault and value of
voltage of such phase before the fault (in case of single or double phase to ground fault).
27. Synchronization is the act of connecting generating sets to the electricity system or two parts of the
electricity system together according to synchronization conditions prescribed in the operating
procedure in the national electricity system issued by the Ministry of Industry and Trade.
28. Black start capability is the ability of a power plant to restore at least one generating set to
operation from the state of complete stop and synchronize to the electrical grid without relying on
transmission network in the area.
29. Black start is the process of restoring all or part of an electricity system to operation from the state
of wholly or partial loss of power by using generating sets with black start capability.
30. Customers using transmission grid are organizations and/or individuals possessing electrical
equipment, electrical grid to connect to transmission grid, including:
a) Generating units;
b) Electricity distribution units receiving electricity direct from transmission grid;
c) Electricity retailers receiving electricity direct from transmission grid;
d) Electricity customers.
31. Dispatch instruction is an order of commanding and controlling operation mode of an electricity
system in real time.
32. Electrical grid is a system of transmission lines, power station and utilities for power transmission.
33. Distribution grid is a part of an electrical grid including transmission lines and power stations of up
to 110 kV.

34. Transmission grid is a part of an electrical grid including transmission lines and power stations of
over 110 kV.
35. Short-term flicker perceptibility (Pst) is a value measured for ten minutes by a flicker meter of
IEC868 standard.
36. Long-term flicker perceptibility (Plt) is a value calculated from 12 measurement results of short-term
perceptibility for about two hours in following formula:
Plt = 3

1
*
12

12

∑P

3
stj

j =1

37. Year N is the current year of operating an electricity system, calculated according to calendar
year.
38. Typical day is a day that has the typical day of consumption of loads as prescribed in the contents,
methods and procedure for electrical load research issued by the Ministry of Industry and Trade.
Typical days include typical working days, weekends, holidays (if any) of years, months and weeks.
39. Outage or reduction of power supply according to plan is the suspension of power supply to carry
out the plan for maintenance, repairs, overhaul and installation of electrical works; regulation and
restriction of loads in case of a shortage according to the plan as informed by the electricity system
and market operator.

40. Thermo-electric plant is a power plant operating on the principle of thermal to electrical energy
conversion including biomass, biogas and solid waste power plants.
41. Regulations on competitive electricity market operation are the regulations issued by the Ministry
of Industry and Trade and also the responsibility of the units in the electricity market by level.
42. Load shedding is the process of cutting loads from electricity system in case of incident or lack of
electricity system security, carried out through an automatic load shedding system or dispatch
instruction.
43. Breakdown is an event or one or several equipment in the electricity system causing a disruption
of power supply or affecting safe and stable supply of power to the national electricity system.
44. Single fault is a breakdown occurring in a single component of an electricity transmission system
as the electricity system is in normal operation mode.
45. Multi fault is a breakdown occurring in at least two components of an electricity transmission
system at the same time.
46. Serious fault is an breakdown causing extensive loss of power on the entire transmission grid, or
fire & explosion which damages people and property.
47. Electricity system split is a situation in which the national electricity system is separated into
disconnected small electricity systems by a fault.
48. RTU/Gateway (Remote Terminal Unit/Gateway) is a device placed at a power station or power
plant serving collection and transmission of data to SCADA system of the electricity system dispatch
center or control center.
49. PSS (Power System Stabilizer) is a device added to the automatic voltage regulator to decrease
voltage fluctuation in the electricity system.
50. Time of starting is a minimum period of time needed to start a generating set from the time the
generating unit receives the starting order from the electricity system and market operator to the time
the generating set is synchronized into the national electricity system.
51. N-1 criterion is a criterion for planning, design, investment, construction and operation of an
electricity system that ensures the electricity system operates normally in accordance with the
operating standards, permissible operating limits when a breakdown occurs in the system or a

component is taken from the system for maintenance and repairs.
52. IEC standards are electrotechnical standards issued by the International Electrotechnical
Commission.
53. Automatic under-frequency load shedding is the act of cutting loads by frequency relays when
frequency or frequency slope of the electricity system drops below permissible limit.
54. Power station is a substation, switching station or compensation station.
55. Control center is a center equipped with information technology and telecommunications
infrastructure system to remotely monitor and control a group of power plants, power stations or
switchgears on the electrical grid.
56. pu is a per-unit system expressing the ratio between actual value and rated value.
Chapter II

REQUIREMENTS FOR OPERATION OF ELECTRICITY TRANSMISSION SYSTEM
Article 4. Frequency
1. Nominal frequency of the national electricity system is 50 Hz. In normal operation mode, electricity
system frequency may fluctuate within ± 0.2 Hz compared with nominal frequency. In other operation
modes, permissible frequency band fluctuation and time for restoration of electricity system to normal
operation are prescribed in Table 1 below:
Table 1
Permissible frequency band fluctuations and time for restoration of electricity system to normal
operation at other operation modes of the national electricity system
Operation
mode

Single fault

Permissible
frequency band
fluctuations
49 Hz ÷ 51 Hz

Time of restoration since the time of fault (effective as of
January 01, 2018)
Unstable status (reset mode)

Restoration to normal
operation mode

Two minutes to bring the
frequency to range 49.5 Hz ÷

Five minutes to bring the
frequency to range 49.8 Hz ÷


50.5 Hz

50.2 Hz

Ten seconds to bring the
frequency to range 49 Hz ÷ 51
Hz
Five minutes to bring the
frequency to range 49.5 Hz ÷
50.5 Hz
2. Permissible frequency band and acceptable number of beyond-the-limit times (the number of times
the frequency may exceed the permissible limits) in case of multi fault, serious fault or extreme
emergency mode are determined according to annual or biennial cycle in Table 2 below:
Table 2
Permissible frequency band and acceptable number of beyond-the-limit times in case of multi fault,

serious fault or extreme emergency mode
Permissible frequency band (Hz)

Acceptable number of beyond-the-limit times

(“f” is electricity system frequency)

(from the beginning of the cycle)

52 ≥ f ≥ 51.25

Seven times a year

51.25 > f > 50.5

50 times a year

49.5 > f > 48.75

60 times a year

48.75 ≥ f > 48

12 times a year

48 ≥ f ≥ 47.5

Biennial

3. During the operation of the national electricity system, the electricity system and market operator

shall be responsible for dispatching and operating the national electricity system and mobilizing all
forms of ancillary services to ensure the frequency is within the permissible band.
Article 5. Stabilization of electricity system
1. Stabilization of an electricity system is the ability of the electricity system, with predetermined initial
conditions, to return to normal operation mode or reset mode after a physical impact has changed
operational parameters of the electricity system. Stabilization of electricity system is classified as
follows:
a) Transient stability is the ability of generating sets in the electricity system to maintain consistent
operational state when subjected to major disturbances.
b) Small signal stability is the ability of generating sets in the electricity system to maintain consistent
operational state when subjected to small disturbances;
c) Dynamic voltage stability is the ability of an electricity system to maintain steady voltage at all buses
when subjected to major disturbances.
d) Steady state voltage stability is the ability of an electricity system to maintain steady voltage at all
buses when subjected to small disturbances.
dd) Frequency stability is the ability of an electricity system to maintain steady frequency when
disturbances have caused loss of load-generation balance.
2. Sub-synchronous resonance is a phenomenon in which the resonant frequency of the turbine shaft
coincides with electricity system frequency resulting in torsional stress on the turbine shaft.
3. The national electricity system operating at normal operation modes or after the fault is cleared
must maintain consistency and meet electricity system stability standards prescribed in Table 3 below:
Table 3
Electricity system stability standards
Type of stability
Transient stability

Stability standards
Rotor angle not in excess of 120 degrees
Within 20 seconds after the fault is cleared, rotor angle fluctuation
must be stamped out.

Small signal stability

Damping ratio should not be less than 5%.

Dynamic voltage stability

Within five seconds after the fault is cleared, at least 75% of the
voltage must be restored.


The electricity system must a reserve capacity of at least 5% in
case a component is taken from the system (N-1).
Frequency stability

The electricity system must meet frequency stability standards as
prescribed in Clause 1, Article 4 herein.

Article 6. Voltage
1. Nominal voltage levels of a transmission grid are 500 kV, 220 kV.
2. In normal operation conditions or in case of a single fault in a transmission grid, permissible voltage
at busbars on the transmission grid is prescribed in Table 4 below:
Table 4
Voltage at busbars on transmission grid
Voltage level

Operation mode
Normal operation

Single fault

500 kV

475 ÷ 525

450 ÷ 550

220 kV

209 ÷ 242

198 ÷ 242

3. In case of a multi fault, serious fault, in an extreme emergency operation mode or electricity system
restoration mode, permissible voltage fluctuation on the transmission grid is greater than ± 10 % to ±
20 % compared with nominal voltage.
4. During the fault, voltage at the place where the fault occurs and surrounding areas may drop to 0 at
phases with fault or increase over 110% of the nominal voltage at phases without fault until the fault is
cleared.
Article 7. Phase balance
In normal operation mode, negative sequence voltage components are not allowed to exceed 3% of
nominal voltage on transmission grid.
Article 8. Harmonics
1. Permissible maximum value of total harmonic distortion (based on percentage of nominal voltage)
caused by high-level harmonic components to the voltage level 220 kV and 500 kv is not allowed to
exceed 3%.
2. Permissible maximum value of total demand distortion (based on percentage of nominal voltage) to
the voltage level 220 kV and 500 kv is not allowed to exceed 3%.
3. In normal operation mode, the transmission network operator shall ensure total harmonic distortion
on the transmission grid is within the range as prescribed in Clause 1, this Article.

4. Customers using transmission grid shall ensure harmonics in the equipment connected to the
transmission grid must not exceed the range as prescribed in Clause 2, this Article.
5. If total harmonic distortion shows signs of violation of the range as prescribed in Clause 1 or 2, this
Article, the customer using transmission grid or the transmission network operator has the right to
order other relevant units to inspect harmonic values or hire an independent testing unit to do the job.
If the result of inspection shows that the total harmonic distortion violates the range as prescribed in
Clause 1 or 2, this Article, all the expenses for inspection, verification, damage and implementation of
remedial measures shall be incurred by any entity that is found in breach of the regulation.
Article 9. Flicker perceptibility
1. Permissible maximum flicker perceptibility in a transmission grid is stipulated in Table 5 below:
Table 5
Flicker perceptibility
Voltage level

Plt95%

Pst95%

220 kV, 500 kV

0.6

0.8

Where: Plt95%, Pst95%: Threshold value of Plt, Pst respectively.
2. The transmission network operator shall control flicker perceptibility on the transmission grid to
ensure that the flicker perceptibility at connection point must not exceed the value prescribed in Table
5 in normal operation mode. Customers using transmission grid shall ensure flicker perceptibility on
the equipment connected to the transmission grid must not exceed the value as prescribed in Table 5.

3. If flicker perceptibility shows signs of violation of the range as prescribed in Clause 1, this Article,
the customer using transmission grid or the transmission network operator has the right to order other
relevant units to inspect flicker perceptibility or hire an independent testing unit to do the job. If the
result of inspection shows that the flicker perceptibility violates the range as prescribed in Clause 1,
this Article, all the expenses for inspection, verification, damage and implementation of remedial
measures shall be incurred by any entity that is found in breach of the regulation.
Article 10. Voltage fluctuation
1. Voltage fluctuations at connection points on the transmission grid by fluctuating loads shall be not
allowed to exceed 2.5% of nominal voltage and must be within permissible voltage values according to
each voltage level prescribed in Article 6 herein.
2. If a voltage divider is operated manually, the voltage fluctuations at the points connected to loads
are not allowed to exceed voltage value indicated by the transformer’s voltage divider.
3. Permissible adjustable voltage level is 5% of nominal voltage to a maximum provided that such
adjustment shall not cause damage to the equipment on electricity transmission system and
equipment belonging to customers using transmission grid.
Article 11. Neutral grounding
1. Neutral grounding of a transmission grid is the connection of the grid direct to the ground.
2. If the neutral grounding of some equipment in the transmission grid is in opposition to the provisions
prescribed in Clause 1, this Article, a written consent of the electricity system and market operator is
required.
Article 12. Short-circuit current and fault clearing time
1. Permissible maximum value of short-circuit current and fault clearing time by main protection on the
electricity system are stipulated in Table 6 below:
Table 6
Permissible maximum value of short-circuit current and fault clearing time by main protection
Voltage
level

Permissible

maximum shortcircuit current

Maximum fault
clearing time by
main protection

500 kV

50

220 kV

50

Minimum time of withstandibility of
equipment (s)
Effective up to
December 31, 2017

Effective as of
January 01, 2018

80

03

01

100

03

01

2. For 110 kV busbars of 500 kV or 220 kV transformers in the transmission grid, permissible
maximum short-circuit current is 40 kA/1s.
3. Total value of unsaturated sub transient reactance of a generating set (X d’’-%) and short-circuit
reactance of a terminal transformer (Uk-%) according to the per-unit system pu is not allowed to be
less than 40%.
If the aforesaid requirements cannot be met, the investor shall be responsible for installing further
reactance so that total value of Xd’’, Uk and electrical reactance according to the per-unit system is not
less than 40%.
4. If value of short-circuit current at connection point of any electrical works to an electricity
transmission system is greater than permissible maximum short-circuit as stipulated in Table 6, the
investor shall take measures to restrict the short-circuit current at connection points to a level lower or
equal to permissible maximum short-circuit current as stipulated in Table 6.
5. Main protection of an electrical equipment is a key element of protection which is installed and set to
make initial impacts, ensuring quickness, sensitivity, selectivity and reliability of impacts of the
protection system in case of a fault within the scope of protection.
6. If maximum short-circuit current exceeds the values as stipulated in Table 6, the transmission
network operator or customers using transmission grid shall be responsible for reporting to the
Electricity Regulatory Authority for instructions.
7. The transmission network operator shall be responsible for informing the customer using
transmission grid about maximum value of short-circuit current at connection point for coordination
during the investment and installation of equipment, ensuring that the switchgears are able to deenergize maximum short-circuit current at connection point at least for the next 10 years.
Article 13. Earth fault factor
Earth fault factor of a transmission grid at all voltage levels is not allowed to exceed 1.4.


Article 14. Reliability of transmission grid

1. Reliability of a transmission grid is determined by percentage of electrical production not supplied
annually due to outage or reduction of power supply outside and inside the plan, and faults on the
transmission grid causing loss of power to electricity customers.
2. Electrical production not supplied is calculated as the product of the load power suspended or
reduced and the corresponding time of suspension, reduction in case the loss of power lasts over one
minute, except for following cases:
a) Outage or reduction of power supply due to lack of power from national electricity system
b) Outage or reduction of power supply due to force majeure events.
3. Percentage of electrical production not supplied annually by a transmission grid is determined in
following formula:

∑ = 1(T × P )
=
n

k kccđ

i

i

i

Att

Where:
- kkccd: Percentage of electrical production not supplied in a year by a transmission grid;
- Ti: Time of outage or reduction of power supply lasting over one minute at time I is determined as the
period from the time of outage or reduction to the time power supply is restored (hour);
- Pi: Average load power suspended, reduced at time i (kW);

- n: Number of times of outage or reduction of power supply in a year;
- Att: Total electrical production transmitted through a transmission grid in a year (kWh).
Article 15. Loss of power on transmission grid
1. Annual loss of power on a transmission grid is determined in following formula:
∆A =

Attreceived - Attdelivered
Attreceived

Where:
- ΔA: Annual loss of power on a transmission grid;
- Attreceived: Total electrical production transmitted to the transmission grid in a year is the production
received by all the customers using transmission grid at connection points plus total electrical
production imported through the transmission grid;
- Attdelivered:Total electrical production delivered from the transmission grid in a year is the production the
electricity distribution units and electricity customers receive from connection points plus total electrical
production exported through the transmission grid;
Chapter III

LOAD FORECASTING FOR NATIONAL ELECTRICITY SYSTEM
Article 16. General provisions on load forecasting for national electricity system
1. Load forecasting for the national electricity system is forecasts on demand for loads to be supplied
by the national electricity system except loads from independent power supplies and not connected to
the national grid. Load forecasting for the national electricity system is grounds for making annual
electricity transmission system development plans, plans and methods for operation of electricity
system, electricity market.
2. Load forecasting for the national electricity system includes annual, monthly, weekly and daily
forecasts on loads and electricity market transaction cycle.
3. Responsibility for making forecasts
a) The electricity system and market operator shall make forecasts on loads for the national electricity

system, electricity systems in the Northern, Central and Southern Vietnam and connection points.
b) Electricity distribution units, electricity retailers and electricity customers shall provide load forecasts
to the electricity system and market operator including forecasts on demand for loads of the entire unit
and individual 110 kV transformers
c) Electricity wholesalers shall provide forecasts on exportation and importation of electricity to the
electricity system and market operator including forecasts on general demand and demands of
connection points serving exportation and importation of electricity.


4. Regarding forecasts on demand of connection points and resolution of load forecasting cycle and
depending on each stage of development and market demand, the Electricity Regulatory Authority
shall provide instructions on implementation of this regulation.
Article 17. Annual load forecasting
1. Annual load forecasting made for next year (year N+1) and the year thereafter (year N+2).
2. Figures serving annual load forecasting include:
a) Monthly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a
30-minute cycle for 104 weeks provided by electricity distribution units, electricity retailers and
electricity customers;
b) Monthly export, import forecasts concerning electrical energy, maximum capacity, typical daily
diagrams in a 30-minute cycle for 104 weeks provided by electricity wholesalers.
3. Elements taken into account for annual load forecasting:
a) Economic growth (GDP) for the next two years officially published by competent agencies;
b) Annual load forecasts and load factor under approved electricity development master plan;
c) Statistical figures on capacity, electrical energy consumed, exported and imported at least for at the
last five years by electricity distribution units, electricity retailers, electricity wholesalers and electricity
customers;
d) Solutions and targets of the plan for energy saving and demand management;
dd) Other necessary information.
4. Results of annual load forecasting for national electricity system include: Maximum capacity,
electrical energy, typical daily diagrams in a 30-minute cycle for 104 weeks of national, regional

electricity systems and connection points.
5. Implementation
a) Before August 01 annually, electricity distribution units, electricity retailers, electricity wholesalers
and electricity customers shall provide results of annual load forecasting to the electricity system and
market operator as prescribed in Clause 2, this Article.
If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and
electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity
system and market operator shall rely on last year’s figures to make forecasts on loads for the national
electricity system.
b) Before September 01 annually, based on the figures provided by relevant units, the electricity
system and market operator shall be responsible for completing and publishing results of annual load
forecasting on its website as prescribed in Clause 4, this Article.
Article 18. Monthly load forecasting
1. Monthly load forecasting made for next month.
2. Figures serving monthly load forecasting include:
a) Weekly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a
30-minute cycle every week provided by electricity distribution units, electrical retailers and electricity
customers;
b) Weekly export, import forecasts concerning electrical energy, maximum capacity, typical daily
diagrams in a 30-minute cycle every week provided by electricity wholesalers.
3. Elements taken into account for monthly load forecasting:
a) Results of monthly load forecasting in the published annual load forecasting;
b) Statistical figures on capacity, consumed, exported and imported electrical energy, maximum loads
in daytime and nighttime for the month year-on-year and the last three months provided by electricity
distribution units, electricity retailers, electricity wholesalers and electricity customers;
c) Events that may cause major changes to demand for loads and other necessary information.
4. Results of monthly load forecasting for national electricity system include: Maximum capacity,
electrical energy, typical daily diagrams for each week with a 30-minute cycle of national, regional
electricity systems and connection points.
5. Implementation

a) Before 20th every month, electricity distribution units, electricity retailers, electricity wholesalers and
electricity customers shall provide monthly load forecasts to the electricity system and market operator
as prescribed in Clause 2, this Article.
If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and
electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity
system and market operator shall rely on last month’s figures or results of annual load forecasting to
make forecasts on loads for national electricity system.
b) Before the last seven days every month, based on the figures provided by relevant units, the
electricity system and market operator shall be responsible for completing and publishing results of
month loading forecasting on its website as prescribed in Clause 4, this Article.
Article 19. Weekly load forecasting
1. Weekly load forecasting made for the next two weeks.
2. The figures serving weekly load forecasting include figures on capacity, electrical energy forecasts
in a 30-minute cycle every day of the next two weeks provided by electricity distribution units,
electricity retailers and electricity customers and 110 kV transformers.
3. Elements taken into account for weekly load forecasting:
a) Results of weekly load forecasting in the published monthly load forecasting;
b) Statistical figures on capacity, consumed electrical energy, maximum loads in daytime and
nighttime for the last four months provided by electricity distribution units, electricity retailers, electricity
wholesalers and electricity customers;
c) Daily weather forecasts for the next two weeks, public holidays, Tet holidays and events that may
cause major changes to demand for loads.
4. Results of weekly load forecasting for national electricity system include: Capacity, electrical energy
in a 30-minute cycle every day of the next two weeks of national, regional electricity systems and
connection points.
5. Implementation
a) Before 10:00 every Tuesday, electricity distribution units, electricity retailers, electricity wholesalers
and electricity customers shall provide weekly load forecasts to the electricity system and market

operator as prescribed in Clause 2, this Article.
If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and
electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity
system and market operator shall rely on last week’s figures or results of monthly load forecasting to
make forecasts on loads for national electricity system.
b) Before 15:00 every Thursday, based on the figures provided by relevant units, the electricity system
and market operator shall be responsible for completing and publishing results of weekly load
forecasting on its website as prescribed in Clause 4, this Article.
Article 20. Daily load forecasting
1. Daily load forecasting made for the next two days.
2. Elements taken into account for daily load forecasting:
a) Results of daily load forecasting in the published monthly load forecasting;
b) Figures on capacity, electrical energy of the electricity system of the last seven days or the holidays,
Tet holidays of last year if the figures fall within public holidays, Tet holidays;
c) Weather forecasts of the next two days and other necessary information.
3. Results of daily load forecasting for national electricity system include: Capacity, electrical energy in
a 30-minute cycle of national, regional electricity systems and connection points.
4. Before 10:00 every day, the electricity system and market operator shall be responsible for
completing and publishing results of daily load forecasting as prescribed in Clause 3, this Article.
Article 21. Load forecasting in a electricity market transaction cycle
1. Load forecasting made for next transaction cycle and eight cycles thereafter.
2. Elements taken into account for load forecasting in a transaction cycle:
a) Results of load forecasting from the published daily load forecasting and the electricity market
transaction cycle previously published;
b) Figures on capacity, electrical energy of the same period of last week;


c) Weather forecasts;
dd) Other necessary information.
3. Results of load forecasting in a electricity market transaction cycle include:

a) Capacity and production of the national electricity system and regional electricity systems in a 30minute cycle of the next transaction cycle and eight cycles thereafter;
b) Capacity and production at each point connecting the transmission grid and distribution grid in a 30minute cycle of the next transaction cycle and eight cycles thereafter.
4. At least 15 minutes before the next transaction cycle, the electricity system and market operator
shall be responsible for completing and publishing results of load forecasting of a transaction cycle as
prescribed in Clause 3, this Article.
Chapter IV

TRANSMISSION GRID DEVELOPMENT PLAN
Article 22. General principle
1. Annually, the transmission network operator shall be responsible for making a transmission grid
development plan for next year (year N+1) with account taken of the year thereafter (year N+2).
2. Annual transmission grid development plans shall be made based on:
a) Published annual load forecasting plans;
b) Approved national electricity development plans, provincial electricity development planning and
signed connection agreements;
c) Requirements for operation of the electricity system prescribed in Chapter II and technical
requirements of connection points prescribed in Chapter V herein;
d) Demand for loads and requirements for electricity system and market operation; ensuring the
national electricity transmission system operates in a safe, reliable and stable manner.
3. The electricity system and market operator shall be responsible for cooperating with the
transmission network operator during the process of transmission grid development plan formulation to
ensure investment, connection and operation of the power generation and electrical grid works meet
the requirements prescribed in Clause 2, this Article.
Article 23. Content of transmission grid development plan
The transmission grid development plan includes following subject matters:
1. Assessment of performance of the transmission grid to the end of June 30 of the current year.
2. Load forecasts in each point of delivery between the transmission grid and distribution grid for the
next year with account taken of the year thereafter.
3. Assessment of implementation of investment and estimated implementation of investment in the list
of transmission grids according to the approved transmission grid development plan until the end of

December 31 of current year.
4. List of power generation projects connecting to the transmission grid for next year with account
taken of the year thereafter accompanied by planned connection points, connection agreements for
these power generation projects.
5. List of information system works, SCADA system, RTU/Gateway, measurement system, data
collection system serving electricity market and electricity system operation and dispatching.
6. Results of calculation of reset modes of the electricity transmission system for each month next
year, dry and rainy seasons of the year thereafter including results of calculation of methods and
assessment of ability of the transmission grid to meet N-1 criterion.
7. Results of calculation of short-circuit current at 500 kV, 220 kV, 110 kV busbars on the transmission
grid in which the positions where maximum value of short-circuit current exceed 90% of permissible
maximum value as prescribed in Article 12 herein must be determined.
8. Results of calculation and analysis of stability of the electricity transmission system.
9. Results of calculation of reactive power compensation on the transmission grid.
10. Determination of obligations and constraints on the transmission grid that may have effect on safe
and stable operation of the electricity transmission system including effects on requirements for
stability of the electricity system as prescribed in Article 5 herein.
11. Proposals for norms of reliability and loss of power of the transmission grid for the next year
according to Article 14 and Article 15 herein.


12. Analysis of ability to meet operational requirements of the electricity system prescribed in Chapter
II and technical requirements of connection points prescribed in Chapter V herein, and proposals for
solutions to meet the prescribed requirements.
13. Analysis and selection of methods of investment in the transmission grid to ensure transmission of
all the power from power plants meeting demand for loads, technical requirements and lowest costs.
14. Lists and schedules of construction of transmission grid items by month of next year and by
quarter of the year thereafter. Fund plan for each project.
15. Proposals (if any).
Article 24. Responsibility for supplying information serving formulation of transmission grid

development plan
1. Generating units shall be responsible for supplying following information:
a) Lists of new power plants planned to be connected to the transmission grid in the next year with
account taken of two years thereafter, progress of investment and connection, and expected date of
operation of such power plants.
b) Main parameters of power plants shall be connected to the electricity transmission system and
information about connection points are stipulated in Annex 1B enclosed herewith;
c) Changes related to connection to existing power plants in the next year with account taken of two
years thereafter.
2. Electricity distribution units, electricity retailers and electricity customers shall be responsible for
providing following information:
a) Lists of connection points in the next year with account taken of the year thereafter; lists of
transmission grid projects to be invested and constructed;
b) Planned progress of energizing new connection points;
c) Maximum load capacity at new connection points and information about connection are specified in
Annex 1C enclosed herewith;
d) Expected proposals for changes to existing connection points in the next year with account taken of
the year thereafter.
3. The electricity system and market operator shall be responsible for providing following information:
a) Results of annual load forecasting as prescribed in Article 17 herein;
b) Expected demand for ancillary services in next year with account taken of the year thereafter;
c) Plan for mobilization of power supplies in the next year with account taken of the year thereafter.
4. Electricity wholesalers shall be responsible for supplying following information:
a) Exported, imported capacity and electrical energy;
b) Progress of putting new power generation projects into operation in the next year with account take
of two years thereafter.
Article 25. Procedures for formulation, approval and public announcement of transmission grid
development plans
1. Before August 01 annually, the transmission network operator shall be responsible for delivering
requests for supply of information and time limit of supply of information to the electricity market and

system operator, electricity wholesalers and customers using transmission grid (including customers
who need to establish new connections).
2. Before September 01 annually, the electricity system and market operator, electricity wholesalers
and customers using transmission grid shall be responsible for providing sufficient information as
prescribed in Article 24 herein to the transmission network operator.
3. Before October 15 annually, the transmission network operator shall be responsible for completing
draft plans for transmission grid development in the next year with account taken of the year
thereafter, and submitting requests to the electricity system and market operator for suggestions on
assessment of impacts of expected transmission grid projects on safety, stability and reliability of the
electricity transmission system.
4. Before November 01 annually, the transmission network operator shall be responsible for
completing the plan for transmission grid development in the next year with account taken of the year
thereafter and reporting to Vietnam Electricity.


5. Before November 15 annually, the transmission network operator shall be responsible for submitting
the plan for transmission grid development in the next year with account taken of the year thereafter
approved by Vietnam Electricity to Electricity Regulatory Authority.
6. Before December 15 annually, the Electricity Regulatory Authority shall conduct assessment, grant
approval and publish on its website the plan for transmission grid development in the next year with
account taken of the year thereafter.
7. Within 15 working days since the plan for transmission grid development is approved by Electricity
Regulatory Authority, the transmission network operator shall be responsible for publishing the plan on
its website.
Chapter V

CONNECTION TO TRANSMISSION GRID
Section 1. GENERAL PRINCIPLE
Article 26. Connection point
1. Connection points are the points connecting equipment, electrical grids and power plants of

customers using transmission grid with the electricity transmission system.
2. Depending on structure of the electrical grids and connection lines, connection points shall be
determined as follows:
a) Regarding overhead lines, connection points are the end points of the suspension string for
outgoing feeders connected to the disconnect switches of the substation or distribution area of the
power plant.
b) Regarding underground lines, connection points are the cosse of disconnector insulators on the
outgoing side of the substation or distribution area of the power plant.
3. Any connection point which is in opposition to provisions prescribed in Clause 2, this Article shall be
agreed by the two parties.
4. Connection points must be detailed in relevant drawings, diagrams and explanations in the
connection agreement or power purchase agreement (PPA).
Article 27. Borders of assets and operation management
1. Borders of assets between the transmission network operator and customers using transmission
grid are connection points.
2. Assets belonging to each party at connection point must be detailed and accompanied by relevant
drawings and diagrams or power purchase agreement (PPA).
3. Each party shall be responsible for investing, constructing and managing assets of its own in
accordance with standards and laws unless otherwise agreed.
Article 28. General requirements
1. The transmission network operator shall be responsible for developing transmission grids according
to approved electricity development planning and investment plan, ensuring transmission grid facilities
meet requirements of the electricity system as prescribed in Chapter II herein and technical
requirements of connection points prescribed in this Chapter.
2. Connecting electrical equipment, electrical grids and power plants of customers using transmission
grid with the transmission grid must be consistent with the electricity development planning approved
by competent state agencies, ensuring transmission grid facilities meet requirements of the electricity
system as prescribed in Chapter II herein and technical requirements of connection points prescribed
in this Chapter.
3. The transmission network operator shall be responsible for making notification to the electricity

customer of any connection proposed by such customer which is in opposition to the approved
electricity development planning. Any customer who needs to get connected shall be responsible for
submitting an application for grant of approval for adjustments and supplements to the planning
according to the regulation on contents and procedures for formulation, assessment, approval and
adjustment of electricity development planning issued by the Ministry of Industry and Trade before
taking next steps.
4. The transmission network operator and customer that request connection must execute a
connection agreement according to the form prescribed herein including following information:
a) Position of connection point;
b) Technical information related to connection point;
c) Progress of connection;


d) Responsibility for investment and operation management;
dd) Terms and conditions of the connection agreement.
5. The transmission network operator is entitled to reject proposals for connection in following cases:
a) Customer’s electrical equipment, grids fail to meet operational and technical requirements
prescribed herein and other relevant technical regulations;
b) Proposals for connection are inconsistent with the approved electricity development planning.
6. The transmission network operator is entitled to disconnect the customer from its transmission grid
if such customer violates technical and operational requirements as prescribed herein or violates the
regulation on safety and operation of its assets. The procedures for settlement of dispute prescribed in
Chapter IX herein shall apply if the two parties fail to reach an agreement on the disconnection.
7. If any change or upgrading of equipment or change of connection diagram by the customer using
transmission grid within its scope of management affects safe operation of the electricity transmission
system or electrical equipment belonging to the transmission network operator at connection point,
such customer must make a written notification to the transmission network operator and the dispatch
level before implementation.
8. Any change related to connection point during the investment and operation must be updated in the
dossier of connection point and signed connection agreement.

9. The customer using transmission grid shall be responsible for storing figures concerning working
modes, operation and maintenance and incidents on the components within its management for a
period of five years. As requested by the transmission network operator, the customer shall provide
adequate information related to the incident on the components within its management. For any
connection serving purchase and sale of electricity between power plants overseas or outside the
territory of Vietnam and the national electricity system, the technical and operational requirements of
the equipment connecting to the transmission grid shall be in order of priority as follows:
a) Be conformable with regulations, international agreements and commitments of which Vietnam is a
signatory;
b) An agreement between relevant parties must be reached to meet all the technical requirements and
technical regulations on each country’s electricity system and ensure that the operation of the
electrical grids is safe, reliable and stable.
Section 2. GENERAL TECHNICAL REQUIREMENTS FOR EQUIPMENT CONNECTING TO
TRANSMISSION GRID
Article 29. Requirements for connecting equipment
1. The diagram of main connection point shall represent all the electrical equipment from middlevoltage to super high-voltage levels and connectivity between the electrical grid of the customer using
transmission grid and the transmission grid. The electrical equipment must be described in symbols,
standard signs and numbered by the dispatch level according to the operating procedure of the
national electricity system issued by the Ministry of Industry and Trade.
2. Circuit breakers directly related to connection points accompanied by protection, measurement and
control systems must be capable of de-energizing maximum short-circuit current at connection point,
meeting the electrical grid and power generation development diagram under the approved electricity
development planning at least for the next 10 years.
3. Equipment connecting directly to the transmission grid shall be fully capable of withstanding
possible maximum short-circuit current at connection points according to the calculations by the
transmission network operator, meeting the electrical grid and power generation development diagram
under the approved electricity development planning at least for the next 10 years.
Article 30. Requirements for protective relay system
1. The transmission network operator and the customer using transmission grid shall be responsible
for designing, installing, setting and testing the protective relay system within their own management

to meet requirements for quickness, sensitivity, selectivity and reliability in case of fault clearance to
ensure safe and reliable operation of the electricity system.
2. Coordination in installing protective relay equipment at connection points must be agreed between
the dispatch level, the transmission network operator and the customer using transmission grid. The
transmission network operator or the customer using transmission grid shall not be allowed to change
its own protective relay equipment and installation parameters without consent of the dispatch level.
3. The dispatch level shall be responsible for issuing relay setting notes within scope of transmission
grid belonging to the transmission network operator and granting approval for the relay settings of the
protective relay equipment belonging to the customer using transmission grid.


4. Maximum time limit for fault clearance through main protection on the components of the electricity
system belonging to the customer using transmission grid is not allowed to exceed the values
prescribed in Article 12 herein.
5. If the protection equipment belonging to the customer is required to connect to the transmission
network operator’s protection equipment, such equipment must meet requirements of the transmission
network operator for connection and be approved by the dispatch level.
6. If the electrical grid belonging to the customer using transmission grid has a problem, the protective
relay equipment in the electrical grid may send commands to disconnect circuit breakers on the
transmission grid with consent of the transmission network operator and the dispatch level with regard
to these circuit breakers.
7. Reliability of impacts of the protective relay system shall not be less than 99%.
8. In addition to requirements prescribed from Clause 1 to Clause 7, this Article, the protective relay
system belonging to the customer using transmission grid and the transmission network operator must
meet following requirements:
a) Power plants must be equipped with synchronization system;
b) Power plants must be equipped with a GPS.
c) Power plants with total installed capacity from 300 MW and on must be equipped with a phasor
measurement unit (PMU) and a GPS. Power plants with total installed capacity less than 300 MW,
equipment of PMU must follow calculations and requirements of the electricity system and market

operator;
d) The transmission network operator and customer using transmission grid other than generating
units shall be responsible for installing a GPS, PMU according to requirements of the dispatch level,
ensuring compatible, reliable and stable connection to the GPS and PMU located at the electricity
system and market operator. The dispatch level shall be responsible for integrating the GPS and PMU
of the transmission network operator and customer using transmission grid to the system located at
the dispatch level;
dd) During operation, in case of upgrading or changing the GPS and PMU, the transmission network
operator and customer using transmission grid shall be responsible for making notifications and
entering negotiations with the dispatch level before implementation;
e) The transmission lines from 220 kV and over connecting to generating sets or distribution area of
the power plant must be equipped with two independent communication channels serving
transmission of signals of protective relay between two ends of lines (transmission time no more than
20 ms);
g) Electricity customers shall be responsible for investing and installing low-frequency relays within
scope of automatic load shedding management according to calculations and requirements of the
dispatch level.
9. Scope, positioning and technical requirements of protective relay equipment for generating sets,
transformers, busbars and lines connecting to the transmission grid shall be conformable with the
regulation on technical requirements of protective relay and automation system in the power plant and
transformer issued by Electricity Regulatory Authority.
Article 31. Requirements for information system
1. The customer using transmission grid shall be responsible for investing, installing and managing the
information system and ensuring it is connected to the information system belonging to the
transmission network operator and the dispatch level. Means of communications serving dispatching
and operation include direct communication channel, telephone and facsimile.
2. The information system belonging to the customer using electrical grid must be compatible with that
of the transmission network operator and the dispatch level.
The customer may negotiate an agreement for use of information system of the transmission network
operator or other suppliers to connect to the information system of the dispatch level to ensure

continuous and reliable communication serving electricity system and market operation.
3. The transmission network operator shall be responsible for investing and managing the information
system of its own to serve electricity system and market operation; cooperating with the dispatch level
in establishing a information transmission line to the dispatch level.
4. The dispatch level shall be responsible for providing requirements for information data, data
transmission and necessary information interface serving electricity system and market operation to
the transmission network operator and customer using transmission grid.


5. The dispatch level and the transmission network operator shall be responsible for cooperating with
the customer using transmission grid in testing, inspecting and connecting the customer’s information
system to the existing information system managed by the units.
Article 32. Requirements for connection of SCADA system
1. Transformers from 220 kV and on, power plants with installed capacity greater than 30 MW and
power plants connected to the transmission grid which is not yet connected to the Control Center must
be equipped with a Gateway or RTU with two ports connecting directly, simultaneously and
independently to the SCADA system of the dispatch level.
2. Power plants with installed capacity greater than 30 MW and power plants connecting to the
transmission grid which is connected to the Control Center must be equipped with a Gateway or RTU
with one port connecting directly to the SCADA system of the dispatch level and two ports connecting
directly to the Control Center. Transformers from 220 kV and on which is connected to the Control
Center must be equipped with a Gateway or RTU with two ports connecting directly to the Control
Center.
3. If a power plant, transformer has multiple dispatching levels with control authority, such dispatching
levels shall be responsible for sharing information to serve electricity system operation coordination.
4. The transmission network operator and customer using transmission grid shall be responsible for
investing, installing and operating the RTU/Gateway within management or hiring the data
transmission lines from service providers to ensure continuous and reliable connection to the SCADA
system of the dispatch level and the Control Center.
5. Technical characteristics of RTU/Gateway belonging to the transmission network operator and

customer using transmission grid must be compatible with the SCADA system of the dispatch level
and the Control Center (if any).
6. The dispatch level shall be responsible for integrating data according to the list of data agreed with
the transmission network operator and customer using transmission grid to its SCADA system. The
transmission network operator and customer using transmission grid shall be responsible for
cooperating with the dispatch level in configuring and setting database on its system to ensure
compatibility with the SCADA system of the dispatch level and control system of the Control Center (if
any).
7. If the SCADA system of the dispatch level has had some technological changes approved by
competent agencies after the connection agreement is signed resulting in changes or upgrading of the
control system, RTU/Gateway of the transmission network operator and customer using transmission
grid, the dispatch level, the transmission network operator and customer shall be responsible for
making necessary adjustments to ensure that the equipment belonging to the transmission network
operator and customer using transmission grid is compatible with changes of the SCADA system. The
transmission network operator and customer using transmission grid shall be responsible for investing
and upgrading the control system and RTU/Gateway to ensure compatibility with the SCADA system
of the dispatch level.
8. During operation, in case of upgrading or expansion of the control system, RTU/Gateway, the
transmission network operator and customer using transmission grid shall be responsible for entering
negotiations with the dispatch level before the upgrading or expansion is carried out.
9. Requirements on lists of data, technical requirements of RTU/Gateway are detailed in the regulation
on technical requirements and SCADA system operation management issued by the Electricity
Regulatory Authority.
Article 33. Neutral grounding in transformers
Neutral grounding in transformers must ensure value of earth fault factor does not exceed the value
prescribed in Article 13 herein.
Article 34. Power factor
1. In normal operation mode, electricity distribution units and electricity customers must maintain a
power factor (cosφ) at key measuring positions from 0.9 and over in case of receiving reactive power
and from 0.98 and on in case of transmitting reactive power.

2. The customer using transmission grid must provide parameters of reactive power compensation
equipment in its electrical grid (if any) to the transmission network operator and the dispatch level,
including:
a) Rated reactive power and adjustment range;
b) Principle of reactive power adjustment.
Article 35. Load fluctuation


The speed of changing power consumption by electricity customers in a minute is not allowed to
exceed 10% of power consumption in normal operation mode unless the electricity customer adjusts
demand as requested or under an agreement with the electricity system and market operator.
Article 36. Automatic frequency load shedding system
1. The customer using transmission grid shall be responsible for cooperating with relevant units in
unifying the installation of the automatic frequency load shedding system and ensuring that it operates
in accordance with calculations and requirements of the dispatch level.
2. The system must be designed to meet following requirements:
a) Reliability not less than 99%;
b) Any unsuccessful load shedding must not affect operation of the entire electricity system.
c) Load shedding procedures and amount of shed power must be in compliance with level of
distribution by the dispatch level and must not be changed in any case without consent of the dispatch
level.
3. Low-frequency relays must be installed and put into operation at the request of the dispatch level.
4. Load recovery procedures after frequency is restored to normal operation mode must be in
compliance with dispatch instruction of the dispatch level.
Article 37. Requirements of Control Center
1. General technical requirements
a) Monitoring, control and information systems installed in the Control Center must be equipped to
ensure safe and reliable operation of power plants, substations;
b) The Control Center’s monitoring and control systems must be technically compatible and ensure
stable, reliable and continuous connection of power plants, substations and switchgears to SCADA

system of the dispatch level;
c) The Control Center must have a backup power supply to ensure normal operation in case of loss of
power from the national electricity system.
2. Requests for connection from Control Center
- There are two independent data transmission lines to be connected to the information system of the
dispatch level. If multiple dispatching levels with control authority exist, an information sharing method
must be agreed by all the dispatching levels;
- There are two data transmission lines to be connected to the control and information system of
power plants, substations remotely controlled by the Control Center;
- Means of communications serving dispatching and operation include direct communication channel,
telephone, facsimile and computer network.
b) Requirements for connection to SCADA system
- There are two ports connecting directly, simultaneously and independently to SCADA system of the
dispatch level. If multiple dispatching levels with control authority exist, a common information sharing
method must be agreed by all the dispatching levels;
- There are ports connecting to RTU/Gateway, control system of power plants, substations and
switchgears on the electrical grid remotely controlled by the Control Center.
c) The Control Center must install a monitoring screen connected to the surveillance camera at power
plants, substations and switchgears on the electrical grid.
3. Power plants, substations or switchgears on the electrical grid remotely controlled by the Control
Center must be equipped with a control and surveillance camera system to establish stable, reliable
and continuous connection to the Control Center meeting requirements prescribed in Clause 1 and
Clause 2, this Article.
Section 3. TECHNICAL REQUIREMENTS FOR CONNECTION TO HYDRO POWER PLANTS AND
THERMO POWER PLANTS
Article 38. Requirements for generating sets’ power control
1. Power plants with installed capacity over 30 MW must be equipped with facilities, control systems ,
AGC system to ensure stable and reliable connection to a generating set’s power control system of the
electricity system and market operator serving remote control of the generating set’s power according
to dispatch instruction of the electricity system and market operator. Particular technical requirements

for connection of the generating set's AGC system to SCADA/EMS of the electricity system and
market operator are prescribed in the regulation on technical and operation requirements of SCADA
system issued by the Electricity Regulatory Authority.


2. The generating set of a power plant must be capable of generating rated active power in a power
factor from 0.85 (corresponding to reactive power generation mode) to 0.9 (corresponding to reactive
power receiving mode) in accordance with characteristics of the generating set’s reactive power.
3. The generating set must be capable of adjusting primary and secondary frequency as prescribed in
the national load dispatch process issued by the Ministry of Industry and Trade and controlling voltage
in the electricity system through continuous adjustment of active power and reactive power of the
generating set.
4. In normal operation mode, voltage changes at connection point to transmission grid within
permissible scope prescribed in Article 6 herein must not affect amount of active power generated and
reactive power generation capability of the generating set.
5. The generating set of a power plant must be capable of generating rated active power continuously
within frequency band 49 Hz – 51 Hz. In a frequency band from 46 Hz to under 49 Hz and over 51 Hz,
level of power reduction must not exceed value according to frequency reduction ratio of the electricity
system. Minimum time to maintain operation of power plants with installed capacity over 30 MW or
power plants connected to the transmission grid in proportion to frequency bands of the electricity
system is specified in Table 7 below:
Table 7
Minimum time to maintain power generation in proportion to frequency band of the electricity system
Minimum time

Frequency band

Hydro power plants

Thermo power plants

From 46 Hz to 47.5 Hz

20 seconds

Not required

From 47.5 Hz to 48.0 Hz

10 minutes

10 minutes

From 48 Hz to under 49 Hz

30 minutes

30 minutes

Continuous generation

Continuous generation

From 51 Hz to 51.5 Hz

30 minutes

30 minutes

From 51.5 Hz to 52 Hz

03 minutes

01 minute

From 49 Hz to 51 Hz

6. Generating sets of a power plant must be capable of withstanding level of voltage symmetry loss in
the electricity system as prescribed in Article7 herein.
7. Generating sets of a power plant must be capable of working continuously in following modes:
a) Unbalanced three-phase loads from 10% and under;
b) Indicator of response of the exciter in a synchronous generating set greater than 0.5%;
c) Negative sequence current is 5% less than rated current.
Article 39. Excitation system of a generating set
1. The excitation system of a generating must ensure that the generating set can operate in a power
factor range prescribed in Clause 2, Article 38 herein. The excitation system must ensure the
generating set operates at a rated apparent power (MVA) within the range ± 5 % of rated voltage at
the generating set’s terminal posts.
2. The generating set must be equipped with AVR which operates continuously and is capable of
maintaining deviation of terminal voltage within ± 0,5 % of rated voltage in the entire permissible
working band of the generating set.
3. AVR must be capable of making up for voltage drop on terminal transformers and ensure stable
distribution of reactive power among generating sets connected to a common busbar.
4. AVR must be installed with following limits:
a) Minimum excitation current;
b) Maximum excitation current.
5. When terminal voltage of a generating set is in a range from 80 to 120% of rated voltage and the
system frequency is in a range from 47.5 to 52Hz in a maximum of 0.1 second, the excitation system
of the generating set must be capable of increasing the current and excitation voltage to following
values:

a) For a generating set of a hydro power plant: 1.8 rated value;
a) For a generating set of a thermo power plant: 2.0 rated value;


6. Change of excitation voltage is not allowed to be less than 2.0 rated excitation voltage/second when
a generating set carries the rated load.
7. A generating set with a capacity over 30 MW must be equipped with a PSS capable of dampening
0.1 Hz – 5 Hz frequency fluctuation contributing to improvement of the electrical system. Generating
units must install and set parameters of the PSS according to calculations by the electricity system
and market operator to ensure dampening ratio of the PSS is not smaller than 5%. For generating sets
equipped with PSS, the generating units shall be responsible for putting the PSS into operation at the
request of the dispatch level.
Article 40. Governor
1. Generating sets of a power plant in operation must engage in adjusting primary frequency in the
national electricity system.
2. Generating sets of a power plant must be equipped with a governor capable of responding to
changes of system frequency in normal operation conditions. The governor must be capable of
performing commands from SCADA/EMS system of the electricity system and market operator unless
it is not required.
3. The governor must be capable of setting value of static coefficient less than or equal to 5%. Set
value of static coefficient shall be determined by the electricity system and market operator.
4. Apart from add-on generating sets of combined cycle power plants, minimum value of a dead-band
in the governor must range within ± 0,05 Hz. Value of dead-band of the governor of each generating
set shall be calculated and determined by the electricity system and market operator during
connection and operation.
5. The governor control system must be installed with following limits and anti-over speed control as
follows:
a) For steam turbines: From 104% to 112% of rated speed;
b) For gas and thermo power turbines: From 104% to 130% of rated speed;
c) If the generating set in the grid area is temporarily disconnected from the national electricity

transmission system but keeps supplying power to customers, the governor system of the generating
set must maintain frequency stability for such grid area.
Article 41. Black start
1. In some important positions in electricity transmission system, some power plants must be capable
of black starting. Requirements for installation of black start capability must be stated in the connection
agreement.
2. The electricity system and market operator shall be responsible for determining important positions
in the national electricity system for the construction of power plants capable of black start and
cooperate with the transmission network operator, generating units in determining specific
requirements for black start of individual power plants.
Section 4. TECHNICAL REQUIREMENTS OF WIND AND SOLAR POWER PLANTS
Article 42. Technical requirements of wind and solar power plants
1. Wind and solar power plants must be capable of maintaining generation of active power within
frequency band from 49 to 51 Hz in following modes:
a) Free generation mode
b) Generating capacity control mode
Wind and solar power plants must be capable of adjusting generation of active power as commanded
by the dispatch level in accordance with change of primary sources no more than 30 seconds with
tolerance within ± 01 % of rated power, specifically as follows:
- Generation of power in accordance with dispatch instruction in case primary sources are equal or
greater than forecast value;
- Generation of possible maximum power in case primary sources are lower than forecast value.
2. In normal operation mode, wind and solar power plants must be capable of generating active power
and ensure no negative effect is caused by change of voltage at connection point within permissible
band prescribed in Article 6 herein.
3. Wind and solar power plants must be capable of maintaining generation of power for a minimum
period of time in proportion to frequency band prescribed in Table 8 below:
Table 8
Minimum time to maintain power generation in proportion to frequency band of electricity system

Frequency band

Minimum time

From 47.5 Hz to 48.0 Hz

10 minutes

Over 48 Hz to under 49 Hz

30 minutes

From 49 Hz to 51 Hz

Continuous generation

From 51 Hz to 51.5 Hz

30 minutes

Over 51.5 Hz to 52 Hz

01 minute

4. When the electricity system’s frequency is greater than 51 Hz, wind and solar power plants must
reduce active power at a speed no less than 01% of rated power. Level of power reduction in
proportion to frequency is determined as follows:
 51.0 − fn 
∆P = 20 × Pm x 


 50 
Where:
- ΔP: Level of active power reduction (MW);
- Pm: Active power in proportion to the point of time prior to power reduction (MW);
- fn: Electricity system frequency prior to power reduction (Hz).
5. Wind and solar power plants must be capable of adjusting reactive power and voltage as follows:
a) If a power plant generates an active power greater or equal to 20% of rated active power and
voltage in normal operation band, such power plant must be capable of adjusting reactive power
continuously in a power factor from 0.85 (corresponding to reactive power generation mode) to 0.95
(corresponding to reactive power receiving mode) at connection point in proportion to rate power;
b) If a power plant generates an active power less than 20% of rated power, such power plant may
reduce ability to receive or generate reactive power in accordance with characteristics of the
generating set;
c) If voltage at connection point is within ± 10 % of rated voltage, the power plant must be capable of
adjusting voltage at connection point with deviation no more than ± 0,5 % of rated voltage in
permissible working band of the generating set;
d) If voltage at connection point varies beyond ± 10 % of rated voltage, the power plant must be
capable of adjusting reactive power to the minimum of 2% compared with rated reactive power in
proportion to each per cent of voltage varying at connection point.
6. Wind and solar power plants at every time of connection to the grid must be capable of maintaining
generation of power in proportion to voltage range as follows:
a) Voltage less than 0.3 pu, minimum time is 0.15 seconds;
b) Voltage from 0.3 pu to under 0.9 pu, minimum time is calculated in following formula:
Tmin = 4 x U – 0.6
Where:
- Tmin (second): Minimum time to maintain power generation:
- U (pu): Actual voltage at connection point (pu).
c) Voltage from 0.9 pu to under 1.1 pu, wind and solar power plants must maintain continuous
generation;

d) Voltage from 1.1 pu to under 1.15 pu, wind and solar power plants must maintain generation for
three seconds;
dd) Voltage from 1.15 pu to under 1.15 pu, wind and solar power plants must maintain generation for
0.5 seconds;
7. Wind and solar power plants must ensure not to cause negative phase sequence component in
excess of 01% of rated voltage. Wind and solar power plants must be capable of withstanding
negative phase sequence components up to 03% of rated voltage for voltage from 220 kV and on.
8. Total harmonic distortion caused by wind, solar power plants at connection point is not allowed to
exceed 03%.
9. Flicker perceptibility caused by wind and solar power plants at connection point is not allowed to
exceed the value prescribed in Article 9 herein.


Section 5. PROCEDURES FOR CONNECTION AGREEMENT
Article 43. Procedures
1. When establishing or changing connection, customers must submit an application for connection to
the transmission network operator.
2. Application includes:
a) A written request for connection accompanied by information according to the form in Annexes 1A,
1A 1B, 1C enclosed herewith;
b) Technical documents concerning equipment expected for connection or possible changes at
existing connection points;
c) Expected time for project completion, economic – technical figures of new connection or connection
change projects.
3. After receiving the application, the transmission network operator shall:
a) Review requirements concerning the equipment expected for connection;
b) Preside over assessment of effects of connection of equipment, electrical grid, power plants of
customers on transmission grid including following subject matters:
- Calculate reset modes of regional electrical grids under requests for connection in the next 10 years
including calculation of all alternatives and assess ability of regional transmission grid to meet N-1

criterion;
- Calculate and assess short-circuit current at connection points to the transmission grid;
- Determine obligations and constraints from new connections that may have effects on safe and
stable operation of electricity transmission system;
- Assess ability to meet requirements for operation of the electricity system prescribed in Chapter II
herein and technical requirements of connection points prescribed in this Chapter;
c) Prepare a draft connection agreement according to the form in Annex 2 enclosed herewith and
submit it to customers who need to get connected and the dispatch level;
d) After 15 working days at the latest since receipt of the application for connection from customers,
the transmission network operator shall submit a written request to the dispatching with control
authority and relevant units for official suggestions as follows:
- Assessment of impacts of connection on the electricity transmission system;
- Technical requirements of equipment at connection points, requirements of operation and
dispatching of generating sets, requirements of frequency load shedding system of electricity
customers to ensure compliance with technical and operation requirements prescribed in Chapter II
and Chapter V herein;
- Draft connection agreement in accordance with provisions prescribed in annexes enclosed herewith.
4. The dispatch level shall be responsible for cooperating with the transmission network operator in
assessing effects of connection on the electricity transmission system as prescribed in Point b, Clause
3, this Article.
5. Customers who need to get connected shall be responsible for providing other necessary
information to the transmission network operator and the dispatch level for determination of technical
characteristics and other technical requirements to ensure safe, reliable and stable operation of the
electricity transmission system.
6. Within 20 working days since receipt of request from the transmission network operator, the
dispatch level and relevant units shall be responsible for delivering suggestions in writing on issues
prescribed in Point d, Clause 3 and Clause 4, this Article to the transmission network operator.
7. Upon receipt of suggestions from the dispatch level and other relevant units, the transmission
network operator shall be responsible for completing the draft connection agreement.
8. The connection agreement shall be made into four copies. Each party keeps two copies. The

transmission network operator shall submit a copy to the dispatch level, relevant units for cooperation
during construction, energizing and official operation.
9. Time for review of the application, negotiation on relevant issues and execution of the connection
agreement is prescribed in Article 44 herein.
10. A customer who needs to get connected to the electrical grid or equipment of the customer using
transmission grid shall be responsible for making direct negotiation with this customer. Before
reaching an agreement for connection plan with the customer who needs to get connected, the
customer using transmission grid shall be responsible for cooperating with the transmission network


operator and the dispatch level in ensuring that the equipment of the customer meets technical
requirements of the equipment at connection points prescribed herein. The customer using
transmission grid shall be responsible for updating connection-related issues to the connection
agreement signed with the transmission network operator.
11. In case of connection to 110 kV or medium-voltage busbars belonging to transformers 500 kV or
220 kV within management by the transmission network operator, the procedures for execution of the
connection agreement are prescribed in Clauses 1 to 9, this Article.
Article 44. Time limit for execution of connection agreement
Time limit for negotiation and signing of the connection agreement is prescribed in Table 9 below:
Table 9
Time limit for review and signing of connection agreement
Implementation steps

Implementation time

Responsibility

Submit an application for
connection

Customers who need to get connected

Examine the application, prepare No more than 35 working
a draft connection agreement and days since receipt of the
deliver it to other units for
application
collection of suggestions.

The transmission network operator shall
preside over and cooperate with the
dispatch level and relevant units.

Complete the draft connection
agreement, negotiate and sign
the connection agreement

The transmission network operator and
customers who need to get connected

No more than 20 working
days since receipt of
suggestions from relevant
units

Section 6. IMPLEMENTATION OF CONNECTION AGREEMENT
Article 45. Rights to get access to equipment at connection points
The transmission network operator and customers who need to get connected shall have the rights to
get access to the equipment at connection points during survey process to make plans for connection,
construction, installation, testing, replacement, removal, operation and maintenance of connection
equipment.

Article 46. Dossier for inspection of energizing conditions
1. Dossier serving general inspection of energizing conditions (technical documents confirmed by
customers who need to get connected and certified copy of legal documents) includes:
a) Written records of inspection of individual parts and whole of connection equipment, transmission
lines and transformers (according to technical standards of Vietnam or international standards
applicable in Vietnam and technical requirements of connection equipment prescribed in this Chapter);
b) Approved technical documents, amendments and supplements (if any) to initial design including
following documents:
- General explanation, electrical equipment layout;
- Schematic diagrams of protective relay, automation and control system that represents circuit
breakers, current transformers, voltage transformers, lightning arrestor, disconnect switches …;
- Secondary diagrams of protective relay, automation and control system;
- Diagrams detailing connection to the transmission grid and parameters of transmission lines;
- Other relevant diagrams (if any).
c) Documents concerning technical parameters and operation management including:
- Technical parameters of equipment including parameters of transmission lines;
- Documents concerning primary energy system, excitation systems, governors, simulation modeling,
PSS, Laplace transform diagram together with other installation values (for construction of new power
plants);
- Instruction manuals for setting of protective relays, automation, specialized software;
- Instruction manuals for equipment operation and other technical documents.
d) Calculations and proposals for trial operation, energizing and putting the plant into operation.
2. Unless otherwise as agreed, customers who need to get connected shall be responsible for
providing all the documents prescribed in Clause 1, this Article to the dispatch level and the
transmission network operator serving energizing as follows:


a) At least three months prior to date of initial trial operation of the power plant;
a) At least three months prior to the date of initial trial operation of the power plant;
3. The dispatch level shall be responsible for making plans for energizing and putting the power plant

into operation, ensuring safety and reliability of the equipment of the national electricity system.
Customers who need to get connected shall be responsible for cooperating with the dispatch level in
formulating methods of energizing the power plant.
4. Within 20 working days since receipt of the documents, the dispatch level shall be responsible for
delivering following documents to the customer:
a) Equipment numbering diagram;
b) Requirements for methods of receiving dispatch instruction;
c) Settings of protective relays of the customer from connection points; protective relay settings note
within transmission grid and other settings related to protective relays of the customer;
d) Agreed energizing method;
dd) Requirements for testing and calibration of equipment;
e) Requirements for establishment of communication system serving dispatching;
g) Requirements for connection and operation of SCADA, monitoring equipment, PMU and PSS;
h) Requirements for installation of information technology system and other necessary infrastructure
serving electricity market operation;
i) Procedures related to electricity system and market operation;
k) Lists of relevant officials and dispatchers accompanied by phone and facsimile numbers.
5. Within 20 working days prior to the date connection points are energized, customers who need to
get connected must reach an agreement with the dispatch level for trial operation schedules, methods
of energizing and putting electrical equipment into operation.
6. Within 15 working days prior to the energizing day, customers who need to get connected must
provide followings to the transmission network operator:
a) Trial operation schedules, methods of energizing and putting the electrical equipment into operation
agreed with the dispatch level;
b) Agreement for assignment of responsibility of relevant parties for management and operation of
connection equipment;
c) Internal regulation on safe operation of connection equipment;
d) Lists of qualified operators as prescribed in the national electricity system dispatch procedure
issued by the Ministry of Industry and Trade including full name, professional title, responsibility,
phone number.

7. Within 15 working days prior to the date connection points are energized, customers who need to
get connected must provide information as prescribed in Points b, c, d, Clause 6, this Article and
information as prescribed in Point a, Clause 6, this Article to the dispatch level and electricity
wholesalers respectively.
Article 47. Inspection of conditions for energizing connection points
1. Within five working days prior to the date connection points are expected to energized, customers
who need to get connected shall be responsible for negotiating with the transmission network operator
on the date for physical inspection of connection points.
2. The transmission network operator shall be responsible for presiding over and cooperating with
relevant units in negotiating with the customer on procedures for inspection of dossier, written record
of inspection and installation of equipment at connection points.
3. If connection points or electrical equipment of the customer fail to meet conditions for energizing as
notified by the transmission network operator, the customer must carry out adjustment, supplement or
replacement as requested and re-negotiate with the transmission network operator on the time for next
inspection.
4. If the dispatch level provides warnings about negative impacts of energizing on safe, reliable and
stable operation of the electricity transmission system or equipment of the customer, the customer
must cooperate with the dispatch level and the transmission network operator in re-inspecting matters
related to the warnings and reaching an agreement for settlement method and re-negotiating with the
transmission network operator on the time for next inspection.


5. If the customer detects possible effects of energizing on safe and reliable operation of its
equipment, the customer shall make proposals to relevant units for handling and re-negotiating with
the transmission network operator on the time for next inspection.
6. The transmission network operator, customers who need to get connected and relevant units shall
be responsible for signing the written record of inspection of conditions for energizing connection
points (hereinafter referred to as “the written record of inspection”).
Article 48. Energizing connection points
1. After the written record of inspection is signed, customers who need to get connected shall be

responsible for delivering an application for energizing accompanied by following documents to the
dispatch level:
a) Written confirmations of fulfillment of legal and technical procedures:
- Equipment within the scope of energizing that meet operational and technical requirements at
connection points;
- Copy of the written record of inspection;
- Measurement system completed as prescribed, electrical meter indicators finalized;
- Signed power purchase agreement (PPA) or any agreement for power purchase;
- Dossier of work acceptance according to the law on construction:
- Primary equipment numbered according to the primary diagram issued by the dispatch level;
- Protective relay, automation, control, excitation and governor systems that have been installed and
set in accordance with requirements prescribed herein and by the dispatch level;
- Lists of qualified operators as prescribed in the national electricity system dispatch procedure issued
by the Ministry of Industry and Trade including full name, professional title, responsibility, phone
number.
- Means of communications serving dispatching as prescribed in the national electricity system
dispatch procedure issued by the Ministry of Industry and Trade;
- Connection to SCADA, monitoring system, PMU and communication system of the dispatch level
fully completed;
- Operation coordination procedure agreed between the generating unit and the dispatch level.
2. If the energizing of connection points of customers has impacts on operation mode or in case of
separation of equipment on the transmission grid from operation, the transmission network operator
shall be responsible for delivering an application for separation of equipment within management to
the dispatch level.
3. Within five working days since receipt of the application, the dispatch level shall be responsible for
making notification to the transmission network operator and customers who need to get connected of
the time and method of energizing connection points.
4. The transmission network operator and customers shall be responsible for coordinating energizing
connection points according to the method notified by the dispatch level.
Article 49. Trial operation, acceptance and official operation of equipment behind connection

points
1. During trial operation, acceptance and official operation of the equipment behind connection points,
customers who need to get connected must appoint dispatchers and competent officials for keeping
watch round the clock and send the list of officials with phone numbers to the transmission network
operator and the dispatch level if need be.
2. Procedures for trial operation and acceptance shall be conformable with the manufacturer’s
instructions and applicable regulations (if any).
3. During trial operation and acceptance, customers who need to get connected shall be responsible
for cooperating with the transmission network operator, the dispatch level and relevant units in
minimizing effects of new equipment in trial operation on safe and reliable operation of the national
electricity transmission system.
4. After the process of trial operation and acceptance is completed, customers who need to get
connected must provide confirmations and following information to the dispatch level and the
transmission network operator:
a) Technical specs of electrical equipment, transmission lines, transformers and generating sets;
b) Test results and installation parameters of excitation and governor systems;


c) Other technical requirements as agreed in the connection agreement.
If equipment of customers who need to get connected fails to meet requirements prescribed herein
and signed connection agreement, the transmission network operator or the dispatch level has the
right not to connect the power plant or electrical grid of the customer to the transmission grid and
request the customer to take remedial measures.
5. Electrical grid, power plant and electrical equipment of the customer shall be put into official
operation after the process of trial operation and acceptance is completed and requirements
prescribed herein and the signed connection agreement are met.
Article 50. Inspection and monitoring of equipment after put into official operation
1. During operation, the transmission network operator or the dispatch level (hereinafter referred to as
"the requester") has the right to request the customer using transmission grid to carry out inspection,
trial operation and supplementing the equipment within its management for following purposes:

a) Inspect the ability of the equipment to meet provisions prescribed herein, technical regulations
applicable in Vietnam and particular requirements of the signed connection agreement;
b) Inspect the compliance of the equipment with terms and conditions under the PPA and the signed
connection agreement;
c) Assess impacts of electrical grid, power plants of the customer using transmission grid on safe and
reliable operation of the national electricity system;
d) Reset technical parameters of generating sets and electrical grids of the customer using
transmission grid to serve safe, stable and reliable operation of the national electricity system.
2. Expenses for inspection, trial operation and additional tests shall be agreed by two parties and
stated in the connection agreement or the PPA. Or shall be stipulated as follows:
a) If inspection result shows that the equipment fails to meet provisions prescribed herein and
applicable technical regulations, the customer using transmission grid shall incur all the expenses for
inspection and additional tests;
b) If inspection result shows no violation, the requester shall incur all the expenses for inspection and
additional tests. For requirements for inspection as prescribed in Point c and Point d, Clause 1, this
Article, the dispatch level must report to the Electricity Regulatory Authority before carrying out
inspection.
3. The requester must make notification of subject matters, time and list of officials involved to the
customer using transmission grid at least 15 days prior to the inspection and additional testing of the
electrical grid and electrical equipment. The customer using transmission grid shall create favorable
conditions for the requester to perform the inspection.
4. During the inspection, the requester is allowed to install monitoring equipment to the electrical
equipment and electrical grid of the customer using transmission grid without having any negative
effect on safe and reliable operation of such equipment.
5. During operation, if equipment of the customer using transmission grid at connection points has
technical problems which may lead to loss of safety and reliability for the operation of the electricity
transmission system, the dispatch level must make notification of such problems and requests for the
remedy of the problems to the customer and the transmission network operator. The customer using
transmission grid must take remedial measures and carry out trial operation to put the equipment
behind connection points into operation again as prescribed in Article 49 herein. If such technical

problems remain un-remedied, the dispatch level or the transmission network operator has the right to
separate the equipment from the connection point and make notification to the customer.
6. For a generating set, the dispatch level has the right to request the generating unit to carry out
testing one or several operational characteristics (it registered) at any time but no more than three
times a year except for following cases:
a) Test result shows that one or several operational characteristics are inconsistent with parameters
published by the generating unit;
b) When the dispatch level and the generating unit do not reach a common agreement on operational
characteristics of the generating set;
c) Trial operation or inspection at the request of the generating unit;
d) Tests of fuel change.
7. The generating unit has the right to inspect and test its generating sets to re-determine operational
characteristics of each generating set after the repair, replacement, improvement or re-assembly is
completed. The time for trial operation must be agreed by the dispatch level.
Article 51. Replacement of equipment at connection points