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MINISTRY OF INDUSTRY AND TRADE OF VIETNAM
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SOCIALIST REPUBLIC OF VIETNAM
Independence - Freedom - Happiness
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No. 29/2026/TT-BCT
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Hanoi, June 2, 2026
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CIRCULAR
OPERATION OF COMPETITIVE WHOLESALE ELECTRICITY MARKET
Pursuant
to the Law on Electricity No. 61/2024/QH15, amended by the Law on Atomic Energy
No. 94/2025/QH15;
Pursuant
to Decree No. 40/2025/ND-CP dated February 26, 2025 of the Government of
Vietnam on functions, tasks, entitlements, and organizational structure of the
Ministry of Industry and Trade of Vietnam;
At the
request of the Director of the Electricity Authority of Vietnam;
The
Minister of Industry and Trade of Vietnam hereby promulgates the Circular on
the operation of the competitive wholesale electricity market.
Chapter
I
GENERAL PROVISIONS
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This
Circular provides for:
1. The
operation of the competitive wholesale electricity market (hereinafter referred
to as the “electricity market”), including the following principal contents:
registration for participation in the electricity market; preparation of electricity
market operation plans; the offer mechanism; the dispatch scheduling mechanism;
electricity metering in the electricity market; determination of the market
price and settlement calculation; information announcement; supervision of electricity
market operation; and responsibilities of units participating in the electricity
market.
2. The
threshold for large electricity consumers participating in cases of direct
power trading.
Article
2. Regulated entities
This
Circular applies to the following entities:
1. Electricity
wholesale units.
2. Generation
units.
3. Power
system and electricity market operation units.
4. Electricity
transmission units.
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6. Large
electricity consumers participating in the direct power trading mechanism.
7. Fuel
supply units.
Article
3. Interpretation of terms
For the
purpose of this Circular, the following terms shall be construed as follows:
1. AGC
(Automatic Generation Control) means an automatic control system that
adjusts the active power output of a generating unit, power plant, power plant
cluster, or energy storage battery system to ensure the safe and stable
operation of the power system.
2. Offer
means the offer to sell electricity into the electricity market for each
generating unit, submitted by the offering entity to the power system and
electricity market operation unit using the offer form prescribed in this
Circular.
3. Scheduling
offer means an offer accepted by the power system and electricity market
operation unit for preparing the day-ahead dispatch schedule and the next
trading interval dispatch schedule.
4. Default
offer means the offer used by the power system and electricity market
operation unit for preparing the day-ahead dispatch schedule and the next
trading interval dispatch schedule where no valid offer is received from the generation
unit.
5. Settlement
statement means the statement calculating payments to direct trading
generation units and electricity purchasing units, prepared by the power system
and electricity market operation unit for each trading day and each settlement
period.
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7. Short-term
hydrothermal optimization program means the short-term hydrothermal
optimization software used by the power system and electricity market operation
unit to calculate unit commitment schedules and dispatch schedules for
preparing the electricity market operation plan for the following week and the
day-ahead dispatch schedule of power plants indirectly participating in the
electricity market.
8. Settlement
period means the period for preparing settlement documents and invoices for
transactions in the electricity market, covering a period of 1 month commencing
on the first day of each month.
9. Declared
capacity means the maximum available capacity of a generating unit declared
by the offering entity or a power plant indirectly participating in the
electricity market.
10. Dispatched
capacity means the output capacity of a generating unit actually dispatched
by the power system and electricity market operation unit during a trading
interval.
11. Next
trading interval dispatched capacity means the output capacity of a
generating unit expected to be dispatched during the first trading interval in
the next trading interval dispatch schedule.
12. Day-ahead
dispatched capacity means the output capacity of a generating unit expected
to be dispatched during the trading intervals in the day-ahead dispatch
schedule according to the results of the constrained scheduling.
13. Minimum
stable generation capacity means the minimum generation output (Pmin) of a
generating unit of a power plant, determined as the lower value between the
Pmin agreed upon by the electricity seller and the electricity purchaser in the
power purchase agreement and the actual Pmin of the generating unit.
14. Incremental
generation capacity means the difference between the dispatched capacity
and the capacity scheduled in the market price schedule of a generating unit.
15. Electricity
Market Web Portal means the web portal used for announcing information on
the operation of the power system and the electricity market.
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17. Calculation
cycle during operating day D means a calculation cycle conducted every 8
hours.
18. Auxiliary
services mean secondary frequency control, fast start, operating reserve, voltage
control, and black start services to ensure electricity supply.
19. Incremental
generation output means the electricity generated by a generating unit
corresponding to its incremental generation capacity.
20. Offering
entity means the entity that directly submits an offer in the electricity
market, including a generation unit, power plants registered to submit offers
directly, and the entity representing a cascade hydropower group in submitting
offers.
21. Fuel
supply unit means an entity supplying or trading fuel for electricity
generation, including Vietnam National Coal - Mineral Industries Holding
Corporation Limited (Vinacomin), Dong Bac Corporation, Petrovietnam Gas Joint
Stock Corporation (PV GAS), and other fuel suppliers and traders.
22. Electricity
wholesale unit means an entity that purchases electricity in the spot
electricity market and from EVN for wholesale and retail sale to other
organizations and individuals, currently comprising the 5 Power Corporations
under EVN (Northern Power Corporation, Central Power Corporation, Southern
Power Corporation, Hanoi Power Corporation, and Ho Chi Minh City Power
Corporation).
23. Electricity
purchasing unit means an entity participating in the competitive wholesale
electricity market as an electricity purchaser, including electricity wholesale
units and EVN.
24. Generation
unit means an electricity unit that owns and operates one or more power
plants connected to the national power system.
25. Indirect
trading generation unit means a generation unit that owns and operates a
power plant which does not submit offers directly to the electricity market and
is not subject to the settlement mechanism prescribed in Chapter VIII of this
Circular.
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27. Direct
trading generation unit means a generation unit that owns and operates a
power plant whose dispatch is scheduled based on submitted offers and whose
settlement is calculated in accordance with Chapter VIII of this Circular.
28. Electricity
metering data management unit means an entity responsible for operating the
system for collecting, processing, and storing electricity metering data
serving the electricity market, including the power system and electricity
market operation unit, generation units, electricity transmission units, and electricity
wholesale units, within the scope of each entity's management of electricity
metering data.
29. Electricity
transmission unit means an electricity unit licensed to conduct electricity
activities in the field of electricity transmission and responsible for
managing and operating the national transmission grid.
30. Power
system and electricity market operation unit means the entity performing
the functions of the National Load Dispatch Center and the Electricity Market
Transaction Operator in accordance with the Law on Electricity (currently the National
Power System and Market Operator Company Limited).
31. Electricity
export unit means an electricity unit responsible for concluding and managing
electricity export contracts with electricity export delivery points on the transmission
grid of the national power system in accordance with regulations.
32. FTP
(File Transfer Protocol) means the file transfer protocol and tool used for
transmitting and receiving information and files among units participating in
the electricity market.
33. Market
capacity price means the price determined for each trading interval
and applied for calculating capacity payments to generation units in the electricity
market.
34. Offer
floor price means the lowest price that an offering entity is permitted to
offer for a generating unit in the day-ahead offer.
35. Market
energy price means the price per unit of electrical energy determined for
each trading interval and applied for calculating energy payments in the electricity
market.
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37. Offer
price cap means the highest price that an offering entity is permitted to
offer for a generating unit in the day-ahead offer.
38. Electricity
market price cap means the maximum market energy price, determined
annually.
39. Value
of lost load means the parameter used in the calculation model to represent
the penalty function value when the calculation model produces a result
requiring load shedding due to insufficient generation resources.
40. Water
value means the expected marginal value calculated for the volume of water
stored in hydropower reservoirs when used for electricity generation to
substitute for thermal power generation in the future, converted into a value
per unit of electrical energy.
41. Efficiency
degradation factor means the factor representing the degradation in the
efficiency of a generating unit over its operating period.
42. Annual
average load factor means the ratio of the total annual electricity
generation output to the product of the total installed capacity and the total
number of hours used for calculating the annual load factor.
43. Monthly
average load factor means the ratio of the total monthly electricity
generation output to the product of the total installed capacity and the total
number of hours used for calculating the monthly load factor.
44. Electricity
market information system means the system of equipment and databases
serving the management of and exchange of information for the electricity
market, managed by the power system and electricity market operation unit.
45. Electricity
market information technology system means the system of equipment
comprising the electricity market information system, the SCADA/EMS system, the
electricity metering system, digital signatures meeting the operational
requirements of the electricity market, and other systems prescribed in this
Circular.
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47. Monthly
event confirmation dossier means the dossier prepared in accordance with
Article 6 of Appendix IV enclosed with this Circular regarding the Procedure
for Cooperation in the Reconciliation of Settlement Data among the power system
and electricity market operation unit, generation units, and electricity
purchasing units.
48. Power
purchase agreement means a written agreement between the electricity
purchaser and the electricity seller governing the sale and purchase of electricity.
49. Reservoir
at risk of spillage means a hydropower reservoir falling into one of the
following cases:
a) A
hydropower reservoir having a regulating capacity of less than 2 days;
b) A
hydropower reservoir having a regulating capacity of 2 days or more that has
not yet discharged water but will reach the normal water level or the maximum
permissible water level under the inter-reservoir operation procedures within
the next 2 days if it is not dispatched according to its available capacity;
c) A
hydropower reservoir subject to a written water release notification issued by
a competent state authority;
d) A
hydropower reservoir located in an area directly affected by a typhoon,
tropical depression, or other hazardous weather phenomena according to the official
bulletin issued by the National Center for Hydro-Meteorological Forecasting or
a Regional Hydro-Meteorological Station.
50.
Electricity Market Operations Engineer means the person directly responsible
for operation planning, power source dispatch scheduling, auxiliary services
scheduling, and settlement calculation in the electricity market.
51. Large
electricity consumers participating in the direct power trading mechanism
means large electricity consumers eligible to participate in the direct power
trading mechanism in accordance with Decree No. 57/2025/ND-CP of the Government
of Vietnam, and any amendments, supplements, or replacements thereto, having an
average monthly electricity consumption as follows:
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b) From 200.000
kWh per month or more for the direct power trading mechanism through the
national grid.
52. Daily
operating time blocks comprise the periods from 00:00 to 08:00, 08:00 to 16:00,
and 16:00 to 24:00.
53. Load
block means the parameter used in the water value calculation model,
determined from a pair of values consisting of a time period (hours) and load
(MWh). For water value calculations, the weekly load shall comprise at least 5 load
blocks.
54. Constrained
scheduling means the arrangement of the dispatch order of generating units
using the least-cost electricity procurement method while taking into account
the technical constraints of the power system.
55. Unconstrained
scheduling means the arrangement of the dispatch order of generating units
using the least-cost electricity procurement method without taking into account
the constraints of the power system.
56. Next
trading interval dispatch schedule means the projected dispatch schedule of
generating units for electricity generation and provision of auxiliary services
for the next trading interval and the following 7 trading intervals, as
calculated and announced by the power system and electricity market operation
unit.
57. Day-ahead
dispatch schedule means the projected dispatch schedule of generating units
for electricity generation and provision of auxiliary services for the trading
intervals of the following trading day, prepared by the power system and
electricity market operation unit.
58. Intra-day
dispatch schedule means the projected dispatch schedule of generating units
for electricity generation and provision of auxiliary services for trading
intervals within the daily operating time blocks, as calculated and announced by
the power system and electricity market operation unit.
59. Market
energy price schedule means the schedule prepared by the power system and
electricity market operation unit after the current trading day to determine
the market energy price for each trading interval.
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61. Water
value calculation model means the hydrothermal optimization software system
used by the power system and electricity market operation unit to calculate water
value in preparing annual, monthly, and weekly operation plans.
62. Reservoir
limit water level means the minimum upstream water level of a hydropower
reservoir at the end of each month of the year or at the end of each week of
the month, calculated and announced by the power system and electricity market
operation unit in accordance with the regulations on medium-term and short-term
electricity supply adequacy assessments under the regulations on dispatching,
operation, switching operations, incident handling, black start, and
restoration of the national power system promulgated by the Ministry of
Industry and Trade of Vietnam, while ensuring that the reservoir limit water
level does not exceed the water level prescribed for the flood season under the
reservoir operation procedures and inter-reservoir operation procedures.
63. Optimal
water level means the upstream water level of a hydropower reservoir at the
end of each month or each week, ensuring the most efficient use of water for
electricity generation while satisfying the applicable operational constraints,
as calculated and announced by the power system and electricity market
operation unit.
64. Year
N means the current year of electricity market operation, calculated
according to the calendar year.
65. Day
D means the current trading day.
66. Typical
day means a day selected as having a typical electricity consumption
pattern of the electricity load in accordance with the regulations on
implementation of demand-side management promulgated by the Ministry of
Industry and Trade of Vietnam. Typical days include typical working days,
weekend days (Saturday and Sunday), and holidays (if any) for the year, month,
and week.
67. Trading
day means a day on which electricity market trading activities take place,
from 00:00 to 24:00 every day.
68. BOT
power plant means a power plant invested under the Build - Operate -
Transfer model through a contract between the project owner and a competent
state authority.
69. Best
new entrant means a newly commissioned thermal power plant with the lowest
calculated average generation price for the following year and whose power
purchase agreement price is agreed upon based on the generation service price
prescribed in the regulations on the method for determining generation service
prices; principles for calculating electricity prices for implementation of power
projects; and principal contents of power purchase agreements promulgated by
the Ministry of Industry and Trade of Vietnam, and within the electricity
generation price bracket prescribed in the regulations on dossiers, procedures,
and methods for determining and approving electricity generation price
brackets; and regulations on dossiers and procedures for developing and
approving electricity import price brackets promulgated by the Ministry of
Industry and Trade of Vietnam. The best new entrant shall be selected annually
for use in calculating the market capacity price.
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71. Strategic
multi-purpose hydropower plant means a hydropower plant included in the
list decided by the Prime Minister of Vietnam in accordance with Point b Clause
2 Article 5 of the Law on Electricity.
72. Contract-allocated
power plant means a power plant that has a power purchase agreement with EVN
and is allocated to an electricity wholesale unit in accordance with Clause 2
Article 40 of this Circular.
73. Cascade
hydropower group means a group of hydropower plants where the water discharged
from the reservoir of an upstream cascade hydropower plant accounts for all or
most of the inflow to the reservoir of the downstream cascade hydropower plant,
and there is no regulating reservoir of 2 days or more between these two power
plants.
74. Trading
node means the location used to determine the delivered and received
electricity output for electricity sale and purchase transactions in the spot
electricity market within the electricity market.
75. Dispatch
scheduling software means the software system used by the power system and
electricity market operation unit to prepare day-ahead, intra-day, and next
trading interval dispatch schedules for generating units in the electricity
market.
76. Electricity
load for settlement calculation means the total electricity output of the
entire power system, converted to the terminals of generating units, plus
electricity import output during a trading interval.
77. Contracted
electricity output means the electricity output negotiated and agreed upon
by the parties in a power purchase agreement, or calculated and announced by
the power system and electricity market operation unit in accordance with this
Circular.
78. Take-or-pay
electricity output (hereinafter referred to as “take-or-pay”) includes:
a) The
minimum committed purchase electricity output under power purchase agreements
in the set of contracts for a power plant project invested under the public-private
partnership model applying the Build - Operate - Transfer (BOT) contract type,
or under supplementary agreements between the electricity purchasing unit and
the BOT generation unit, and the committed dispatched electricity output under
electricity import contracts (if any);
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79. Metered
output means the metered electricity output of a power plant at the electricity
delivery and receipt point.
80. Annual
planned output means the electricity output of a power plant expected to be
dispatched in the following year.
81. Monthly
planned output means the electricity output of a power plant expected to be
dispatched in the months of the year.
82. Fuel
consumption rate means the amount of thermal energy consumed by a
generating unit or power plant to produce one unit of electrical energy.
83. User
account means the login name of a user or member unit used to access the Electricity
Market Web Portal.
84. Offer
gate closure time means the time after which generation units are not
permitted to modify their offers, except in the cases prescribed in Article 49
of this Circular. In the electricity market, the offer gate closure time for Day
D is 11:30 on Day D-1; for a daily operating time block, it is before 8 hours
prior to the commencement time; and for next-interval operation, it is before
30 minutes prior to the commencement time.
85. Month
M means the current month of electricity market operation, calculated
according to the calendar month.
86. Electricity
market participant means an entity participating in trading activities or
providing services on the electricity market in accordance with Article 2 of
this Circular, except for the case prescribed in Clause 7 Article 2 of this
Circular.
87. Spot
electricity market means the market for electricity purchase and sale
during trading intervals, operated by the electricity market transaction
operator in accordance with the levels of the competitive electricity market.
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89. Electricity
market information means all data and information relating to activities of
the electricity market.
90. Dispatch
order means the result of arranging the capacity bands in the offer
according to the principle of prices from low to high, taking into account the
constraints of the power system.
91. Total
hours for calculating annual load factor means the total number of hours of
Year N for generating units that have commenced commercial operation from Year
N-1 or earlier, or the total number of hours from the time of commercial
operation of the generating unit until the end of the year for generating units
commencing commercial operation in Year N, excluding the outage period of the
generating unit under the approved maintenance plan for Year N.
92. Total
hours for calculating monthly load factor means the total number of hours
of Month M for generating units that have commenced commercial operation from Month
M-1 or earlier, or the total number of hours from the time of commercial
operation of the generating unit until the end of the month for generating
units commencing operation in Month M, excluding the outage period of the
generating unit under the approved maintenance plan for Month M.
93. Slow-start
generating unit means a generating unit that is unable to start and
synchronize with the grid in less than 30 minutes.
94. Electricity
market website means the website used for announcing electricity market
information.
95. Week
T means the current week of electricity market operation.
96. Gas
fuel limit exceedance means a case where the total capacity of the first
price band with identical offer prices in the offers of gas turbine generating
units submitted for day-ahead or next-interval scheduling, plus the minimum
stable generation capacity of generating units of power plants indirectly
participating in the electricity market scheduled for dispatch, exceeds the
total capacity limit of such power plants calculated and converted from the gas
limit. Gas fuel limit exceedance applies to dispatch scheduling and shall not
be used to adjust the contracted electricity output of power plants.
97. Metering
point means the location where the electricity metering system is installed
to determine delivered and received electricity output for electricity market
settlement, in compliance with the regulations on electricity transmission
systems, electricity distribution systems, and electricity metering promulgated
by the Ministry of Industry and Trade of Vietnam and other relevant laws.
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Chapter
II
REGISTRATION FOR PARTICIPATION IN
ELECTRICITY MARKET
Article
4. Responsibilities of generation units for participation in electricity market
1. Except
for the power plants prescribed in Clauses 2 and 3 of this Article, generation
units owning and operating the following power plants shall complete procedures
for registration for direct participation in the electricity market, including:
a) Power
plants with an installed capacity greater than 30 MW connected to the national
power system (including BOT power plants whose contracts have expired and which
have been transferred to Vietnam, and hydropower plants operating in cooperation
with strategic multi-purpose hydropower plants as prescribed in Point b Clause
4 Article 51 of the Law on Electricity);
b)
Hydropower plants with an installed capacity of 10 MW or more whose power
purchase agreements under the avoided cost tariff have expired, including cascade
hydropower plants;
c) Power
plants using other renewable energy sources with an installed capacity of 10 MW
or more whose power purchase agreements under the State’s incentive or
preferential pricing mechanisms have expired;
d) Renewable
energy power plants participating in the direct power trading mechanism through
the national grid in accordance with regulations.
2. Power
plants not prescribed in Clause 1 of this Article may choose to participate in
the electricity market. Where they choose to directly participate in the electricity
market, generation units shall:
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b)
Complete and submit the dossier for registration for participation in the electricity
market as prescribed in Clause 1 Article 7 of this Circular;
c) Comply
with the requirements applicable to generation units participating in the electricity
market under this Circular and relevant legislative documents.
3. Generation
units owning and operating power plants that indirectly participate in the
electricity market include:
a) BOT
power plants with valid power purchase agreements;
b) Gas-fired
thermal power plants subject to the constraint of maximum use of gas fuel
sources;
c) Strategic
multi-purpose hydropower plants;
d)
Imported power sources;
dd) Power
plants using other renewable energy sources, except for the cases prescribed in
Clauses 1 and 2 of this Article, and renewable energy power plants
participating in the direct power trading mechanism through private connection
grids in accordance with regulations;
e) Power
plants located in industrial parks that sell only part of, or do not sell,
their electricity output to the national power system, except for the case
prescribed in Clause 2 of this Article;
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h) Renewable
energy power plants operating under the avoided cost tariff mechanism with
valid power purchase agreements;
i)
Pumped-storage hydropower plants;
k)
Independent Battery Energy Storage Systems (BESS) serving the demand of the national
power system.
4. Before
November 1 of Year N, the power system and electricity market operation unit
shall prepare lists of direct trading generation units, indirect trading
generation units, and electricity purchasing units in the electricity market
for Year N+1 for announcement to electricity market participants, and
concurrently report them to the Electricity Authority of Vietnam for monitoring
and supervision.
5. Generation
units owning and operating power plants directly participating in the electricity
market shall invest in and complete equipment systems for connection to the electricity
market information system (including the offer system, dispatch order
management system, electricity market settlement support system, and internal
electricity market information network connection system), the SCADA/EMS system,
the electricity metering system, and digital signatures, meeting the
operational requirements of the electricity market and other requirements in
accordance with regulations.
Article
5. Responsibilities of electricity wholesale units for participation in
electricity market
1. Electricity
wholesale units shall register for participation in the electricity market
where they purchase electricity at metering points within the scope of the competitive
wholesale electricity market prescribed in Article 77 of this Circular.
2. Electricity
wholesale units shall invest in and complete equipment systems for connection
to the electricity market information system, the electricity metering system,
and remote metering data collection systems at boundary metering points within
their management scope, as well as digital signatures, meeting the operational
requirements of the electricity market and other systems in accordance with
regulations.
Article
6. Time of participation in electricity market
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a) From
the first day of Month M, if the commercial operation date of the power plant is
recognized before the 25th day of Month M-1;
b) From
the first day of Month M+1, if the commercial operation date of the power plant
is recognized from the 25th day to the last day of Month M-1.
2. Generation
units owning and operating power plants whose power purchase agreements under
the State’s incentive or preferential mechanisms have expired, including BOT
power plants transferred to Vietnam, shall participate in the electricity
market as follows:
a) From
the first day of Month M, if the power purchase agreement under the regulations
on the method for determining generation service prices; principles for
calculating electricity prices for implementation of power projects; and
principal contents of power purchase agreements promulgated by the Ministry of
Industry and Trade of Vietnam is concluded before the 25th day of Month M-1;
b) From
the first day of Month M+1, if the power purchase agreement under the regulations
on the method for determining generation service prices; principles for
calculating electricity prices for implementation of power projects; and
principal contents of power purchase agreements is concluded from the 25th day
to the last day of Month M-1, unless the generation unit voluntarily registers
for participation in the electricity market from the first day of Month M after
fully satisfying the prescribed conditions.
3. Electricity
wholesale units shall participate in the electricity market from the date on
which they carry out electricity delivery, receipt, and purchase from the transmission
grid.
Article
7. Registration for participation in electricity market by direct trading
generation units and electricity wholesale units
1. For direct
trading generation units
a) A generation
unit may participate in the electricity market when it fully satisfies the
following requirements:
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- It has
completed acceptance testing and put into operation the systems prescribed in
Clause 5 Article 4 of this Circular;
- It has
completed the conclusion of the power purchase agreement, and the commercial
operation date of the power plant has been recognized as agreed upon by the
parties in the power purchase agreement;
- An
agreement has been reached on the entity representing the cascade hydropower
group in submitting offers, where the generation unit acts as the
representative of the cascade hydropower group.
b) At
least 7 working days before the latest date by which it is required to
participate in the electricity market as prescribed in Article 6 of this
Circular, the generation unit shall submit 1 set of the dossier for
registration for participation in the electricity market for each power plant
to the power system and electricity market operation unit via the electricity
market website. The power system and electricity market operation unit shall
provide guidance to units on the components of the dossier for registration for
participation in the electricity market by generation units.
2. For electricity
wholesale units
a) An electricity
wholesale unit may participate in the electricity market when it satisfies the
following requirements:
- Its
electricity operation license remains valid;
- It
satisfies the regulations on electricity metering at its boundary delivery and
receipt metering points in accordance with regulations;
- It has
completed acceptance testing and put into operation the remote metering data
collection system at boundary metering points within its management scope, the
internal electricity market information network connection system, and digital
signatures.
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Article
8. Inspection of dossiers for registration for participation in electricity
market
1. Within
2 working days from the date of receipt of the dossier, the power system and
electricity market operation unit shall inspect the completeness of the dossier
for registration for participation in the electricity market and request the
registering entity to supplement and complete the dossier if the dossier fails
to satisfy the requirements prescribed in Article 7 of this Circular.
2. Within
3 working days from the date of receipt of a valid dossier, the power system
and electricity market operation unit shall inspect the dossier and assess the
entity’s eligibility for official participation in the electricity market.
3. Where
the entity registering for participation in the electricity market has fully
satisfied the conditions for participation in the electricity market, the power
system and electricity market operation unit shall notify the registering
entity and announce the information on the electricity market website at least 24
hours before the time such entity officially participates in the electricity
market.
Article
9. Information on electricity market participants
1. Electricity
market participants shall register their general information with the power
system and electricity market operation unit.
2. The power
system and electricity market operation unit shall develop and announce
detailed requirements for information for registration for participation in the
electricity market applicable to each type of electricity market participant.
3. Registration
of meters and connection points
a) The power
system and electricity market operation unit shall establish and maintain
registration information on meters and connection points within the trading
scope of the electricity market;
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c) The power
system and electricity market operation unit shall cooperate with relevant electricity
market participants in confirming the connection points and meters at the
connection points of each electricity market participant;
d) Where
there is any change in ownership of or responsibility for a connection point,
the relevant electricity market participant shall notify the power system and
electricity market operation unit.
4. The power
system and electricity market operation unit shall retain and update
registration information of all electricity market participants.
5. Where
there is any change in registration information, the electricity market
participant shall notify the power system and electricity market operation unit
of such change.
6. The power
system and electricity market operation unit shall update and announce registration
information of electricity market participants, including any changes, and
fully retain historical information and data.
7. The power
system and electricity market operation unit shall report to the Electricity
Authority of Vietnam cases of registration for participation in the electricity
market, commencement of participation in the electricity market, or failure to
carry out registration for participation in the electricity market in
accordance with regulations.
8. On a
monthly basis, the power system and electricity market operation unit shall
update, consolidate, and report to the Electricity Authority of Vietnam when an
entity registers for participation in the electricity market or when there is
any change relating to the participation of an electricity market participant,
including: the registration status and results of assessment of registration
dossiers of new members, cases of failure to carry out registration for
participation in the electricity market in accordance with regulations, changes
in registration information, or cessation of participation in the electricity
market by electricity market participants.
Article
10. Termination of participation in electricity market
1. Cases
of termination of participation in the electricity market
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- At the
request of the generation unit owning and operating the power plant where the
power plant completely ceases operation or where the power plant does not
maintain and is unable to restore the installed capacity stated in the
information registered for participation in the electricity market within 1
year;
- The
electricity operation license in the field of electricity generation of the
power plant is revoked or expires.
b) An electricity
wholesale unit no longer purchases electricity at the delivery and receipt
points within the scope of the electricity market, or its electricity operation
license in the field of electricity wholesale or retail is revoked or expires.
2. Where
an electricity operation license is revoked, the time of termination of
participation in the electricity market by the generation unit or electricity
wholesale unit shall be counted from the time such electricity operation
license is revoked under the decision of the competent authority. In other
cases, at least 30 days before the intended time of termination of
participation in the electricity market, the electricity market participant
shall send a written request for termination of participation in the electricity
market to the power system and electricity market operation unit.
3. Within
10 days from the date of receipt of the written notice requesting termination
of participation in the electricity market from an electricity market
participant, the power system and electricity market operation unit shall
consider and decide thereon, and report to the Electricity Authority of Vietnam
for supervision of implementation.
4. The power
system and electricity market operation unit shall retain the dossier and announce
information on the electricity market website regarding the termination of the
electricity market participant's participation in the electricity market.
Article
11. Dispatch of power plants not yet directly participating in electricity
market and power plants indirectly participating in electricity market
1. For
power plants that have not been issued an electricity operation license, or
whose electricity operation license has expired or has been revoked, the power
system and electricity market operation unit shall not dispatch such power
plants to generate electricity to the national power system, except where
urgent situations arise that seriously threaten the ability to ensure
electricity supply and are approved by the Minister of Industry and Trade of
Vietnam in accordance with regulations.
2. For power
plants or generating units of power plants that have been issued an electricity
operation license:
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- A
supply-demand imbalance occurs in the power system or dispatch is necessary to
ensure electricity supply;
- Dispatch
is necessary to satisfy downstream water supply requirements under inter-reservoir
operation procedures, single-reservoir operation procedures, or at the request
of a competent state authority, for hydropower plants;
- Dispatch
is necessary to prevent spilling, for hydropower plants.
b) For
power plants that have an agreed commercial operation date and have submitted
dossiers for registration for participation in the electricity market, or are
awaiting the time of participation in the electricity market: they shall be
dispatched as power plants indirectly participating in the electricity market;
c) For
generating units of power plants that have an agreed commercial operation date
or have entered official operation, while the remaining generating units have
not yet been energized for the first time or remain under testing for
commercial operation or official operation: they shall be dispatched as power
plants indirectly participating in the electricity market.
3. Where
dispatched by the power system and electricity market operation unit under
Clauses 1 and 2 of this Article, the generation unit owning and operating the
power plant or generating unit of the power plant shall be paid in accordance
with the power purchase agreement or the agreement reached between the two
parties.
Chapter
III
PRINCIPLES FOR OPERATION OF ELECTRICITY
MARKET
Article
12. Principles for operation of electricity market
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2. Respect
and guarantee the right of electricity sellers and purchasers in the electricity
market to freely choose their trading counterparties and transaction methods.
3. The
State shall regulate the operation of the competitive electricity market to
ensure the sustainable development of the power system and satisfy the
requirements for safe, stable, reliable, and efficient electricity supply.
Article
13. Trading day, trading interval, dispatch interval, and operating principles
1. A trading
day shall be calculated from 00:00 to 24:00 of a calendar day.
2. A trading
interval shall be 30 minutes, commencing at the beginning of each 30-minute
period during the trading day. When infrastructure conditions are satisfied,
the Ministry of Industry and Trade of Vietnam shall consider reducing the trading
interval to less than 30 minutes.
3. A dispatch
interval shall be 30 minutes, commencing at the beginning of each 30-minute
period during the trading day. When infrastructure conditions are satisfied,
the Ministry of Industry and Trade of Vietnam shall consider reducing the dispatch
interval to less than 30 minutes, concurrently with the reduction of the trading
interval prescribed in Clause 2 of this Article.
4. During
participation in the electricity market, all units shall comply with this
Circular and follow the dispatch instructions of the power system and
electricity market operation unit to ensure the stable operation of the electricity
market, effective competition, and the stable, safe, and reliable operation of
the power system.
5. Generation
units shall cooperate with fuel supply units to ensure the availability of
sufficient primary fuel to meet the operational and dispatch requirements of
the national power system; and shall submit offers that satisfy fuel
constraints and ensure the safe operation of the fuel supply system.
Article
14. Electricity trading nodes
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a) For a generation
unit, the trading node shall be the electricity delivery and receipt point
between the power plant owned by the generation unit and the national power
system;
b) For an
electricity wholesale unit, the trading node shall be:
- The electricity
delivery and receipt point between the transmission grid and the distribution
grid of the electricity purchasing unit;
- The electricity
delivery and receipt point, if any, between power plants participating in the electricity
market and the distribution grid of the electricity purchasing unit;
- The electricity
delivery and receipt point on the distribution grid with another electricity
purchasing unit participating in the electricity market.
2. Generation
units and electricity purchasing units shall register their trading nodes with
the power system and electricity market operation unit during the registration
process for participation in the electricity market. Where there is any change
to existing trading nodes or any addition of new trading nodes, generation
units and electricity purchasing units shall notify the power system and
electricity market operation unit accordingly.
3. The power
system and electricity market operation unit shall cooperate with relevant
units in establishing, managing, and announcing the list of trading nodes
corresponding to each electricity market participant.
4. The power
system and electricity market operation unit shall cooperate with relevant
units in establishing and managing the list of electricity meters for each trading
node to determine the electricity output traded in the electricity market at
such trading node during each trading interval.
Article
15. Offer price limits
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2. For
thermal generating units
a) The offer
price cap of a thermal generating unit shall be determined annually, adjusted
monthly, and calculated based on the following factors:
- The heat
rate of the generating unit;
- The efficiency
degradation factor over the operating period of the generating unit;
- Fuel
prices;
- The
variable price under the power purchase agreement.
b) The offer
floor price of a thermal generating unit shall be VND 0/kWh.
3. For
hydropower generating units:
a) The offer
price cap of a hydropower generating unit shall be prescribed in Article 44 of
this Circular;
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Article
16. Market prices applicable to direct trading generation units
1. Market
energy price applicable to generation units
a) The power
system and electricity market operation unit shall calculate the market energy
price after the operating period based on the unconstrained scheduling method;
b) The market
energy price shall not exceed the electricity market price cap.
2. Market
capacity price applicable to generation units
a) The power
system and electricity market operation unit shall calculate the market
capacity price during the preparation of the operation plan for the following
year, and such price shall remain unchanged throughout the applicable year;
b) The market
capacity price shall be calculated on the principle of ensuring that the best
new entrant fully recovers its variable costs and fixed costs.
3. The full
market electricity price applicable to generation units shall be the sum of the
following 2 components:
a) The market
energy price applicable to generation units;
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Article
17. Determination of contracted electricity output
1. General
provisions
a) The generation
unit and the electricity purchasing unit shall negotiate, agree upon, and
specify in the power purchase agreement either the contracted electricity
output or the percentage of electricity output settled at the contract price,
within the range prescribed in Point b of this Clause, for determining the
annual contracted electricity output or the contracted electricity output for
each year of a multi-year period. Based on the annual contracted electricity
output agreed upon in the power purchase agreement, the generation unit and the
electricity purchasing unit shall calculate and agree on the allocation of the contracted
electricity output to each month of the year.
Where the
generation unit and the electricity purchasing unit agree on the annual and
monthly contracted electricity output, they shall notify the power system and
electricity market operation unit of the agreed contents in writing so that the
power system and electricity market operation unit may allocate the contracted
electricity output to each trading interval. Where the generation unit and the electricity
purchasing unit only agree on the percentage of electricity output settled at
the contract price, they shall notify the power system and electricity market
operation unit, which shall calculate and allocate the contracted electricity
output in accordance with this Circular.
b) The
percentage of electricity output settled at the contract price shall not exceed
100% and shall not be lower than 60%.
c) For long-term
contracted electricity output:
- Annually,
the power system and electricity market operation unit shall calculate
scenarios for long-term contracted electricity output for the subsequent 5-year
period based on: updated forecasts of the national power system load demand and
regional load demand; available capacity and projected dispatched electricity
output of power plants in the national power system; take-or-pay obligations
(if any); approved power development planning; projected electricity prices of
power plants provided by the electricity purchasing unit; and other appropriate
input data;
- Based
on the long-term contracted electricity output scenarios calculated by the power
system and electricity market operation unit, the generation unit and the electricity
purchasing unit shall negotiate and agree on the long-term contracted
electricity output in the power purchase agreement;
- The
selected long-term contracted electricity output option shall ensure transparency,
reasonableness, consistency with the power system development plan, and the
objectives of safe, stable, reliable, and economically and technically optimal
operation of the national power system;
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2. For
power plants having power purchase agreements with EVN
a) Where
the generation unit and EVN agree on the annual and monthly contracted
electricity output, both parties shall provide such information to the power
system and electricity market operation unit for calculation and allocation of
the contracted electricity output to each trading interval in accordance with
Clause 3 Article 38 of this Circular.
b) Where
the generation unit and EVN agree on the percentage of electricity output
settled at the contract price but have not agreed on the annual contracted
electricity output; or fail to reach agreement on the annual and monthly contracted
electricity output, and in the case prescribed in Clause 5 of this Article:
- For
thermal power plants, the power system and electricity market operation unit
shall calculate the minimum contracted electricity output for Year N+1 and
allocate such minimum contracted electricity output to the months of Year N+1
in accordance with Article 29 of this Circular; calculate the monthly contracted
electricity output of the thermal power plant in accordance with Clause 1
Article 38 of this Circular; and allocate such output to each trading interval
in accordance with Clause 3 Article 38 of this Circular;
- For
hydropower plants, the power system and electricity market operation unit shall
calculate the monthly contracted electricity output in accordance with Clause 2
Article 38 of this Circular and the contracted electricity output for each trading
interval in accordance with Clause 3 Article 38 of this Circular.
3. For
power plants having power purchase agreements with EVN and allocated to
electricity wholesale units, and power plants having power purchase agreements
with electricity wholesale units
a) Where
the parties agree on the annual and monthly contracted electricity output, they
shall provide such information to the power system and electricity market
operation unit for calculation and allocation of the contracted electricity
output to each trading interval in accordance with Article 40 of this Circular.
b) Where
the parties agree on the percentage of electricity output settled at the
contract price but have not agreed on the annual contracted electricity output;
or fail to agree on the annual and monthly contracted electricity output, and
in the case prescribed in Clause 5 of this Article, the power system and
electricity market operation unit shall calculate the minimum annual contracted
electricity output, the minimum monthly contracted electricity output, and the
monthly contracted electricity output in accordance with Articles 29, 30, and
38 of this Circular, and allocate such output to each trading interval in
accordance with Article 40 of this Circular.
4. For
new power plants (commencing commercial operation after the effective date of this
Circular)
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b) Where
the generation unit and the electricity purchasing unit fail to agree on the contracted
electricity output for the remaining months of the year, the power system and
electricity market operation unit shall calculate such output in accordance
with Clause 1 or Clause 2 Article 38 of this Circular.
c) Contracted
electricity output for each trading interval: Unless otherwise agreed between
the generation unit and the electricity purchasing unit, the contracted
electricity output for each trading interval of the power plant shall be
determined by the power system and electricity market operation unit during the
preparation of the operation plan for the following month, based on the
allocation of the monthly contracted electricity output to the trading
intervals of that month in accordance with Clause 3 Article 38 and Article 40
of this Circular.
5. For
power plants having entered into a power purchase agreement but failing to
reach agreement with EVN or an electricity wholesale unit on either the
percentage of electricity output settled at the contract price or the annual
contracted electricity output for Year N+1 as prescribed in Clause 1 of this
Article for submission to the power system and electricity market operation
unit before November 15 of Year N:
a) The generation
unit and the electricity purchasing unit shall propose the percentage of
electricity output settled at the contract price and the contracted electricity
output, report such proposal to the Electricity Authority of Vietnam, and
provide it to the power system and electricity market operation unit before November
20 each year;
b) Based
on the reports of the generation unit and the electricity purchasing unit, the power
system and electricity market operation unit shall propose options for the percentage
of electricity output settled at the contract price for the following year in
accordance with Point b Clause 1 of this Article and report them to the Electricity
Authority of Vietnam;
c) Where
the parties still fail to reach agreement on the percentage of electricity
output settled at the contract price or on the annual or monthly contracted
electricity output: before December 10 of Year N, based on the calculation
results of the power system and electricity market operation unit under Point b
of this Clause, the Electricity Authority of Vietnam shall assess, appraise,
and submit to the Ministry of Industry and Trade of Vietnam for approval the percentage
of electricity output settled at the contract price for Year N+1 for
application by the parties during the period in which no agreement has been
reached, specifically as follows:
- The percentage
of electricity output settled at the contract price approved by the Ministry of
Industry and Trade of Vietnam shall be determined in accordance with the
principle prescribed in Point b Clause 1 of this Article, be appropriate to
each stage of development of the electricity market, and ensure a balance of
interests between the electricity purchaser and the electricity seller;
- Based
on the percentage of electricity output settled at the contract price announced
by the Ministry of Industry and Trade of Vietnam, the power system and
electricity market operation unit shall calculate the minimum annual contracted
electricity output and minimum monthly contracted electricity output in
accordance with Article 29 of this Circular, and the monthly contracted
electricity output in accordance with Clauses 1 and 2 Article 38 of this
Circular, and notify the generation unit and the electricity purchasing unit
for implementation in accordance with this Circular.
d) During
the period in which the percentage of electricity output settled at the
contract price approved by the Ministry of Industry and Trade of Vietnam is
applied, the generation unit and the electricity purchasing unit shall continue
negotiating the contracted electricity output for the remaining months of the
year. Where the generation unit and the electricity purchasing unit reach
agreement on the contracted electricity output for the remaining months of the
year, they shall provide such information to the power system and electricity
market operation unit for calculation and announcement. At the time when the power
system and electricity market operation unit calculates and announces the
contracted electricity output, if the generation unit and the electricity
purchasing unit still fail to reach agreement on the contracted electricity
output, the parties shall implement the contracted electricity output as
calculated and announced by the power system and electricity market operation
unit.
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a) Adjustment
of monthly contracted electricity output:
- Where
the generation unit and the electricity purchasing unit agree on the monthly contracted
electricity output, or agree on the contents relating to the adjustment of the
monthly contracted electricity output (including adjustment cases and
adjustment principles) before the operating month, the adjustment of the
monthly contracted electricity output shall be carried out in accordance with
the agreement between the parties. The parties shall notify the power system
and electricity market operation unit of the agreed contents for the operation
of the electricity market;
- Where
the monthly contracted electricity output of thermal power plants is calculated
by the power system and electricity market operation unit in accordance with
Clause 1 Article 38 of this Circular, and there is no other agreement between
the generation unit and the electricity purchasing unit regarding adjustment of
the monthly contracted electricity output, the adjustment of the contracted
electricity output shall be carried out in accordance with the principles
prescribed in Article 37 of this Circular.
b) Adjustment
of contracted electricity output for each trading interval:
- Where
the generation unit and the electricity purchasing unit agree on the principles
for adjustment of the contracted electricity output for each trading interval
(including adjustment cases and adjustment principles) before the power system
and electricity market operation unit calculates and announces the contracted
electricity output for each trading interval, such adjustment shall be carried
out in accordance with the agreement between the parties. The parties shall
notify the power system and electricity market operation unit of the agreed
contents for the operation of the electricity market;
- Where
the contracted electricity output for each trading interval is calculated by
the power system and electricity market operation unit in accordance with
Articles 39 and 40 of this Circular, and there is no other agreement between
the generation unit and the electricity purchasing unit regarding adjustment of
the contracted electricity output for each trading interval, such adjustment
shall be carried out in accordance with the principles prescribed in Article 39
of this Circular.
Article
18. Operation and dispatch of power sources
1. The
operation and dispatch of power sources in the power system shall comply with
the following requirements:
a) Ensure
the power system operates safely, stably, reliably, continuously, and satisfies
electricity load demand;
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- Technical
requirements of the power system and operating standards for electrical
equipment, ensuring voltage, frequency, and grid stability in accordance with
the regulations on electricity transmission systems, electricity distribution
systems, and electricity metering promulgated by the Ministry of Industry and
Trade of Vietnam;
- Technical
constraints of the primary fuel supply system as provided and announced by the fuel
supply unit;
- Downstream
water supply requirements or water level constraints prescribed in the inter-reservoir
operation procedures, reservoir operation procedures, or as required by
competent state authorities;
c) Give
priority to testing programs for commissioning generating units and power
plants into official operation;
d) Give
priority to hydropower plants located in areas directly affected by typhoons,
tropical depressions, and other hazardous weather phenomena to ensure the
safety of relevant works and downstream areas;
dd)
Ensure compliance with take-or-pay obligations and primary fuel consumption
constraints for electricity generation approved by competent state authorities
(if any);
e)
Optimize the technical-economic performance of the power system.
2. The
following cases constitute an overload or generation surplus in the power
system:
a) During
operation planning, where the aggregate minimum stable generation capacity of
grid-connected thermal generating units, or the capacity required to maintain
the technical constraints of grid-connected power sources, together with the
forecast output of renewable energy sources and the capacity of hydropower
plants currently discharging water, at risk of spillage, or required to satisfy
downstream water supply demand in a region, area, or the entire power system
during a trading interval, exceeds the regional load plus the interconnection
transmission capacity limit between regions or the forecast system load
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3. Where
an overload or generation surplus occurs in the power system as prescribed in
Clause 2 of this Article, the power system and electricity market operation
unit shall cooperate with dispatch authorities at all levels to comply with
Clause 1 of this Article and shall adjust dispatched capacity in the following
order:
a)
Operate available Battery Energy Storage Systems (BESS) to absorb electricity
from power sources during periods of generation surplus or overload for storage
and discharge the stored electricity when required by the power system;
b) Reduce
the generation output of thermal generating units in descending order of variable
costs, except for thermal generating units of gas-fired thermal power plants
subject to the constraint of maximum use of gas fuel sources and thermal power
plants subject to take-or-pay obligations;
c) Reduce
generation output or shut down generating units of hydropower plants that are
not discharging water (except for hydropower plants at risk of spillage
specified in Point i), in ascending order of the ratio of remaining storage
volume to allowable storage capacity, except for generating units of imported
hydropower plants subject to take-or-pay obligations;
d) Shut
down slow-start generating units in the following order: generating units
voluntarily requesting shutdown; generating units unable to support the power
system in overload relief and voltage regulation; according to the generating
unit offer price (applicable only to day-ahead, intra-day, and next trading
interval scheduling); according to variable costs, from highest to lowest;
where slow-start generating units have identical variable costs, shutdown shall
be based on start-up costs, from lowest to highest;
dd)
Reduce the generation output of biomass power plants;
e) Reduce
generation output or shut down generating units or power plants having
contractual provisions requiring reduction or shutdown before other power
plants (such conditions being specified in the connection agreement or the power
purchase agreement);
g) Reduce
the generation output of all or part of grid-connected wind power plants,
grid-connected solar power plants, and medium-voltage grid-connected rooftop
solar power systems, except for the power plants specified in Point n of this
Clause and imported renewable energy power plants subject to take-or-pay
obligations;
h) Reduce
the generation output of waste-to-energy power plants that still have the
capability to store primary fuel;
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k) Reduce
or shut down the offer floor price capacity of hydropower plants directly
participating in the electricity market and hydropower plants indirectly
participating in the electricity market that are at risk of spillage, in
ascending order of the ratio of remaining storage volume to allowable storage
capacity, taking into account the operating characteristics of generating
units, reservoir-specific characteristics, and impacts on downstream areas;
l) Shut
down thermal generating units of gas-fired thermal power plants subject to the
constraint of maximum use of gas fuel sources and power plants subject to fuel take-or-pay
obligations, in descending order of variable costs, taking into account the
operating characteristics of each type of source and their capability to
support the power system in overload relief and voltage regulation;
m) Reduce
the generation output of hydropower plants directly participating in the electricity
market that are discharging water and offering at the offer floor price, and
hydropower plants indirectly participating in the electricity market that are
discharging water;
n) Reduce
the generation output of power plants or part of power plants undergoing
testing for recognition of their commercial operation date or entry into
official operation.
4. For
generating units of power plants within the same group specified in Points dd,
g, h, i, l, and m Clause 3 of this Article, generation output reduction shall
be implemented on the principle of proportionally allocating the required
reduction according to rated capacity, available capacity, declared capacity,
or forecast capacity (depending on the power source type and dispatch method),
without regard to price criteria.
5. Where an
overload or generation surplus occurs in the power system, and dispatched
capacity must be adjusted in accordance with Clause 3 of this Article:
a) No
reduction or shutdown shall be applied to hydropower plants that must be
dispatched to ensure the safety of relevant works and downstream areas due to
the direct impact of typhoons, tropical depressions, or other hazardous weather
phenomena according to official bulletins issued by the National Center for
Hydro-Meteorological Forecasting or a Regional Hydro-Meteorological Station;
b)
Uniform reductions shall be applied across renewable energy sources and
hydropower plants discharging water where the surplus generation capacity is
substantial, occurs over multiple trading intervals in a day, and continues for
several consecutive days.
6. Power
purchase agreement information
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b) The
power system and electricity market operation unit shall use the information
provided under Point a of this Clause solely for the purposes of operating and
dispatching generating units and power plants in the national power system,
while ensuring compliance with applicable information confidentiality
requirements.
Chapter
IV
ELECTRICITY MARKET OPERATION PLANS
Section
1. OPERATION PLAN FOR THE FOLLOWING YEAR
Article
19. Operation plan for the following year
1. The
power system and electricity market operation unit shall prepare the electricity
market operation plan for the following year, including the following principal
contents:
a)
Selection of the best new entrant;
b)
Calculation of the market capacity price;
c)
Calculation of the water value and optimal water level of hydropower
reservoirs;
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dd)
Determination of options for the electricity market price cap
e)
Calculation of the annual planned output, the minimum annual contracted electricity
output, and allocation of the minimum annual contracted electricity output to
the months of the year for thermal power plants that have not reached agreement
on the annual or monthly contracted electricity output.
Detailed
contents of the electricity market operation plan for the following year are
prescribed in Appendix I enclosed with this Circular.
2. The
power system and electricity market operation unit shall use the electricity
market simulation model to calculate the contents prescribed in Clause 1 of
this Article. The input parameters used for simulation of thermal generating
units in the electricity market shall include the variable costs of the
generating units determined under Clause 3 of this Article, hydrological
characteristics, technical characteristics of hydropower plants, constraints
prescribed for preparation of the operating mode of the national power system
under the regulations on dispatching, operation, switching operations, incident
handling, black start, and restoration of the national power system promulgated
by the Ministry of Industry and Trade of Vietnam, take-or-pay obligations, and
constraints relating to secondary frequency control services.
3. The variable cost
of a thermal generating unit shall be determined as follows:
a) Where
the heat rate is specified in the power purchase agreement, the variable cost
of the generating unit shall be determined as follows:
Where:
VCb : Variable
cost of the generating unit (VND/kWh);
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:Variable price
component adjusted according to fluctuations in the cost of auxiliary fuel
(oil) of the power plant (VND/kWh);
: Variable price component
adjusted according to other changes affecting the power plant (VND/kWh).
- The
variable price component adjusted according to fluctuations in the cost of the
primary fuel of the power plant shall be determined using the following
formula:
Where:
: Variable price component
adjusted according to fluctuations in the cost of the primary fuel of the power
plant (VND/kWh);
: Average heat rate of the
primary fuel of the generating unit as specified in the power purchase
agreement (kg/kWh, BTU/kWh, or kcal/kWh);
: Primary fuel price,
including transportation, storage, and regasification costs, where applicable
(VND/kcal, VND/BTU, or VND/kg).
- The
variable price component adjusted according to fluctuations in the cost of the
auxiliary fuel of the power plant shall be determined using the following
formula:
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Where:
: Variable price component
adjusted according to fluctuations in the cost of the auxiliary fuel of the
power plant (VND/kWh);
: Average heat rate of the
auxiliary fuel agreed upon in the power purchase agreement based on the
equipment manufacturer's specifications (kg/kWh);
: Auxiliary fuel price,
including transportation charges and other applicable fees (VND/kg).
- The
average heat rate of the primary and auxiliary fuels shall be provided by the electricity
purchasing unit and adjusted by the efficiency degradation factor. Where the heat
rate specified in the power purchase agreement is the average heat rate over
the entire project life, no adjustment shall be made by the efficiency
degradation factor. Where the power purchase agreement specifies only the heat
rate curve at different loading levels, the heat rate of the generating unit
shall be determined at the loading level corresponding to the long-term average
electricity output of the power plant specified in the power purchase agreement.
Where the
thermal generating unit has no heat rate specified in the power purchase
agreement, it shall be determined based on the heat rate of a reference power
plant in the same group that has the same generation technology, installed
capacity, and manufacturer. The power system and electricity market operation
unit shall calculate the fuel consumption rate or heat rate of such reference
power plant.
- The efficiency
degradation factor of a thermal generating unit shall be the efficiency
degradation factor specified in the power purchase agreement and provided by
the electricity purchasing unit.
Where no efficiency
degradation factor is specified in the power purchase agreement, the efficiency
degradation factor of the reference power plant in the same group, as
determined by the power system and electricity market operation unit, shall
apply.
- The
other variable price component of the power plant 
(VND/kWh) shall be determined in accordance
with the power purchase agreement.
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c) The
basis for determining the price components and costs used in calculating the
variable price or variable cost for Year N shall be as follows:
- Fuel
prices applicable to Year N as announced by or determined in accordance with
the guidance of the competent authority;
- Fuel
prices applicable to Year N in accordance with the power purchase agreement and
the fuel supply agreement. Where fuel prices depend on the fuel supply plan
and/or fuel price indices, the generation unit and the fuel supply unit shall
provide the electricity purchasing unit with the fuel supply plan and/or fuel
price indices for consideration during the determination of the projected fuel
price for Year N;
- Fuel
prices based on electricity payment dossiers for the 3 most recent months
preceding the time of submission of data for preparation of the operation plan
for Year N, taking into account factors affecting fuel prices in Year N. Where,
at the time of preparation of the operation plan for Year N, the electricity
payment dossier reflecting the fully calculated fuel price for the most recent
month is not yet available (because the payment dossier does not yet reflect
the full fuel price under the fuel supply agreement), the average monthly fuel
price calculated from invoices in accordance with the fuel supply agreement may
be used;
- Where
the variable cost or fuel consumption rate specified in the power purchase
agreement is determined at different loading levels, the 85% loading level of
the power plant shall be applied in calculating the projected variable price
and variable cost for Year N.
4. Before
October 25 each year, the power system and electricity market operation unit
shall solicit comments from EVN, generation units, electricity wholesale units,
and other relevant entities on the electricity market operation plan for the
following year.
5. Before
November 5 each year, the consulted entities shall provide comments on the electricity
market operation plan for the following year to the power system and
electricity market operation unit for finalization.
6. Before
November 15 each year, based on the comments received, the power system and
electricity market operation unit shall finalize the calculations and submit
the electricity market operation plan for the following year (including
calculation results, input data, and explanatory notes as prescribed in this
Circular) to the Electricity Authority of Vietnam for appraisal.
7. Before
December 10 each year, the Electricity Authority of Vietnam shall submit the electricity
market operation plan for the following year to the Ministry of Industry and
Trade of Vietnam for consideration and approval, including the following contents:
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b) The percentage
of electricity output settled at the contract price (alpha factor) applicable
during the period in which the parties have not yet negotiated and agreed on
the contracted electricity output and the alpha factor;
c) The best
new entrant;
d) The electricity
market price cap for the following year;
dd) The market
capacity price for the following year.
Article
20. Classification of hydropower plants
1. Hydropower
plants in the electricity market shall be classified as follows:
a) Strategic
multi-purpose hydropower plants;
b) Cascade
hydropower groups;
c)
Hydropower plants with reservoirs having a regulating capacity of 2 days or
more;
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For
hydropower plants using water from irrigation reservoirs for electricity
generation and subject to special requirements imposed by competent state
authorities, the power system and electricity market operation unit shall
report to the Ministry of Industry and Trade of Vietnam for consideration and
decision on the form of participation of such power plants in the electricity
market for that year.
2. Annually,
the power system and electricity market operation unit shall classify and
update the list of hydropower plants prescribed in Clause 1 of this Article.
Article
21. Electricity load demand forecasting for preparation of operation plans for
the following year
1. The
power system and electricity market operation unit shall forecast electricity
load demand for preparation of the operation plan for the following year in
accordance with the method prescribed in the regulations on dispatching,
operation, switching operations, incident handling, black start, and
restoration of the national power system promulgated by the Ministry of
Industry and Trade of Vietnam. The forecast data for electricity load demand
used for preparing the operation plan for the following year shall include:
a) Total electricity
load demand of the national power system and the load demand of the Northern,
Central, and Southern regions for the entire year and for each month of the
year;
b) Electricity
load curves of typical days for the Northern, Central, and Southern regional
power systems and the entire national power system for each month of the year;
c) The
maximum and minimum demand of the national power system load for each month.
2. Where
the report on the calculation of the annual operation plan and operating mode
of the national power system, approved by the Ministry of Industry and Trade of
Vietnam, contains multiple electricity load demand forecast options or scenarios,
the power system and electricity market operation unit shall calculate and
select one forecast option for preparation of the electricity market operation
plan for the following year in accordance with one of the following options:
a) The electricity
load demand forecast option having a higher growth rate and being closest to
the average electricity load growth rate over the preceding 3 years. In
determining the average electricity load growth rate over the preceding 3
years, years with abnormal fluctuations caused by force majeure events (such as
natural disasters or epidemics) may be excluded;
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3. Electricity
wholesale units shall forecast electricity load demand for the following year
and submit the forecast to the power system and electricity market operation
unit in accordance with the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system promulgated by the Ministry of Industry and Trade of Vietnam.
Article
22. Auxiliary services for operation plans for the following year
1. The
types of auxiliary services for power system operation in the electricity
market include:
a) Secondary
frequency control;
b) Fast
start;
c) Voltage
control;
d) Black
start;
dd) Must-run
operating reserve.
2. The
power system and electricity market operation unit shall determine the demand
for auxiliary services in accordance with the regulations on electricity
transmission systems, electricity distribution systems, and electricity
metering and the regulations on dispatching, operation, switching operations,
incident handling, black start, and restoration of the national power system,
both promulgated by the Ministry of Industry and Trade of Vietnam.
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1. The
power system and electricity market operation unit shall use the electricity
market simulation model to determine the annual average load factor of power
plants.
2. Based
on the annual average load factor obtained from the simulation results, the
power system and electricity market operation unit shall classify base-load, intermediate-load,
and peak-load power plants into the following 3 groups:
a) Base-load
power plants, including power plants having an annual average load factor of 60%
or greater;
b) Intermediate-load
power plants, including power plants having an annual average load factor
greater than 25% but less than 60%;
c) Peak-load
power plants, including power plants having an annual average load factor of 25%
or less.
Article
24. Determination of offer price cap for thermal generating units
1. Where
heat rate data are available
a) The offer
price cap of a thermal generating unit shall be determined according to the
following formula:
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Ptr:
Offer price cap of the thermal generating unit (VND/kWh);
KDC:
Adjustment coefficient for the offer price cap based on the classification of
thermal power plants. For base-load power plants, KDC = 0%; for intermediate-load
power plants, KDC = 5%; for peak-load power plants, KDC =
20%;
PNLC:
Primary fuel price (including transportation cost of the primary fuel) of the
thermal generating unit (VND/kcal, VND/BTU, or VND/kg);
PNLP:
Auxiliary fuel price of the thermal generating unit (VND/kcal, VND/BTU, or
VND/kg);
Pbdkhac:
Other variable price component adjusted for other changes as determined under
the power purchase agreement (VND/kWh);
HRC:
Heat rate of the primary fuel at the average loading level of the thermal
generating unit (BTU/kWh, kcal/kWh, or kg/kWh);
HRP:
Heat rate of the auxiliary fuel at the average loading level of the thermal
generating unit (BTU/kWh, kcal/kWh, or kg/kWh).
b) Fuel
price parameters of thermal generating units shall be determined in accordance
with Clause 3 Article 19 of this Circular.
c) The
primary fuel price shall be provided by the electricity purchasing unit to the power
system and electricity market operation unit before September 1 of Year N-1.
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a) The
offer price cap of a thermal generating unit shall be determined according to
the following formula:
Where:
Ptr: Offer price cap of the thermal generating unit (VND/kWh);
KDC:
Adjustment coefficient for the offer price
cap based on the classification of thermal power plants. For base-load power
plants, KDC = 0%; for intermediate-load power plants, KDC
= 5%; for peak-load power plants, KDC = 20%;
: Variable price
(including transportation cost of the primary fuel) for Year N under the power
purchase agreement of the power plant (VND/kWh).
b) The
variable price (including transportation cost of the primary fuel) used for
calculating the offer price cap shall be the projected variable price for Year
N provided by the electricity purchasing unit to the power system and electricity
market operation unit.
3. The
power system and electricity market operation unit shall announce the input data
and calculation results for the offer price cap of thermal generating units.
Article
25. Determination of electricity market price cap applicable to generation
units
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2. The electricity
market price cap for Year N shall not exceed 115% of the highest offer price
cap among thermal generating units directly submitting offers in the electricity
market, and shall not be lower than the average variable cost of thermal
generating units directly submitting offers in the electricity market,
excluding generating units subject to dispatch constraints arising from take-or-pay
obligations or fuel supply capability.
3. The
option for the electricity market price cap applicable to Year N shall be
selected in accordance with the following principles:
a)
Ensuring the technical-economic optimization of the power system and the electricity
market, while balancing the interests of the electricity purchaser and the electricity
seller in the electricity market;
b)
Ensuring consistency with the selection of the best new entrant for determining
the market capacity price, with the objective of enabling full recovery of
electricity generation costs and encouraging power plants to participate in the
electricity market.
Article
26. Selection of the best new entrant;
1. The best
new entrant for Year N shall be a power plant participating in the electricity
market that satisfies all of the following criteria:
a)
Commenced commercial operation of its entire installed capacity in Year N-1,
except for the case specified in Clause 3 of this Article;
b)
Classified as a base-load power plant in accordance with the criteria
prescribed in Clause 2 Article 23 of this Circular;
c) Uses
coal-fired thermal power generation technology or combined-cycle gas turbine
technology;
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2. The electricity
purchasing unit shall prepare a list of power plants satisfying the criteria
prescribed in Points a and c Clause 1 of this Article and provide the power system
and electricity market operation unit with the power purchase agreement data of
such power plants or the data agreed upon with the generation unit for
determining the best new entrant. The information provided shall include:
a) The variable
price for Year N;
b) The fixed
price for Year N agreed in the power purchase agreement and applicable to
settlement during Year N;
c) The
agreed electricity output used for calculating the contract price.
3. Where
fewer than 3 power plants satisfy the criteria prescribed in Points a, b, and c
Clause 1 of this Article, the power system and electricity market operation
unit shall supplement the list with the best new entrants selected for Year N-1,
in order of the most recent commercial operation dates, until the list contains
3 power plants, and shall request the electricity purchasing unit to update and
resubmit the information prescribed in Clause 2 of this Article for calculation
and selection of the best new entrant for Year N.
4. The power system
and electricity market operation unit shall calculate the average full
generation cost of each power plant satisfying the criteria prescribed in
Points a, b, and c Clause 1 of this Article using the following formula:
Where:
PTPTB: Average full
generation cost of the power plant in Year N (VND/kWh);
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: Variable price for Year N under the power purchase
agreement of the power plant (VND/kWh);
: Agreed electricity output used for calculating the
contract price for Year N of the power plant (kWh);
: Projected electricity output in Year N of the power plant
determined from the electricity market simulation model using the constrained
scheduling method (kWh).
5. The
list of best new entrants shall be ranked in ascending order of average full
generation cost. The best new entrant selected for Year N shall be the power
plant having the lowest average full generation cost as determined in
accordance with Clause 4 of this Article.
Article
27. Principles for determining market capacity price
1. Ensure
that the best new entrant fully recovers its electricity generation costs when
participating in the electricity market.
2. Ensure
that the market capacity price is proportional to the forecast load demand of
the national power system for each trading interval.
Article
28. Procedure for determining market capacity price
The power
system and electricity market operation unit shall determine the market
capacity price in accordance with the following procedure:
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a)
Determine the projected market revenue of the best new entrant for Year N using
the following formula:
Where:
RTTD:
Projected revenue from the market energy price of the best new entrant in Year
N (VND);
i: Trading interval i in Year N;
I: Total number of trading intervals in Year N;
SMPi:
Projected market energy price for trading interval i in Year N, determined from
the electricity market simulation model using the unconstrained scheduling
method (VND/kWh);
: Projected electricity
output at the metering point of the best new entrant during trading interval i
in Year N, determined from the electricity market simulation model using the constrained
scheduling method (kWh).
b)
Determine the total annual electricity generation cost of the best new entrant
using the following formula:
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Where:
TCBNE:
Total annual electricity generation cost of the best new entrant in Year N
(VND);
PBNE:
Average full generation cost per kWh of the best new entrant, determined in
accordance with Clause 4 Article 26 of this Circular (VND/kWh);
: Projected electricity
output at the metering point of the best new entrant during trading interval i
in Year N, determined from the electricity market simulation model using the constrained
scheduling method (kWh);
i:
Trading interval i in Year N;
I: Total number of trading intervals in Year N.
c) The
annual revenue shortfall of the best new entrant shall be determined using the
following formula:
AS = TCBNE - RTTD
Where:
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TCBNE:
Total annual electricity generation cost of the best new entrant in Year N,
determined under Point b of this Clause (VND);
RTTD:
Projected revenue from the market energy price of the best new entrant in Year
N, determined under Point a of this Clause (VND).
d) Where
the calculated annual revenue shortfall is negative under the option with the
lowest electricity market price cap, the power system and electricity market
operation unit shall report to the Electricity Authority of Vietnam for
selection of the next best new entrant in the list of new power plants
prescribed in Article 26 of this Circular and recalculate the results, or
review the list of power plants participating in the electricity market to
determine an electricity market price cap consistent with this Circular.
2. Determination
of the monthly revenue shortfall
The monthly
revenue shortfall of the best new entrant shall be determined by allocating the
annual revenue shortfall among the months of Year N using the following
formula:
Where:
M: Month M of Year N;
MS: Monthly revenue shortfall of the best new entrant (VND);
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: Peak system load
in Month M (MW).
3. Determination
of the market capacity price for each trading interval
a)
Determine the average annual available capacity of the best new entrant using
the following formula:
Where:
: Average annual available capacity of the best new
entrant in Year N (kW);
I: Total
number of trading intervals in Year N;
i: Trading interval during which the best new entrant is
projected to be dispatched;
: Projected dispatched capacity of the best
new entrant during trading interval i in Year N, determined from the electricity
market simulation model using the constrained scheduling method and converted
to the metering point (kW).
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Where:
I: Total number of trading intervals in Month t;
i: Trading interval i in Month t;
CANi:
Market capacity price for trading interval i (VND/kWh);
: Average annual
available capacity of the best new entrant in Year N (kW);
MSM:
Monthly revenue shortfall of the best new entrant in Month M (VND);
: Forecast system load for
trading interval i according to the forecast typical day load curve for Month M
(MW);
ΔT:
Duration of 1 trading interval (minutes).
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1. Determination
of the minimum annual contracted electricity output
a) The
total minimum annual contracted electricity output of a thermal power plant
shall be calculated using the following formula:
Qctt = a x α x GO
Where:
Qctt :
Total minimum annual contracted electricity output for Year N (kWh);
GO: Long-term average electricity output of the power plant
as specified in the power purchase agreement (kWh);
a: Annual generation output adjustment factor applicable
separately to coal-fired thermal power plants and gas-fired thermal power
plants, as prescribed by the Ministry of Industry and Trade of Vietnam after
considering the proposal of the power system and electricity market operation
unit and the opinions of relevant entities. The factor a shall be selected on
the principle of ensuring consistency with the selected alpha factor, ensuring
that the calculated total minimum contracted electricity output appropriately
reflects primary fuel constraints, contributes to ensuring electricity supply,
and balances the interests of the electricity purchaser and the electricity
seller;
α: Percentage of electricity output settled at the contract
price applicable to Year N (%).
b) For
thermal power plants, offshore wind power plants, and new energy power plants
eligible for the long-term minimum contracted electricity output mechanism under
the regulations on power development planning, power supply network development
plans, investment in construction of power projects, and bidding for selection
of investors in electricity business projects, and the regulations on the
development of renewable energy and new energy promulgated by the Government of
Vietnam, together with the relevant amending, supplementing, or replacing legal
documents, the following shall apply:
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- Where
the total minimum annual contracted electricity output for Year N is lower than
the long-term minimum contracted electricity output, the total minimum annual contracted
electricity output for Year N shall be adjusted to the long-term minimum contracted
electricity output specified in the power purchase agreement.
2. Determination
of the minimum monthly contracted electricity output
The
minimum monthly contracted electricity output of a thermal power plant shall be
determined during the preparation of the operation plan for the following year
as follows:
a) The electricity
market simulation model prescribed in Clause 2 Article 19 of this Circular
shall be used, applying the constrained scheduling method, to determine the
projected monthly electricity output of the power plant;
b) The
minimum monthly contracted electricity output shall be determined using the
following formula:
Where:
: Minimum contracted electricity output of the power
plant for Month M (kWh);
Qctt: Total minimum annual contracted electricity output of the
power plant (kWh);
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Where the
monthly available output of the power plant is insufficient to meet the minimum
monthly contracted electricity output, the minimum monthly contracted
electricity output shall be adjusted to equal the monthly available output. The
power system and electricity market operation unit shall allocate the
difference to the remaining months of the year, ensuring that the total minimum
annual contracted electricity output remains unchanged.
c) For
thermal power plants, offshore wind power plants, and new energy power plants
eligible for the long-term minimum contracted electricity output mechanism
under the regulations on power development planning, power supply network
development plans, investment in construction of power projects, and bidding
for selection of investors in electricity business projects, and the regulations
on the development of renewable energy and new energy promulgated by the
Government of Vietnam, together with the relevant amending, supplementing, or
replacing legal documents, the following shall apply:
- The
minimum monthly contracted electricity output for Month M in Year N shall be
determined in accordance with Points a and b of this Clause;
- Where
the total minimum contracted electricity output for Month M in Year N is lower
than the long-term minimum contracted electricity output determined for Month M,
the total minimum contracted electricity output for Month M in Year N shall be
adjusted to the corresponding long-term minimum contracted electricity output
specified in the power purchase agreement (if any).
3. For a
new thermal power plant commencing participation in the electricity market
during the middle of the current operating year, its minimum annual and minimum
monthly contracted electricity output shall be determined in accordance with
the principles prescribed in Clauses 1 and 2 of this Article once complete
information under the power purchase agreement is available.
Article
30. Responsibilities for determining minimum annual contracted electricity
output and minimum monthly contracted electricity output
1. The
power system and electricity market operation unit shall:
a)
Calculate the minimum annual and minimum monthly contracted electricity output
of thermal power plants in accordance with Article 29 of this Circular;
b)
Solicit comments on the Electricity Market Web Portal on the input data used
for calculation and the preliminary calculation results of the minimum annual
and minimum monthly contracted electricity output of electricity purchasing
units and direct trading generation units for verification within 3 days after
the electricity market operation plan for the following year has been approved
by the Ministry of Industry and Trade of Vietnam.
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3. For
power plants having power purchase agreements with an electricity wholesale unit,
the generation unit and the electricity wholesale unit shall verify and
cooperate with the power system and electricity market operation unit in
resolving any discrepancies in the calculated minimum annual and minimum
monthly contracted electricity output within 2 days after the power system and
electricity market operation unit organizes the solicitation of comments on the
Electricity Market Web Portal.
4. Within
1 day after receiving comments from the relevant entities, the power system and
electricity market operation unit shall revise the calculation results (if
necessary) and officially announce the minimum annual and minimum monthly contracted
electricity output applicable to the relevant entities.
Article
31. Announcement of electricity market operation plans for the following year
1. After
the electricity market operation plan for the following year has been approved
in accordance with Article 19 of this Circular, the power system and
electricity market operation unit shall announce on the Electricity Market Web
Portal the input data and the results of the preparation of the electricity
market operation plan for the following year for electricity market
participants.
2. The announced
information on the electricity market operation plan for the following year
shall include:
a)
Results of the calculations for the operation plan for the following year,
including:
- Projected
market energy price for each trading interval applicable to generation units
and electricity wholesale units;
- Results
of the selection of the best new entrant;
- Market
capacity price for each trading interval;
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- Classification
of thermal power plants.
b) Input
parameters used in preparing the annual electricity market operation plan,
including:
- Forecast
load demand for the Northern, Central, and Southern regions and for the entire national
power system in each trading interval;
- Hydrological
data and operating constraints of hydropower reservoirs used in the electricity
market simulation;
- Schedule
for commissioning new power plants; technical parameters and operating
constraints of the transmission grid;
- Projected
electricity import and export schedules; annual maintenance and repair plans
for power plants, the transmission grid, and major gas supply sources;
- Forecast
load demand of electricity wholesale units for each trading interval;
- Take-or-pay
obligations;
- Minimum
gas flow required to prevent shutdown of gas production platforms and ensure
the safety of gas fields;
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3. Information
on the electricity market operation plan for the following year shall only be announced
to direct trading generation units owning power plants directly related to such
information (except EVN), including:
a) Total
projected electricity generation output of the power plant for each month as
determined in the electricity market simulation;
b) The water
value of the hydropower plant;
c) The variable
price data of the thermal power plant used in the simulation calculations.
Section 2. OPERATION PLAN FOR THE FOLLOWING MONTH
Article
32. Electricity load demand forecasting for preparation of operation plans for
the following month
1. The
power system and electricity market operation unit shall forecast electricity
load demand for preparation of the operation plan for the following month in
accordance with the method prescribed in the regulations on dispatching,
operation, switching operations, incident handling, black start, and
restoration of the national power system promulgated by the Ministry of
Industry and Trade of Vietnam. The forecast data for electricity load demand
used for preparing the operation plan for the following month shall include:
a) Total electricity
load demand of the national power system and the load demand of the Northern,
Central, and Southern regions for the entire month and for each trading
interval of the month;
b) Electricity
load curves of typical days for the Northern, Central, and Southern regions and
the entire national power system during the month.
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Article
33. Calculation of water value
The power
system and electricity market operation unit shall calculate the water value
for the weeks of the following month. The calculated water value results used
for preparation of the operation plan for the following month shall include:
1. Projected
electricity output of strategic multi-purpose hydropower plants.
2. Water
value of hydropower plants in cascade hydropower groups.
3. Water
value of hydropower plants with reservoirs having a regulating capacity of 2 days
or more.
4. Weekly
optimal water levels during the month for hydropower plants with reservoirs
having a regulating capacity of 2 days or more.
Article
34. Classification of base-load, intermediate-load, and peak-load power plants
for the following month
1. The
power system and electricity market operation unit shall use the electricity
market simulation model to determine the monthly average load factor of power
plants for the following month.
2. Based
on the monthly average load factor obtained from the simulation results, the
power system and electricity market operation unit shall classify base-load, intermediate-load,
and peak-load power plants for the following month into the following 3 groups:
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b) Intermediate-load
power plants, including power plants having a monthly average load factor
greater than 25% but less than 70%;
c) Peak-load
power plants, including power plants having a monthly average load factor of 25%
or less.
Article
35. Adjustment of offer price cap for thermal generating units
1. The power
system and electricity market operation unit shall calculate and adjust the offer
price cap of thermal generating units for the following month in accordance
with the method prescribed in Article 24 of this Circular, taking into account
updated factors affecting the variable price for Month M in accordance with the
method agreed in the power purchase agreement, based on the following:
a) Fuel
prices for the following month and the remaining months of the year shall be
determined as follows:
a1) Fuel prices used in preparing the operation plan for the
following month (M+1) shall be determined based on:
- Fuel
prices applicable to the following month as announced by or determined in
accordance with the guidance of the competent authority;
- Fuel
prices applicable to the following month under the power purchase agreement and
the fuel supply agreement. Where fuel prices depend on the fuel procurement
plan and/or fuel price indices, the generation unit and the fuel supply unit
shall provide the electricity purchasing unit with the fuel supply plan and/or
fuel price indices for consideration in determining the projected fuel prices
for the following month and the remaining months of the year;
- Fuel
prices stated in the electricity payment dossier for the month immediately
preceding the submission of data for preparation of the operation plan for the
following month.
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- Where
forecast fuel price data for the period from Month M+2 to year-end are issued
by a competent authority or a reputable forecasting consultancy, the fuel
prices of power plants shall be determined based on such forecast data and the
provisions of the fuel supply agreement;
- Where
no forecast fuel price data are available, the fuel prices used in preparing
the operation plan for the following month shall be applied;
- Fuel
quantities shall be determined based on the most recently updated fuel supply
plan for the period from Month M+2 to year-end provided by the generation unit
and the fuel supply unit.
b) The electricity
purchasing unit shall provide and update the power system and electricity
market operation unit on changes in the variable price (including the
transportation cost of the primary fuel) applicable to thermal power plants for
the following month and the remaining months of the year.
c) The
classification results of thermal power plants for the following month in
accordance with Article 34 of this Circular.
2. The
power system and electricity market operation unit shall announce the input
data and the offer price cap results for thermal generating units for the
following month.
Article
36. Secondary frequency control service in operation plans for the following
month
1. The power
system and electricity market operation unit shall determine the demand for secondary
frequency control service of the power system for the following month in
accordance with the regulations on electricity transmission systems,
electricity distribution systems, and electricity metering and the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system, both promulgated by the
Ministry of Industry and Trade of Vietnam.
2. The power
system and electricity market operation unit shall prepare and announce the
list of generating units eligible to provide secondary frequency control
service for the following month in accordance with the regulations on
electricity transmission systems, electricity distribution systems, and
electricity metering and the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system, both promulgated by the Ministry of Industry and Trade of
Vietnam.
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1. The
monthly contracted electricity output of a power plant shall be adjusted where
the maintenance and repair schedule of the power plant for Month M+1 differs
from the operation plan used for calculating the contracted electricity output
due to:
a) A
request from the power system and electricity market operation unit to ensure
electricity supply, provided that such request is not attributable to causes
arising from the power plant;
b) A
request from a competent state authority and agreed upon by the power system
and electricity market operation unit based on the actual operating conditions
of the power system.
2. In the
cases prescribed in Clause 1 of this Article, the power system and electricity market
operation unit shall adjust the monthly contracted electricity output in
accordance with the following principle: the portion of the monthly contracted
electricity output corresponding to the rescheduled maintenance period shall be
shifted between months, ensuring that the total contracted electricity output
of the adjusted months remains unchanged in accordance with the settlement
calculation procedures in the electricity market set out in Appendix III
enclosed with this Circular.
3. Where
the approved available output of the power plant for Month M+1 is insufficient
to meet the monthly contracted electricity output, the monthly contracted
electricity output shall be adjusted to equal the available output for that
month. The generation unit shall provide the power system and electricity market
operation unit, before the 20th day of Month M, with information on the fuel
supply plan for the thermal power plant for the following month (confirmed by
the fuel supply unit) as the basis for preparing the operation plan for the
following month and, where necessary, considering adjustment of the contracted
electricity output in such case.
4. Where
there are significant fluctuations (changes exceeding 20%) in input fuel prices
or force majeure events (such as natural disasters or epidemics) affecting the
normal operation of the power system (including load shedding or the loss of a
substantial amount of load, loss of or impacts on electricity transmission
capability between regions, impacts on the normal operation of a substantial
number of power plants, or spillway discharge from hydropower reservoirs as
required by competent state authorities), the power system and electricity market
operation unit shall update the relevant data, recalculate the electricity
market operation plans for the remaining months of the quarter, and report to
the Ministry of Industry and Trade of Vietnam for consideration and decision.
Article
38. Determination of contracted electricity output for each trading interval of
power plants having power purchase agreements with EVN
The power
system and electricity market operation unit shall determine the monthly
contracted electricity output and the contracted electricity output for each
trading interval of power plants having direct contracts with EVN for the
following month in accordance with the following steps:
1. The
monthly contracted electricity output of coal-fired thermal power plants shall
be determined quarterly; the monthly contracted electricity output of gas
turbine power plants shall be determined once every 6 months; and the contracted
electricity output of offshore wind power plants and new energy power plants
shall be determined monthly, specifically as follows:
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Where:
: Monthly contracted electricity output of the power
plant (kWh);
: Monthly planned output of coal-fired thermal power plants
under the updated power system operating mode for the first month of each
quarter (January, April, July, and October), or of gas turbine power plants
under the power system operating mode for January and July, or of offshore wind
power plants and new energy power plants under the monthly power system
operating mode, converted to the electricity delivery and receipt point (kWh);
QcttM :
Minimum monthly contracted electricity output of the power plant (kWh),
determined in accordance with Clause 2 Article 29 of this Circular;
α : Percentage of electricity output settled at the
contract price applicable to Year N (%).
2. The monthly contracted
electricity output of a hydropower plant with a reservoir having a regulating
capacity of 2 days or more shall be determined as follows:
QcM = α x QdkM
Where:
: Monthly contracted
electricity output of the power plant (kWh);
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α: Percentage of electricity output settled at the contract
price applicable to Year N (%).
3. The contracted
electricity output of a power plant for each trading interval of the month
shall be determined according to the following principles:
a) The contracted
electricity output for each trading interval shall be proportional to the
projected electricity output of the power plant for each trading interval of
the month, as determined by the electricity market operation planning system
using the constrained scheduling method, according to the following formula:
Where:
i: Trading interval i
of the month;
I: Total number of trading
intervals in the month;
: Contracted electricity
output of the power plant during trading interval i (kWh);
: Projected electricity output of the power plant during
trading interval i, determined from the electricity market simulation model
using the constrained scheduling method (kWh);
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b) The contracted
electricity output for each trading interval shall be adjusted to ensure
consistency with the forecast load demand of the national power system, taking
into account the impacts of renewable energy sources, the primary fuel supply
capability of the generation unit, downstream water supply requirements
applicable to hydropower plants, the operating capability and availability of
power plants, and the demand of the power system.
4. The power
system and electricity market operation unit shall allocate the total
difference arising from the adjustment of the contracted electricity output
under Clause 3 of this Article to other trading intervals of the month, on the
principle of ensuring that the monthly contracted electricity output remains
unchanged.
5. The
power system and electricity market operation unit shall announce on the Electricity
Market Web Portal the input data used for calculation and the preliminary calculation
results of the monthly contracted electricity output for the electricity
purchasing unit and direct trading generation units at least 5 days before the
last day of Month M. The electricity purchasing unit and the generation units
shall cooperate with the power system and electricity market operation unit in
completing the verification of discrepancies in the calculated contracted
electricity output for each trading interval of the following month at least 3
days before the last day of Month M. The power system and electricity market
operation unit shall announce the official calculation results of the contracted
electricity output for each trading interval of the month on the Electricity
Market Web Portal for the electricity purchasing unit and direct trading
generation units at least 3 days before the last day of Month M.
6. The electricity
purchasing unit and direct trading generation units shall sign to confirm the
monthly contracted electricity output adjusted in accordance with Article 39 of
this Circular and the contracted electricity output for each trading interval
based on the calculation results of the power system and electricity market
operation unit.
Article
39. Adjustment of contracted electricity output for each trading interval of
thermal power plants having power purchase agreements with EVN
1. Cases
in which the contracted electricity output of a thermal power plant shall be
adjusted:
a) Where
a boiler of a multi-boiler thermal generating unit is shut down due to an
incident, a generating unit is shut down due to an incident, or the power plant
undergoes an unplanned emergency repair not included in the calculation of the contracted
electricity output for each trading interval;
b) Where
a boiler of a multi-boiler thermal generating unit or a generating unit of a
thermal power plant requires a repair period longer than the approved
maintenance and repair schedule used in calculating the contracted electricity
output for each trading interval;
c) Where
information on a shortage of gas fuel is announced in accordance with Clause 7
Article 56 of this Circular;
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dd) Where
the start-up time of a thermal generating unit, calculated from the
commencement of start-up to synchronization with the grid, exceeds the start-up
time prescribed in the power purchase agreement by more than 2 hours;
e) Where
information is announced regarding a change in the gas system maintenance and
repair plan compared with the gas system maintenance and repair plan used for
allocating the contracted electricity output for each trading interval under
the monthly plan.
2. Where
there are sufficient grounds to confirm a case prescribed in Point a Clause 1
of this Article, the contracted electricity output for each trading interval shall
be adjusted according to the following principles:
a) Where
the incident duration is 72 hours or less, the contracted electricity output of
the power plant shall not be adjusted;
b) Where
the incident duration exceeds 72 hours
b1) From
the time the incident occurs until the end of the trading interval marking the
completion of the 72-hour period, the contracted electricity output allocated
to the power plant shall remain unchanged;
b2) From
the first trading interval after the end of the 72 -hour period until the
generating unit has remedied the incident and becomes available:
- Where
the actual electricity output at the electricity delivery and receipt point of
the power plant is lower than the contracted electricity output of the power
plant during this period, the contracted electricity output for each trading
interval shall be adjusted to equal the actual electricity output at the electricity
delivery and receipt point of the power plant;
- Where
the actual electricity output at the electricity delivery and receipt point of
the power plant is greater than or equal to the contracted electricity output
of the power plant during this period, the contracted electricity output of the
power plant shall not be adjusted.
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c1) From
the commencement of the repair until the end of the trading interval marking
the completion of the 72 -hour period, the contracted electricity output
allocated to the power plant shall remain unchanged;
c2) From
the first trading interval after the end of the 72 -hour period until the
generating unit becomes available:
- Where
the actual electricity output at the electricity delivery and receipt point of
the power plant is lower than the contracted electricity output of the power
plant during this period, the contracted electricity output for each trading
interval shall be adjusted to equal the actual electricity output at the electricity
delivery and receipt point of the power plant;
- Where
the actual electricity output at the electricity delivery and receipt point of
the power plant is greater than or equal to the contracted electricity output
of the power plant during this period, the contracted electricity output of the
power plant shall not be adjusted.
3. Where
there are sufficient grounds to confirm a case prescribed in Point b Clause 1
of this Article, the contracted electricity output for each trading interval
shall be adjusted according to the following principle:
During
the trading intervals of the extended repair period, where the actual
electricity output at the electricity delivery and receipt point of the power
plant is lower than the contracted electricity output of the power plant, the contracted
electricity output for such trading intervals shall be adjusted to equal the
actual electricity output at the electricity delivery and receipt point of the
power plant.
4. In the
cases prescribed in Points c, d, and dd Clause 1 of this Article, the contracted
electricity output of gas turbine power plants and coal-fired thermal power
plants for the relevant trading intervals shall be adjusted according to the
following principle: where the actual electricity output at the electricity
delivery and receipt point of the power plant during a trading interval is
lower than the contracted electricity output of the power plant, the contracted
electricity output for such trading interval shall be adjusted to equal the
actual electricity output at the electricity delivery and receipt point of the
power plant.
5. The direct
trading generation unit shall cooperate with the power system and electricity
market operation unit in confirming the events prescribed in Clause 1 of this
Article and provide the confirmation to the electricity purchasing unit and the
direct trading generation unit as the basis for adjusting the contracted
electricity output for each trading interval of the power plant. For
confirmation of a boiler incident involving a multi-boiler coal-fired thermal
generating unit:
a) Where
sufficient data relating to the event are available from the distributed
control system (DCS) or other equivalent control systems, the event shall be
confirmed based on such data;
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6. The electricity
purchasing unit and the direct trading generation unit shall re-sign to confirm
the monthly contracted electricity output of the power plant as adjusted in
accordance with Clauses 1, 2, and 3 of this Article and Clause 6 Article 17 of
this Circular.
Article
40. Determination of contracted electricity output for each trading interval of
power plants having power purchase agreements with electricity wholesale units,
and power plants having power purchase agreements with EVN and allocated to
electricity wholesale units
1. For
power plants having power purchase agreements with electricity wholesale units:
a) The contracted
electricity output of a power plant for each trading interval shall be
determined as follows:
- Determine
the monthly contracted electricity output of the power plant in accordance with
Clause 1 Article 38 of this Circular;
- Determine
and adjust the contracted electricity output of the power plant for each trading
interval in accordance with Clause 3 Article 38 and Article 39 of this
Circular.
b) Contracted
electricity output for each trading interval between an electricity wholesale
unit and a power plant having a power purchase agreement with such electricity
wholesale unit
The power
system and electricity market operation unit shall calculate such output using
the following formula:
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i: Trading interval i of the month;
: Contracted electricity
output between electricity wholesale unit l and power plant g during trading
interval i (kWh);
: Contracted electricity output of power plant g during
trading interval i, determined and adjusted in accordance with Point a of this
Clause (kWh);
: Forecast electricity output delivered and received at the
supply source of electricity wholesale unit l during trading interval i (kWh);
L: Total number of electricity wholesale units.
2. For
power plants having power purchase agreements with EVN and allocated to electricity
wholesale units:
a) The contracted
electricity output for each trading interval between the power plant and EVN
shall be determined as follows:
- Adjust
the monthly contracted electricity output of the power plant in accordance with
Clause 1 Article 38 of this Circular;
- Determine
and adjust the contracted electricity output of the power plant for each
trading interval in accordance with Clause 3 Article 38 and Article 39 of this
Circular.
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The power
system and electricity market operation unit shall calculate such output in the
following sequence:
- Determine
the monthly contracted electricity output allocated by EVN to an electricity
wholesale unit using the following formula:
Where:
L: Total number of electricity wholesale units;
Qc(l,M):
Contracted electricity output for Month M allocated by EVN to electricity
wholesale unit l (kWh);
: Monthly contracted electricity
output between power plant g and EVN, determined in the monthly electricity
market operation plan in accordance with Article 38 of this Circular (kWh);
Qptdk(l,M):
Forecast electricity output at the supply source of electricity wholesale unit l
in Month M (kWh).
- The contracted
electricity output for each trading interval allocated by EVN to an electricity
wholesale unit shall be determined using the following formula:
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Where:
i:
Trading interval i of the month;
I: Total number of trading intervals in the month;
Qc(l,i):
Contracted electricity output during trading interval i allocated by EVN to electricity
wholesale unit l (kWh);
Qc(l,M):
Contracted electricity output for Month M allocated by EVN to electricity
wholesale unit l (kWh);
Qptdk(l,i):
Forecast electricity output at the supply source of electricity wholesale unit l
during trading interval i (kWh).
Article
41. Review, approval, and announcement timeline for electricity market
operation plans for the following month
1. The electricity
market operation plan for the following month shall include input parameters
and calculation explanations as prescribed in Appendix I enclosed with this
Circular, with the following principal contents:
a) The water
value and optimal water level for each week of the following month of
hydropower plants in cascade hydropower groups and hydropower plants with
reservoirs having a regulating capacity of 2 days or more;
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c) The
average of the offer price caps of thermal generating units participating in
the electricity market;
d) The contracted
electricity output of power plants for each trading interval of the following
month;
dd) The
projected electricity generation output of power plants for each trading
interval of the following month;
e) The
percentage of electricity purchased at the spot electricity market price in
each month of the following year, applicable to electricity wholesale units
with respect to contract-allocated power plants, determined in accordance with
Clause 2 Article 98 of this Circular;
g) The contracted
electricity output for the subsequent 2 months, for coal-fired thermal power
plants, in the electricity market operation plans for January, April, July, and
October, and for the subsequent 5 months, for gas-fired thermal power plants,
in the electricity market operation plans for January and July.
2. Before
the 22nd day of each month, the power system and electricity market operation
unit shall solicit comments from EVN and electricity market participants on the
electricity market operation plan for the following month.
3. Before
the 23rd day of each month, EVN and electricity market participants shall
review and submit their written comments on the monthly electricity market
operation plan to the power system and electricity market operation unit.
4. Before
the 25th day of each month, the power system and electricity market operation
unit shall submit the monthly electricity market operation plan to the Electricity
Authority of Vietnam.
5. Before
the 28th day of each month, the Electricity Authority of Vietnam shall appraise
and approve the monthly electricity market operation plan.
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Article
42. Announcement of information on electricity market operation plans for the
following month
1. The
power system and electricity market operation unit shall announce the following
general information to electricity market participants:
a)
Forecast electricity load demand for the following month for the Northern,
Central, and Southern regions and for the entire national power system;
b) Total
forecast electricity load demand of electricity wholesale units for each trading
interval;
c) The
electricity import and export plan for the following month;
d) The
projected electricity output of each power plant for the following month;
dd) The
list of generating units eligible to provide secondary frequency control
service for the following month in accordance with the regulations on
electricity transmission systems, electricity distribution systems, and
electricity metering and the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system, both promulgated by the Ministry of Industry and Trade of
Vietnam;
e)
Warnings of any deterioration in the electricity supply adequacy of the power
system;
g)
Solutions to ensure the stable, safe, and reliable operation of the power
system.
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a) Weekly
reservoir water levels of hydropower plants for the following month;
b) The
percentage of electricity purchased at the spot electricity market price for
the following month, applicable to electricity wholesale units with respect to contract-allocated
power plants, determined in accordance with Clause 2 Article 98 of this
Circular;
c) The contracted
electricity output of generating units for each trading interval, as calculated
by the power system and electricity market operation unit;
d) The water
value of hydropower plants;
dd) The offer
price cap of thermal generating units for the following month;
e)
Thermal power plant classification results;
g) The
average of the offer price caps of thermal generating units participating in
the electricity market under the monthly electricity market operation plan;
h) The
generating unit dispatch plan for the following month;
i) The
upstream water level of hydropower reservoirs on the last day of the following
month;
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Section 3. OPERATION PLAN FOR THE FOLLOWING WEEK
Article
43. Preparation of operation plans for the following week
1. The
power system and electricity market operation unit shall collect input data for
calculating and preparing the electricity market operation plan for the
following week, as provided by electricity market participants and relevant
entities in accordance with Appendix I enclosed with this Circular.
2. The
power system and electricity market operation unit shall calculate and announce
the following results:
a)
Forecast electricity load demand, including the load demand of the national
power system and regional power systems;
b) Total
projected electricity generation output of each power plant for the following
week;
c) The water
value and projected output for each trading interval of strategic multi-purpose
hydropower plants;
d) The water
value of hydropower plants in cascade hydropower groups and hydropower plants
with reservoirs having a regulating capacity of 2 days or more;
dd) The
highest water value among hydropower plants participating in the electricity
market;
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g) The
weekly optimal water levels of hydropower reservoirs;
h) The
weekly reservoir limit water levels of hydropower reservoirs having a regulating
capacity of 2 days or more;
i) The
maintenance and repair schedules for power sources and the power grid for the
following week;
k) The
demand for secondary frequency control service and the list of generating units
expected to provide secondary frequency control service under the operation
plan for the following week;
l) The
projected operating capacity of Battery Energy Storage Systems (BESS) for each trading
interval.
Article
44. Offer price cap of hydropower plants
1. Except
for the cases prescribed in Clause 3 of this Article, the offer price cap of a
hydropower plant with a reservoir having a regulating capacity of 2 days or
more shall be determined based on the water value of such power plant for the
following week, as announced in accordance with Article 43 of this Circular,
specifically as follows:
a) The offer
price cap shall be the highest value of:
- 120% of
the water value of the hydropower plant;
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b) Each
month, the power system and electricity market operation unit shall announce to
hydropower plants the average of the offer price caps of thermal generating
units for the following month according to the same announcement schedule
applicable to the offer price caps of thermal generating units for the
following month.
2. Offer
price cap of hydropower plants in special cases
a) The offer
price cap of a hydropower plant in the cases prescribed in Points b and c of
this Clause shall be determined using the following formula:
Ptr = 1,2 x max (Pgtn ; PDOmax)
Where:
Ptr:
Offer price cap of the hydropower plant applicable in special cases (VND/kWh);
Pgtn: Water
value of the hydropower plant (VND/kWh);
PDOmax: Variable
cost of the most expensive DO oil-fired thermal generating unit in the power
system (VND/kWh).
b) Where
the reservoir water level of a hydropower plant is lower than the weekly reservoir
limit water level, the offer price cap applicable to such hydropower plant for
the following week shall be determined in accordance with Point a of this
Clause. Once the reservoir water level is no longer lower than the weekly reservoir
limit water level, the power plant shall resume application of the offer price
cap prescribed in Clause 1 of this Article from Tuesday of the following week.
Each month, the power system and electricity market operation unit shall
announce the variable cost of the most expensive DO oil-fired thermal
generating unit in the power system;
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4. Each
week, the power system and electricity market operation unit shall:
a)
Calculate the offer price caps of hydropower generating units of hydropower
plants participating in the electricity market in accordance with Clauses 1 and
2 of this Article;
b)
Announce the calculation results of the offer price cap for each hydropower
generating unit of hydropower plants participating in the electricity market
applicable to the following week, together with the input parameters used for
calculation, including the water value, the variable cost of the most expensive
DO oil-fired thermal generating unit in the power system, and the average of
the offer price caps of thermal generating units participating in the electricity
market under the monthly operation plan.
5. Hydropower
plants directly participating in the electricity market shall:
a) Submit
offers in compliance with the regulations on the offer price cap and offer
floor price;
b)
Satisfy downstream water-use demand constraints and other hydrological
constraints.
Article
45. Secondary frequency control service under operation plans for the following
week
1. The
power system and electricity market operation unit shall determine the demand
for secondary frequency control service of the power system for the following
week in accordance with the regulations on electricity transmission systems,
electricity distribution systems, and electricity metering and the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system, both promulgated by the
Ministry of Industry and Trade of Vietnam.
2. The
power system and electricity market operation unit shall select, prepare, and
announce the list of generating units of power plants expected to provide
secondary frequency control service for the following week. The selected
generating units shall provide secondary frequency control service at the
request of the power system and electricity market operation unit, and in
accordance with relevant laws.
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Chapter
V
OPERATION OF ELECTRICITY MARKET
Section 1. DAY-AHEAD ELECTRICITY MARKET OPERATION
Article
46. Information for day-ahead electricity market operation
Before
10:00 on Day D-1, the power system and electricity market operation unit shall
determine, calculate, and announce the following information:
1. The
forecast electricity load demand curves for Day D of the entire national power
system and the Northern, Central, and Southern regions.
2. The
projected or forecast dispatched capacity for each trading interval of the
following day of power plants indirectly participating in the electricity
market as prescribed in Clause 3 Article 4 of this Circular, rooftop solar
power sources, and power plants that do not directly submit offers in the electricity
market, taking into account take-or-pay obligations.
3. The
projected or forecast dispatched capacity for each trading interval of the
following day of the power plants prescribed in Article 11 of this Circular.
4. The
total projected gas consumption for the following day of gas-fired thermal
power plants using the same gas source.
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6. The
projected dispatched capacity of hydropower plants with reservoirs having a
regulating capacity of less than 2 days for each trading interval of the
following day.
7. The
projected operating capacity of Battery Energy Storage Systems (BESS).
Article
47. Price offers
1. A price
offer shall comply with the following principles:
a) It
shall comprise 10 pairs of offer prices (VND/kWh) and capacity levels (MW) for
the generating unit for each trading interval of Day D;
b) The
capacity specified in the price offer shall be the capacity measured at the
generator terminals;
c) The
capacity of each subsequent offer band shall not be lower than that of the
immediately preceding offer band. The minimum offer increment shall be 3 MW;
d) It
shall include information on the technical parameters of the generating unit,
including:
- The declared
capacity of the generating unit for Day D;
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- The
maximum ramp-up and ramp-down rates of the generating unit;
- Technical
constraints applicable to the simultaneous operation of generating units;
- The
fuel status of the thermal power plant;
- The
spill status of the hydropower reservoir.
dd) The declared
capacity of a generating unit in the offer for Day D shall not be lower than
the declared capacity for Day D-2 under the regulations on medium-term and
short-term electricity supply adequacy assessments prescribed in the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system promulgated by the Ministry
of Industry and Trade of Vietnam, except in the case of an emergency shutdown
for repair, which must be approved; a force majeure technical incident;
capacity derating due to a low reservoir water level; or cooperated offering by
hydropower plants in a cascade hydropower group to prevent spilling. The power
plant shall update its declared capacity when its available capacity decreases.
Where the start-up offer of a thermal generating unit is updated, the declared
capacity shall correspond to the capacity available under normal operating
conditions;
e) Under
normal conditions, the first capacity band in the price offer of a thermal generating
unit shall equal the minimum stable generation capacity of the generating unit.
The final capacity band shall equal the declared capacity. During the start-up
or shutdown of a thermal power plant, its price offer for the following trading
interval may be updated with a capacity lower than the minimum stable
generation capacity;
g) A
hydropower plant may offer 0 MW for its first capacity bands in each trading
interval. For a hydropower plant with a regulating capacity of 2 days or more,
the final capacity band shall equal the declared capacity. Where the water
level of the hydropower reservoir has fallen to the dead water level, the power
plant may adjust its declared capacity to 0 MW;
h) The
unit of the offer price shall be VND/kWh, with a minimum decimal precision of
0,1;
i) The
offer price shall be between the offer floor price and the offer price cap of
the generating unit and shall be non-decreasing as the offered capacity
increases.
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a) The
offer of a hydropower plant with a reservoir having a regulating capacity of
less than 2 days shall be made as follows:
- The
offer price shall be VND 0/kWh for all offered capacity bands;
- The
offered capacity shall equal the projected generation capacity of the
generating unit during the relevant trading interval. The generation unit
owning, managing, or operating a hydropower plant with a reservoir having a
regulating capacity of less than 2 days may submit a revised price offer,
increasing the offered capacity according to the actual hydrological conditions
of the power plant;
- A
hydropower plant with a reservoir having a regulating capacity of less than 2
days may submit a revised price offer for the following trading interval,
adjusting its offered capacity according to the actual hydrological conditions
of the power plant.
b) Where
the reservoir water level of a hydropower plant has remained below the
reservoir limit water level for 2 consecutive weeks; where the reservoir water
level has remained below the weekly reservoir limit water level for 1 week and
the regional energy reserve margin for that week is less than 5%; or where the
reservoir water level has remained below the weekly reservoir limit water level
for 1 week and is lower than the upper limit of the reservoir operating
water-level range for the dry season, if any, prescribed in the inter-reservoir
operating procedures, the price offer shall be made as follows:
- The offer
floor price shall be offered for the output corresponding to the lower of the
downstream water discharge requirement imposed by the competent state authority
and the discharge requirement under the inter-reservoir or single-reservoir
operating procedures, except where the relevant unit is located in an area
affected by storms or heavy rainfall, based on the assessment of the
hydrometeorological forecasting unit, or where the reservoir water level must
be lowered to ensure the flood-control storage level in accordance with the
inter-reservoir or single-reservoir operating procedures or at the request of a
competent state authority;
- The offer
price cap shall be offered for the remaining output. The applicable offer price
cap shall be determined in accordance with Point a Clause 2 Article 44 of this
Circular.
c) The
offer of a hydropower plant whose reservoir water level has remained below the
weekly reservoir limit water level for 1 week and is lower than the minimum
water level or the lower limit of the reservoir operating water-level range for
the dry season prescribed in the inter-reservoir operating procedures shall be
made by the offering unit according to the following principles:
- The
offer floor price shall be offered for the output corresponding to the lower of
the downstream water discharge requirement imposed by the competent state
authority and the discharge requirement under the inter-reservoir or
single-reservoir operating procedures, except where the relevant unit is
located in an area affected by storms or heavy rainfall, based on the
assessment of the hydrometeorological forecasting unit, or where the reservoir
water level must be lowered to ensure the flood-control storage level in
accordance with the inter-reservoir or single-reservoir operating procedures or
at the request of a competent state authority;
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- The
applicable offer price cap (Ptr) shall be determined using the
following formula:
Where:
: The minimum water level or the lower limit of the
reservoir operating water-level range for the dry season of the reservoir of
hydropower plant i, as prescribed in the inter-reservoir operating procedures,
at 24:00 on Sunday (m);
: The water level of the reservoir of hydropower plant i
at 24:00 on Sunday (m).
d) The
offer of a thermal generating unit during start-up and shutdown shall be made
as follows: the offered capacity may be lower than the minimum stable
generation capacity, and the same capacity level shall apply to all 10
offer-price pairs;
dd) The price
offer of a non-hydropower renewable energy power plant shall be made as
follows:
- The
offer price shall be VND 0/kWh for the entire offered capacity;
- The
offered capacity shall equal the forecast capacity of the power plant. The generation
unit shall submit the forecast capacity of the power plant for each trading
interval of the following day to the power system and electricity market
operation unit and comply with the regulations on forecasting the capacity and
electricity output of renewable energy sources under the regulations on
dispatching, operation, switching operations, incident handling, black start,
and restoration of the national power system promulgated by the Ministry of
Industry and Trade of Vietnam;
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Article
48. Intra-day price offers
1. The
offer prices specified in an intra-day price offer shall not be changed from
those specified in the day-ahead price offer.
2. The
capacity at the first offer level shall not be changed from that specified in
the day-ahead price offer, except in the cases where revision of a price offer
is permitted under Article 49 of this Circular. The capacity at the remaining
offer levels may be changed from that specified in the day-ahead price offer,
provided that the requirements of Article 47 of this Circular are complied
with.
Article
49. Revision of price offers
1. Cases
in which a price offer may be revised
A revised
price offer submitted by an offering unit shall apply in the following cases:
a) Where
a thermal generating unit is undergoing start-up, synchronization with the
grid, or shutdown, the offering unit for such thermal generating unit may
revise the offered capacity upward or downward and resubmit the price offer for
that generating unit;
b) Where
a thermal generating unit is synchronized with the grid earlier than scheduled
at the request of the power system and electricity market operation unit, the offering
unit may revise the declared capacity upward and resubmit the price offer for
that thermal generating unit;
c) Where
a generating unit experiences an incident resulting in shutdown or a reduction
in available capacity, or undergoes an unplanned repair approved by the power
system and electricity market operation unit in accordance with the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system promulgated by the Ministry
of Industry and Trade of Vietnam, the offering unit may revise the declared
capacity downward and resubmit the price offer for that generating unit;
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dd) For
hydropower plants with reservoirs having a regulating capacity of 2 days or
more, the offering unit may revise the price offer in the following cases:
- A downstream
water supply requirement or reservoir operation order of a competent state
authority is issued in writing after the close of offer submission;
- The
hydropower plant is required to make a regulated discharge, excluding
environmental flow discharge; the reservoir water level is higher than the
level prescribed in the inter-reservoir or single-reservoir operating
procedures; the reservoir reaches the spill threshold; or there is a risk that
the reservoir will be required to spill;
- The
hydropower plant is unable to satisfy the downstream water supply requirement
on Day D because a generating unit of the power plant experiences an incident
or a reduction in available capacity on Day D;
- The
hydropower plant is unable to satisfy the downstream water supply requirement
on Day D because an insufficient volume of its offers at the offer floor price
was dispatched during preceding trading intervals for downstream water supply;
- The
reservoir water level is below the dead water level, and the generating unit is
incapable of operation;
- A
hydropower plant required to apply a special price offer under Points b and c
Clause 2 Article 47 of this Circular has fully satisfied the downstream water
supply requirement for the day.
e) Where
a power plant is required to postpone or reschedule its repair at the request
of the power system and electricity market operation unit, completes its repair
earlier than the approved schedule, or places a generating unit on reserve at a
time different from that scheduled;
g) Non-hydropower
renewable energy power plants directly participating in the electricity market
may update their capacity in accordance with the selected forecast capacity of
the power system and electricity market operation unit.
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a) For
the cases prescribed in Points a, b, c, and e Clause 1 of this Article:
- A
revised price offer shall not change the offer prices specified in the day-ahead
price offer or intra-day price offer;
- In the
case prescribed in Point a Clause 1 of this Article, all offered capacity bands
in the revised price offer of the thermal generating unit shall be equal and
shall correspond to the projected generation capacity during synchronization
with the grid or shutdown;
- In the
case prescribed in Point b Clause 1 of this Article, the revised price offer
shall not change the capacity at capacity levels lower than or equal to the declared
capacity for the following trading interval, except where the technical
parameters specified in the offer cannot be satisfied;
- In the
case prescribed in Point c Clause 1 of this Article, the revised price offer
may reduce the declared capacity below the declared capacity for Day D-2;
- In the
case prescribed in Point e Clause 1 of this Article, the revised price offer
may adjust the declared capacity in accordance with the status of the
generating unit and the repair schedule.
b) For
the cases prescribed in Point dd Clause 1 of this Article:
- A
revised price offer shall not change the offer prices specified in the
day-ahead price offer or intra-day price offer;
- The generation
unit may change only the capacity levels of the first offered capacity bands to
satisfy the downstream water supply requirement for the operating day or to
prevent spilling. Where the reservoir water level is below the dead water level
and the generating unit is incapable of operation, the generation unit may
update the declared capacity in accordance with the status of the generating
unit;
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- The
revised price offer shall comply with Article 47 of this Circular.
3. The
offering unit may revise and resubmit the day-ahead price offer, intra-day
price offer, or price offer for the remaining trading intervals of Day D to the
power system and electricity market operation unit before the close of offer
submission.
4. Upon
receipt of a revised price offer from an offering unit, the power system and
electricity market operation unit shall, based on the actual conditions of the power
system, examine and confirm the validity of such revised price offer:
a) Where
the revised price offer is invalid, the power system and electricity market
operation unit shall notify the offering unit and the generation unit of the
reasons;
b) Where
the revised price offer is valid
- For
revised price offers that increase capacity, except for the cases prescribed in
Points d, dd, and g Clause 1 of this Article, the power system and electricity market
operation unit shall use such revised price offers in electricity market
operation where the announced day-ahead, intra-day, or
following-trading-interval schedule contains a capacity shortage warning, or
where necessary to ensure electricity supply;
- For the
remaining cases, the power system and electricity market operation unit shall
use such revised price offers in the course of electricity market operation.
Article
50. Offering by cascade hydropower groups
1. A cascade
hydropower group shall submit a single consolidated price offer for the entire
group and comply with the offer price limits prescribed in Clause 3 Article 15
of this Circular.
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3. The
representative offering unit shall comply with the offering regulations
applicable to all power plants within the cascade hydropower group.
4. Where
the power plants cannot agree on a representative offering unit and propose to
submit their own offers, the respective generation units shall submit offers
independently.
5. The water
value of a cascade hydropower group shall be the water value of the largest
hydropower reservoir in that cascade. The power system and electricity market
operation unit shall identify the hydropower reservoir to be used for
calculating the water value of the cascade hydropower group concurrently with
the classification of hydropower plants under Article 20 of this Circular.
6. Where
a cascade hydropower group includes a strategic multi-purpose hydropower plant:
a) The
power system and electricity market operation unit shall announce the
generation output of each power plant in the cascade hydropower group for each trading
interval of the following week in accordance with Clause 2 Article 43 of this
Circular;
b) Where
the announced output of the strategic multi-purpose hydropower plant within the
group is adjusted in accordance with Article 66 of this Circular, the power
system and electricity market operation unit shall correspondingly adjust the
announced output of downstream power plants in the cascade.
Article
51. Submission of price offers
1. Before
11:30 on Day D-1, the offering unit shall submit its price offer for Day D.
2. For
each intra-day electricity market operation time frame, the offering unit shall
submit its intra-day price offer at least 8 hours before the commencement of
such time frame.
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4. Offering
units shall register their email addresses and contact details with the power system
and electricity market operation unit.
Article
52. Verification of validity of price offers
1. Before
11:00 on Day D-1, the power system and electricity market operation unit shall
verify the validity of the price offers received from offering units in
accordance with Article 51 of this Circular. Where an offering unit submits
multiple price offers, only the last received price offer shall be considered.
2. No
later than 30 minutes before the close of intra-day offer submission, the power
system and electricity market operation unit shall verify the validity of the intra-day
price offers received from offering units in accordance with Article 51 of this
Circular. Where an offering unit submits multiple price offers, only the last
received price offer shall be considered.
3. Where
a price offer is invalid, the power system and electricity market operation
unit shall notify the offering unit and request it to resubmit the price offer
no later than the close of offer submission.
4. Upon
receipt of a notice from the power system and electricity market operation unit
that its price offer is invalid, the offering unit shall revise and resubmit
the price offer before the close of offer submission.
Article
53. Scheduling offers
1. After
the close of offer submission, the power system and electricity market
operation unit shall verify the validity of the last received price offers
submitted in accordance with Article 51 of this Circular. The last valid price
offer shall be used as the scheduling offer for day-ahead dispatch scheduling.
2. After
the close of intra-day offer submission, the power system and electricity
market operation unit shall verify the validity of the last received intra-day
price offers submitted in accordance with Article 51 of this Circular. The last
valid price offer shall be used as the intra-day scheduling offer for intra-day
rolling dispatch scheduling.
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4. Where
the power system and electricity market operation unit does not receive a price
offer for a generating unit, or where the default offer is inconsistent with
the status of the generating unit, the default offers of power plants shall be
determined as follows:
a) For a
thermal power plant, the default offer shall be prepared based on the available
capacity and the offer price cap of the generating unit at the time of
application;
b) For a
hydropower plant or cascade hydropower group, the default offer shall be
determined as follows:
- The offer
floor price shall apply to the output corresponding to the downstream water supply
requirement;
- The offer
price cap of the generating unit prescribed in Article 44 of this Circular
shall apply to the remaining output.
c) For a
hydropower plant with a reservoir having a regulating capacity of more than 2
days that is required to apply a price offer in special cases, the offer prices
and offered output in its default offer shall comply with Points b and c Clause
2 Article 47 of this Circular;
d) For
wind power, solar power, biomass power, and small hydropower plants
participating in the electricity market, the default offer shall have an offer
price of VND 0/kWh for all offer bands and an offered capacity equal to the
forecast capacity.
5. Simulation
of thermal power plants that do not directly submit day-ahead offers
a) A generation
unit owning power plants that do not directly participate in offer submission
shall declare their capacity on Day D-2 in accordance with the regulations on
medium-term and short-term electricity supply adequacy assessments under the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system promulgated by the Ministry
of Industry and Trade of Vietnam;
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- Where a
generating unit is dispatched according to the results announced under Clause 2
Article 46 of this Circular, it shall be simulated at the offer floor price for
the portion corresponding to its minimum stable generation capacity and at its variable
price for the remaining available capacity;
- Where a
generating unit is not scheduled according to the results announced under
Clause 2 Article 46 of this Circular, it shall be simulated at its variable
price for its entire available capacity;
- The
ramp-up and ramp-down rates used in the simulation shall comply with the power
purchase agreement and the current condition of the electricity market
infrastructure. Where the electricity market infrastructure is not yet capable
of accommodating such rates, the ramp-up and ramp-down rates applicable at an
85% load level and consistent with the power purchase agreement shall be used.
c) Where
a generating unit re-declares its available capacity, the power system and electricity
market operation unit shall update the simulation in accordance with Point b
Clause 5 of this Article.
Article
54. Data used for day-ahead dispatch scheduling
The power
system and electricity market operation unit shall use the following data for
day-ahead dispatch scheduling:
1. Daily
load curves of the entire national power system and the Northern, Central, and
Southern regions.
2. The scheduling
offers of offering units.
3. Simulation
results for generating units of thermal power plants that do not directly
submit offers, concurrently with power plants having submitted offers, in
accordance with Clause 5 Article 53 of this Circular. For rooftop solar power
sources and other power plants that do not directly submit offers, the
projected dispatched capacity for each trading interval prescribed in Clause 2
Article 46 of this Circular shall be used.
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5. Day-ahead
forecast capacity of non-hydropower renewable energy power plants.
6. Electricity
export and import output prescribed in Articles 74 and 75 of this Circular.
7. Capacity
of generating units of power plants providing auxiliary services.
8. Capacity
requirement for secondary frequency control reserve service.
9. Information
on the capability of generating units to provide secondary frequency control
reserve service.
10. Maintenance
and repair schedules for the transmission grid and generating units approved by
the power system and electricity market operation unit.
11. Approved
generating unit testing schedules.
12. Results
of the short-term electricity supply adequacy assessment for Day D in
accordance with the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system promulgated by the Ministry of Industry and Trade of Vietnam.
13. Updated
information on the availability of the transmission grid and generating units
obtained from the SCADA system or provided by the electricity transmission unit
and generation units.
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15. The
projected operating capacity of Battery Energy Storage Systems (BESS).
16. Fuel
supply capability.
Article
55. Day-ahead dispatch scheduling
The power
system and electricity market operation unit shall prepare the day-ahead
dispatch schedule in accordance with Appendix II enclosed with this Circular.
The day-ahead dispatch schedule shall include the following principal contents:
1. The unconstrained
dispatch schedule, including:
a) The
projected market energy price for each trading interval of the following day;
b) The
dispatch order of generating units for each trading interval of the following
day.
2. The constrained
dispatch schedule, including:
a) The
projected dispatch profile of each generating unit for each trading interval of
the following day and the regional marginal price for each trading interval of
the following day;
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c) The
projected operating mode and network configuration of the power system for each
trading interval of the following day;
d)
Warning information, if any;
dd) The
capacity reserved by generating units for secondary frequency control reserve
service.
3. Dispatch
scheduling in the event of an overload or generation surplus: the power system
and electricity market operation unit shall perform the relevant calculations
in accordance with Article 18 of this Circular.
Article
56. Announcement of day-ahead dispatch schedules
Before
16:00 each day, the power system and electricity market operation unit shall
announce the following information contained in the day-ahead dispatch schedule:
1. The
projected dispatched capacity, including capacity dispatched for secondary
frequency control reserve service, of generating units for each trading
interval of the following day, and the regional marginal price for each trading
interval of the following day.
2. The
projected market energy price for each trading interval of the following day
applicable to generation units and electricity wholesale units.
3. The
list of generating units expected to increase or decrease their generation
capacity during each trading interval of the following day.
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a) The trading
intervals in which a capacity shortage is expected;
b) The
amount of the capacity shortage;
c)
Electricity supply adequacy constraints that may not be satisfied.
5. Information
on any surplus generation capacity warning for the following day, including:
a) The trading
intervals in which surplus generation capacity is expected;
b) The
generating units expected to cease generation.
6. Information
on the provision of secondary frequency control service:
a) The
capacity demand of the power system for secondary frequency control service;
b) The
list of generating units providing secondary frequency control service;
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7. Projected
information on fuel shortages affecting thermal power plants of direct trading
generation units during the following trading intervals.
8. Technical
constraints applicable to the operation of power sources and the power grid.
9. Intervention
measures taken by the power system and electricity market operation unit to
ensure electricity supply.
10. Adjustments
or interventions made by the power system and electricity market operation unit
to the price offers of generation units in accordance with regulations.
11. Before
17:00 each day, based on the projected dispatch profile announced by the power system
and electricity market operation unit, the dispatch authority having control
over the power plants prescribed in Point b Clause 1 Article 4 of this Circular
shall determine and announce:
a) The
dispatched capacity of each generating unit for each trading interval of the
following day based on the offers submitted by the relevant units, taking into
account technical limitations of the power grid;
b)
Technical constraints affecting the generation capacity of generating units.
Article
57. Synchronization of generating units with the grid
1. For a slow-start
generating unit, the generation unit shall make the generating unit ready for
synchronization with the grid in accordance with the day-ahead dispatch
schedule announced by the power system and electricity market operation unit.
Where the start-up time of the generating unit exceeds 24 hours, the generation
unit shall synchronize the generating unit with the grid based on the results
of the short-term electricity supply adequacy assessment announced by the power
system and electricity market operation unit.
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3. During
the synchronization of thermal generating units with the grid, the generation
unit shall update the capacity for each trading interval in the price offer of
the generating unit and submit it to the power system and electricity market
operation unit in accordance with Article 49 of this Circular.
Article
58. Handling of capacity shortage warnings
1. The
power system and electricity market operation unit may revise the declared
capacity of strategic multi-purpose hydropower plants in accordance with Clause
2 Article 66 of this Circular and adjust the dispatched capacity of gas-fired
thermal power plants through gas line-packing measures to prioritize dispatch
of the highest possible capacity of such gas-fired thermal power plants during
peak-load periods of the power system.
2. The
power system and electricity market operation unit shall adjust and dispatch
additional available capacity from Battery Energy Storage Systems (BESS).
3. The
power system and electricity market operation unit shall use an offer that
increases capacity as the scheduling offer for preparing the dispatch schedule
for the following trading interval and calculating the electricity market price.
4. The
power system and electricity market operation unit shall start up additional slow-start
generating units and generating units providing auxiliary services.
5. The
power system and electricity market operation unit shall announce on the
Electricity Market Web Portal the expected capacity shortage and its expected
duration.
Article
59. Handling of warnings of insufficient capacity for secondary frequency
control service
1. The
power system and electricity market operation unit shall prepare the dispatch schedule
in a manner that satisfies the requirements for secondary frequency control
service, except where there is insufficient capacity for such service.
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3. The
power system and electricity market operation unit may revise the declared
capacity of power plants indirectly participating in the electricity market as
prescribed in Article 46 of this Circular to satisfy the requirements for secondary
frequency control service.
4. The
power system and electricity market operation unit may adjust and dispatch
additional available capacity from Battery Energy Storage Systems (BESS).
Section 2. INTRA-DAY ELECTRICITY MARKET OPERATION
Article
60. Data used for intra-day dispatch scheduling
The power
system and electricity market operation unit shall use the following data for
intra-day dispatch scheduling:
1. Load
curves from the calculation interval to the end of the day for the entire national
power system and the Northern, Central, and Southern regions.
2. Grid
synchronization and shutdown plans for slow-start generating units in
accordance with the announced day-ahead dispatch schedule.
3. The intra-day
scheduling offers of offering units.
4. Simulation
results for generating units of thermal power plants that do not directly
submit offers, concurrently with power plants having submitted offers, in
accordance with Clause 5 Article 53 of this Circular.
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6. Announced
output adjusted to reflect the actual operating conditions of the power plants
and the power system for power plants that autonomously control active power
generation in accordance with the regulations on dispatching, operation,
switching operations, incident handling, black start, and restoration of the
national power system, and small hydropower plants with reservoirs having a
regulating capacity of less than 2 days that submit offers in the electricity
market.
7. Forecast
capacity from the calculation interval to the end of the day of non-hydropower
renewable energy power plants.
8. Electricity
export and import output prescribed in Articles 74 and 75 of this Circular.
9. Capacity
of generating units of power plants providing auxiliary services.
10. Capacity
requirement for secondary frequency control reserve service.
11. Information
on the capability of generating units to provide secondary frequency control
reserve service.
12. Maintenance
and repair schedules for the transmission grid and generating units approved by
the power system and electricity market operation unit.
13. Approved
generating unit testing schedules.
14. Results
of the short-term electricity supply adequacy assessment for Day D in
accordance with the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system promulgated by the Ministry of Industry and Trade of Vietnam.
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16. Take-or-pay
obligations.
17. Hydrological
parameters of hydropower reservoirs.
18. Parameters
of Battery Energy Storage Systems (BESS).
19. Fuel
supply capability.
Article
61. Intra-day dispatch scheduling
The power
system and electricity market operation unit shall prepare dispatch schedules
for intra-day operation time frames. The intra-day dispatch schedule shall
include:
1. The
unconstrained dispatch schedule, including:
a) The
projected market energy price for each remaining trading interval of Day D;
b) The
dispatch order of generating units for each remaining trading interval of Day D.
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a) The
projected dispatch profile of each generating unit for each remaining trading
interval of Day D, and the regional marginal price for each remaining trading
interval of Day D;
b)
Warning information, if any;
c) The
capacity reserved by generating units for secondary frequency control reserve
service.
3. Dispatch
scheduling in the event of an overload or surplus generation: the power system
and electricity market operation unit shall comply with Article 18 of this
Circular.
Article
62. Announcement of intra-day dispatch schedules
No later
than 2 hours before the commencement of an operation time frame, the power system
and electricity market operation unit shall announce the following information
contained in the intra-day dispatch schedule:
1. The
projected dispatched capacity, including capacity dispatched for secondary
frequency control reserve service, of generating units for each trading interval
within the operation time frame, and the regional marginal price for each trading
interval within such operation time frame.
2. The
projected market energy price for each trading interval within the operation
time frame applicable to generation units and the electricity wholesale unit.
3. The
list of generating units expected to increase or decrease their generation
capacity during each trading interval within the operation time frame.
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a) The
trading intervals in which a capacity shortage is expected;
b) The
amount of the capacity shortage;
c)
Electricity supply adequacy constraints that may not be satisfied.
5. Information
on any surplus generation capacity warning for the trading intervals within the
operation time frame, including:
a) The
trading intervals in which surplus generation capacity is expected;
b) The
generating units expected to cease generation.
6. Information
on the provision of secondary frequency control service:
a) The
capacity demand of the power system for secondary frequency control service;
b) The
list of generating units providing secondary frequency control service;
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7. Technical
constraints applicable to the operation of power sources and the power grid.
8. Intervention
measures taken by the power system and electricity market operation unit to
ensure electricity supply.
9. Adjustments
or interventions made by the power system and electricity market operation unit
to the price offers of generation units in accordance with regulations.
10. No
later than 1 hour before the commencement of the operation time frame, the
dispatch authorities having control over the power plants prescribed in Point b
Clause 1 Article 4 of this Circular shall determine and announce:
a) The
dispatched capacity of each generating unit for each intra-day trading interval,
based on the offers submitted by the relevant units and taking into account
technical limitations of the power grid;
b)
Technical constraints affecting the generation capacity of generating units.
Article
63. Handling of capacity shortage warnings
1. The
power system and electricity market operation unit may revise the declared
capacity of strategic multi-purpose hydropower plants in accordance with Clause
2 Article 66 of this Circular.
2. The
power system and electricity market operation unit shall adjust and dispatch
additional available capacity from Battery Energy Storage Systems (BESS).
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4. The
power system and electricity market operation unit shall start up additional
generating units providing auxiliary services.
5. The
power system and electricity market operation unit shall announce on the
Electricity Market Web Portal the expected capacity shortage and its expected
duration.
Article
64. Handling of warnings of insufficient capacity for secondary frequency
control service
1. The
power system and electricity market operation unit shall prepare the dispatch
schedule in a manner that satisfies the requirements for secondary frequency
control service, except where there is insufficient capacity for such service.
2. The
power system and electricity market operation unit may use an offer that
increases capacity as the intra-day scheduling offer for preparing the intra-day
dispatch schedule.
3. The
power system and electricity market operation unit may revise the declared
capacity of power plants indirectly participating in the electricity market as
prescribed in Article 46 of this Circular to satisfy the requirements for
secondary frequency control service.
4. The
power system and electricity market operation unit may adjust and dispatch
additional available capacity from Battery Energy Storage Systems (BESS).
Section 3. ELECTRICITY MARKET OPERATION FOR THE FOLLOWING
TRADING INTERVAL
Article
65. Data used for dispatch scheduling for the following trading interval
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1. Forecast
load curves of the entire national power system and the Northern, Central, and
Southern regions for the following trading interval and the subsequent 7 trading
intervals.
2. Grid
synchronization and shutdown plans for slow-start generating units in
accordance with the announced day-ahead dispatch schedule or intra-day dispatch
schedule.
3. The scheduling
offers of offering units for the following trading interval.
4. The declared
capacity under the day-ahead dispatch schedule of power plants that do not
directly submit offers in the electricity market, as announced by the power system
and electricity market operation unit in accordance with Article 56 or Article
62 of this Circular.
5. Simulation
results for generating units of thermal power plants that do not directly
submit offers, concurrently with power plants having submitted offers, in
accordance with Clause 5 Article 53 of this Circular. For other power plants
that do not directly submit offers, the declared capacity under the day-ahead
dispatch schedule or intra-day dispatch schedule prescribed in Article 56 or
Article 62 of this Circular shall be used.
6. Forecast
capacity for the following trading interval and the subsequent 7 trading
intervals of non-hydropower renewable energy power plants and power plants
operating under the avoided-cost mechanism.
7. The
capacity demand of the power system for secondary frequency control service and
the capability of generating units providing such service to provide secondary
frequency control service.
8. The
capacity of fast-start reserve service and must-run service required to ensure
electricity supply for the following trading interval.
9. The
updated list of generating units providing secondary frequency control service.
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11. Other
electricity supply adequacy constraints and technical requirements of the power
system.
12. Maintenance,
repair, and testing schedules for generating units approved by the power system
and electricity market operation unit.
13. Electricity
import output.
14. Take-or-pay
obligations.
Article
66. Adjustment of announced output of power plants
Before
preparing the dispatch schedule for the following trading interval, the power system
and electricity market operation unit may adjust the output for the following trading
interval of strategic multi-purpose hydropower plants and power plants that
autonomously control active power generation in accordance with the regulations
on dispatching, operation, switching operations, incident handling, black
start, and restoration of the national power system promulgated by the Ministry
of Industry and Trade of Vietnam, as announced under Clause 1 Article 56 of
this Circular.
1. The
output of a strategic multi-purpose hydropower plant for the following trading
interval may be adjusted in any of the following cases:
a)
Abnormal fluctuations in hydrological conditions, renewable energy forecasts,
or load demand;
b) A
capacity shortage warning under the day-ahead dispatch schedule;
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d)
Surplus generation capacity or a capacity shortage arises during the
calculation of the dispatch schedule for the following trading interval.
2. In the
cases prescribed in Points a and b Clause 1 of this Article, the adjustment
range for the announced output of strategic multi-purpose hydropower plants
shall be ±25% of the total installed capacity of such plants in the power
system, excluding capacity reserved for secondary frequency control service.
3. For
power plants that autonomously control active power generation in accordance
with the regulations on dispatching, operation, switching operations, incident
handling, black start, and restoration of the national power system promulgated
by the Ministry of Industry and Trade of Vietnam, and rooftop solar power
sources, the announced output shall be adjusted to reflect the actual operating
conditions of the power plants and the power system.
Article
67. Dispatch scheduling for the following trading interval
1. The
power system and electricity market operation unit shall prepare the dispatch
schedule for generating units for the following trading interval using the constrained
scheduling method and the unconstrained scheduling method prescribed in
Appendix II enclosed with this Circular.
2. Dispatch
scheduling for the following trading interval in the event of a capacity
shortage:
a) The
power system and electricity market operation unit shall schedule generating
units according to the following principles:
- Use
offers that increase capacity;
- Adjust
and dispatch additional available capacity from Battery Energy Storage Systems
(BESS);
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- Dispatch
thermal power plants indirectly participating in the electricity market at
their variable prices;
- Dispatch
generating units providing fast-start reserve service to ensure electricity
supply;
- Dispatch
hydropower plants indirectly participating in the electricity market in
descending order of the ratio of remaining reservoir volume to useful reservoir
volume;
- Dispatch
generating units providing must-run service to ensure electricity supply;
- Reduce
the capacity reserved for secondary frequency control service to the minimum
permissible level.
b) The
power system and electricity market operation unit shall examine and determine
the amount of load expected to be shed to ensure electricity supply.
3. Dispatch
scheduling for the following trading interval in the event of an overload or
surplus generation: the power system and electricity market operation unit
shall adjust the dispatch schedule for the following trading interval by
applying the measures prescribed in Article 18 of this Circular.
4. The
power system and electricity market operation unit shall prepare the dispatch
schedule for the following trading interval in a manner that satisfies the
constraints relating to the demand for secondary frequency control service.
5. Dispatch
scheduling for the following trading interval in the event of insufficient
capacity for secondary frequency control service:
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b) The
power system and electricity market operation unit may use an offer that
increases capacity as the scheduling offer for preparing the dispatch schedule
for the following trading interval;
c) The
power system and electricity market operation unit may revise the declared
capacity, as prescribed in Article 56 of this Circular, of power plants
indirectly participating in the electricity market to satisfy the requirements
for secondary frequency control service;
d) The
power system and electricity market operation unit may adjust and dispatch
additional available capacity from Battery Energy Storage Systems (BESS).
Article
68. Announcement of dispatch schedules for the following trading interval
The power
system and electricity market operation unit shall announce the dispatch
schedule for the following trading interval 10 minutes before the commencement
of that trading interval, including the following information:
1. The
forecast load for the following trading interval of the entire national power
system and the Northern, Central, and Southern regions.
2. The
dispatch schedules of generating units and the regional marginal prices for the
Northern, Central, and Southern regions for the following trading interval and
the subsequent 7 trading intervals, prepared in accordance with Article 67 of
this Circular.
3. The
projected market price for each trading interval of the following day
applicable to generation units and the electricity wholesale unit.
4. Measures
taken by the power system and electricity market operation unit in the event of
a capacity shortage or surplus generation capacity.
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6. Information
on adjustments to the dispatched capacity of hydropower plants indirectly
participating in the electricity market, if any.
7. The
projected load-shedding schedule, if any.
8. Information
on the provision of secondary frequency control service:
a) The
capacity demand of the power system for secondary frequency control service;
b) The
list of generating units selected to provide secondary frequency control
service;
c) The
capacity reserved for secondary frequency control service by each generating
unit on the list prescribed in Point b of this Clause.
9. Technical
constraints applicable to power sources and the power grid during the following
trading interval.
Section 4. REAL-TIME OPERATION
Article
69. Real-time power system dispatch
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2. The
dispatch authority having control over the power plants prescribed in Point b
Clause 1 Article 4 of this Circular shall operate such power plants based on
the announced dispatch schedule for the following trading interval and report
to the power system and electricity market operation unit upon completion.
3. Generation
units shall comply with dispatch instructions issued by the power system and
electricity market operation unit and the dispatch authority having control
over them.
4. A generation
unit owning a hydropower plant shall comply with the weekly water level limits
of the hydropower plant calculated and announced by the power system and
electricity market operation unit in accordance with Clause 2 Article 43 of
this Circular.
Article
70. Regulations applicable where reservoirs of hydropower plants are below
weekly water level limits
1. The power
system and electricity market operation unit shall issue a warning to a
hydropower plant whose reservoir water level is below the weekly water level
limit. The generation unit shall adjust its offer prices for the following days
to ensure that the reservoir water level is not lower than the weekly water
level limit for the following week.
2. In any
of the following cases, commencing at 00:00 on Tuesday of the following week,
the power system and electricity market operation unit shall schedule the relevant
hydropower plant based on the default offer prescribed in Points b and c Clause
2 Article 47 of this Circular to restore the reservoir water level to the
weekly water level limit: the reservoir of the hydropower plant has remained
below the weekly water level limit for 2 consecutive weeks; the hydropower
plant has remained below the weekly water level limit for 1 week and the
regional energy reserve ratio for that week is less than 5%; the hydropower
plant has remained below the weekly water level limit for 1 week and is below
the upper limit of the water-level range for reservoir operation during the dry
season, if any, prescribed in the inter-reservoir operating procedures; the
hydropower plant has remained below the weekly water level limit for 1 week and
is below the minimum water level or the lower limit of the water-level range
for reservoir operation during the dry season prescribed in the inter-reservoir
operating procedures.
3. Once
the reservoir water level is no longer below the weekly water level limit, the
hydropower plant shall resume submitting price offers in the following week.
4. Before
10:00 every Monday, the power system and electricity market operation unit
shall notify the generation unit and the electricity purchasing unit of dispatch
scheduling commencing on Tuesday in the following cases:
a) The
hydropower plant is below the weekly reservoir water level limit for the first
week or for the second week;
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c) The
hydropower plant has remained below the weekly water level limit for 1 week and
is below the upper limit of the water-level range for reservoir operation
during the dry season, if any, prescribed in the inter-reservoir operating
procedures;
d) The
hydropower plant has remained below the weekly water level limit for 1 week and
is below the minimum water level or the lower limit of the water-level range
for reservoir operation during the dry season prescribed in the inter-reservoir
operating procedures.
Article
71. Intervention in electricity market
1. The
power system and electricity market operation unit may intervene in the electricity
market in any of the following cases:
a) The power
system is operating under an emergency operating condition prescribed in the regulations
on electricity transmission systems, electricity distribution systems, and
electricity metering and the regulations on dispatching, operation, switching
operations, incident handling, black start, and restoration of the national
power system promulgated by the Ministry of Industry and Trade of Vietnam;
b)
Circumstances arise in which electricity supply cannot be ensured, based on the
electricity supply adequacy assessment conducted by the power system and
electricity market operation unit in accordance with the regulations on
dispatching, operation, switching operations, incident handling, black start,
and restoration of the national power system promulgated by the Ministry of
Industry and Trade of Vietnam;
c) A
dispatch schedule for the following trading interval cannot be produced by the
commencement of that trading interval.
2. Where
intervention in the electricity market occurs in the case prescribed in Point b
Clause 1 of this Article, the power system and electricity market operation
unit may adjust the dispatch profiles of power plants to ensure electricity
supply. The power system and electricity market operation unit shall report the
following information to the Ministry of Industry and Trade of Vietnam and the Electricity
Authority of Vietnam:
a) The
expected commencement and ending times;
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c)
Outstanding issues or issues arising, if any.
3. During
intervention in the electricity market, dispatched power sources shall satisfy
the technical constraints necessary for the safe, stable, and reliable
operation of the power system.
4. In the
event of intervention in the electricity market, the power system and
electricity market operation unit shall dispatch generating units to achieve
the following objectives in order of priority:
a)
Maintaining the balance between generation capacity and load;
b)
Satisfying the requirements for secondary frequency control service;
c)
Satisfying voltage quality requirements;
d) Maintaining
the minimum generation configuration necessary to ensure the stability and
inertia of the power system.
5. Announcement
of information on intervention in the electricity market
a) When
intervening in the electricity market, the power system and electricity market
operation unit shall announce the following information:
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- The trading
intervals during which intervention in the electricity market is expected.
b) Within
24 hours after the intervention in the electricity market ends, the power system
and electricity market operation unit shall announce the following information:
- The
reasons for the intervention in the electricity market;
- The trading
intervals during which the electricity market was subject to intervention;
- The
measures applied by the power system and electricity market operation unit to
intervene in the electricity market.
Article
72. Suspension of spot electricity market
1. The spot
electricity market shall be suspended in any of the following cases:
a) An
emergency arises due to a natural disaster or national defense and security
requirements;
b) The
power system and electricity market operation unit requests suspension of the spot
electricity market in any of the following cases:
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- The
power system operates under a supply-demand imbalance, where the total available
capacity of power plants in the power system is lower than the forecast load,
and the power system and electricity market operation unit must implement
electricity supply curtailment measures to ensure the safe operation of the
system for 48 consecutive trading intervals;
- The
safe and continuous operation of the electricity market cannot be ensured.
c) Other
cases at the request of a competent authority.
2. The
Ministry of Industry and Trade of Vietnam shall consider and decide on the
suspension of the spot electricity market in the cases prescribed in Points a
and b Clause 1 of this Article and notify the power system and electricity
market operation unit thereof.
3. The
power system and electricity market operation unit shall notify electricity
market participants of the decision of the Ministry of Industry and Trade of
Vietnam to suspend the spot electricity market.
4. Operation
of the power system during the suspension of the spot electricity market
a) The
power system and electricity market operation unit shall dispatch and operate
the power system according to the following principles:
- Ensuring
the safe, stable, and reliable operation of the system at the lowest
electricity purchase cost for the entire system;
- Ensuring
compliance with output agreements under electricity export and import contracts
and take-or-pay obligations;
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b) Generation
units, the electricity transmission unit, and other relevant units shall comply
with dispatch instructions issued by the power system and electricity market
operation unit.
Article
73. Restoration of spot electricity market
1. Operation
of the spot electricity market shall be restored when the following conditions
are satisfied:
a) The
causes leading to the suspension of the spot electricity market have been
remedied;
b) The
power system and electricity market operation unit confirms that the spot
electricity market is capable of resuming operation.
2. The
Ministry of Industry and Trade of Vietnam shall consider and decide on the
restoration of the spot electricity market and notify the power system and
electricity market operation unit thereof.
3. The
power system and electricity market operation unit shall notify electricity
market participants of the decision of the Ministry of Industry and Trade of
Vietnam to restore the spot electricity market.
Section 5. ELECTRICITY EXPORTS AND IMPORTS IN ELECTRICITY
MARKET OPERATION
Article
74. Treatment of exported electricity in dispatch scheduling
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2. Exported
electricity output shall be treated as load at the export point and used for
calculating the forecast electricity load demand of the system for day-ahead
dispatch scheduling and dispatch scheduling for the following trading interval.
Article
75. Treatment of imported electricity in dispatch scheduling
1. Before
10:00 on Day D-1, the power system and electricity market operation unit shall
announce the projected imported electricity output for each trading interval of
Day D.
2. For
dispatch scheduling purposes, imported electricity output shall be treated as a
must-run source with a profile announced in advance for the following day.
Article
76. Payment for exported and imported electricity
Imported
or exported electricity shall be paid for in accordance with the relevant
import or export contract concluded between the parties.
Chapter
VI
ELECTRICITY METERING IN ELECTRICITY MARKET
Article
77. Boundary metering locations in wholesale electricity market
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2. Each
boundary metering location in the wholesale electricity market shall be
assigned a separate identifier in the database of the electricity metering data
management system in accordance with uniform regulations applicable to electricity
market participants, including:
a) A boundary
metering location for electricity delivery and receipt between a power plant
and the transmission grid;
b) A
boundary metering location for the delivery and receipt of imported or exported
electricity between the relevant connection and the transmission grid or
distribution grid;
c) A
boundary metering location for electricity delivery and receipt between the transmission
grid and a distribution grid;
d) A
boundary metering location for electricity delivery and receipt between a power
plant and a distribution grid;
dd) A
boundary metering location for electricity delivery and receipt on a
distribution grid between electricity wholesale units.
Article
78. Electricity metering systems and systems for collecting, processing, and
storing metering data
1. Electricity
metering systems and systems for collecting, processing, and storing
electricity metering data shall be designed in accordance with the boundary
metering locations in the wholesale electricity market prescribed in Article 77
of this Circular.
2. Detailed
requirements concerning minimum configuration, technical specifications, time
synchronization, sealing and lead sealing, security, operation and maintenance,
acceptance testing, handling of metering system incidents, verification, and
auditing shall comply with the regulations on electricity transmission systems,
electricity distribution systems, and electricity metering promulgated by the
Ministry of Industry and Trade of Vietnam.
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Article
79. Responsibilities for collecting and managing metering data in electricity
market
1. The
power system and electricity market operation unit shall fully collect metering
data at the delivery and receipt boundary metering locations prescribed in
Clause 2 Article 77 of this Circular. For boundary metering locations between
power plants not participating in the electricity market and the distribution
grid, collection shall be carried out in accordance with Clause 5 of this
Article. Metering data collected and announced by the power system and
electricity market operation unit shall be the data given priority for use in
calculations and payments in the electricity market.
The power
system and electricity market operation unit shall transmit to the shared
metering data repository of EVN the metering data collected at the delivery and
receipt boundary metering locations prescribed in Points a, b, and d Clause 2
Article 77 of this Circular and Point a Clause 5 of this Article.
2. Except
for delivery and receipt metering locations connected to power plants, the electricity
transmission unit shall collect delivery and receipt metering data within its
management scope and transmit such data to the shared metering data repository
of EVN and the power system and electricity market operation unit.
3. An electricity
wholesale unit shall collect delivery and receipt metering data within its
management scope, including the provision of rooftop solar power data, and
transmit such data to the shared metering data repository of EVN and the power system
and electricity market operation unit.
4. Power
plants directly participating in the electricity market shall collect metering
data within their management scope and transmit such data to the power system
and electricity market operation unit for use as backup data, for comparison
and reconciliation with the data set directly collected by the power system and
electricity market operation unit, and for confirmation of the official
metering data used for calculations and payments in the electricity market.
5. Other
power plants that do not participate in the competitive wholesale electricity
market:
a) For a
renewable energy power plant that has entered into a contract with EVN, the
power system and electricity market operation unit shall directly collect the
metering data;
b) For a
small hydropower plant, the electricity purchasing unit shall collect metering
data from the power plant within its management scope and transmit such data to
the power system and electricity market operation unit;
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6. Where
a delivery and receipt boundary metering location or the method of metering
electricity delivered and received at such boundary is changed within its
management scope, the generation unit, electricity transmission unit, or electricity
purchasing unit, as applicable, shall promptly notify the relevant parties of
and update them on such change for the collection and transmission of
electricity metering data to the power system and electricity market operation
unit.
7. Before
16:00 on the first day of each month, the power system and electricity market
operation unit shall announce meter readings at the delivery and receipt
boundary metering locations prescribed in Clause 2 Article 77 of this Circular
and Point a Clause 5 of this Article.
Article
80. Storage of metering data
The power
system and electricity market operation unit and units participating in the
competitive wholesale electricity market as prescribed in Article 2 of this
Circular shall retain electricity metering data and related records for at
least 5 years.
Article
81. Methods and procedures for collecting metering data
1. Meter
readings and transmission of meter data to the power system and electricity
market operation unit shall be carried out daily through the following two
parallel and independent methods:
a) Method
1: The power system and electricity market operation unit shall perform time
synchronization and directly collect metering data from boundary meters in the
wholesale electricity market in accordance with Article 79 of this Circular;
b) Method
2: The generation unit, electricity transmission unit, and electricity
wholesale unit shall collect metering data from meters within their respective
management scopes. Data collected by the electricity transmission unit and electricity
wholesale unit shall be transmitted to the shared metering data repository of EVN
and the power system and electricity market operation unit.
2. Metering
data shall be collected according to the following schedule:
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b) Before
24:00 on Day D+1, the power system and electricity market operation unit shall
announce metering data for metering data verification;
c) Before
12:00 on Day D+4, the electricity transmission unit, generation unit, and electricity
purchasing unit shall verify and reconcile metering data, identify any issues
or events resulting in output discrepancies, and submit to the power system and
electricity market operation unit their feedback confirming the metering data
reconciliation results. After this deadline, the power system and electricity
market operation unit shall not accept feedback concerning issues related to
the metering data for Day D. Where no feedback is submitted by the relevant
units on the Electricity Market Web Portal before 12:00 on Day D+4, such units
shall be deemed to have confirmed their agreement, and the power system and
electricity market operation unit shall not be responsible for handling any
subsequently arising feedback;
d) Before
12:00 on Day D+5, the power system and electricity market operation unit shall
cooperate with the relevant units to inspect, verify, and correct discrepancies
and estimate metering data;
dd)
Before 16:00 on Day D+5, the power system and electricity market operation unit
shall calculate and announce the official electricity metering and load data
for Day D on the Electricity Market Web Portal;
e) Before
12:00 on Day D+6, the power system and electricity market operation unit shall
reannounce the official electricity metering and load data for Day D where
abnormalities or data discrepancies are identified after Day D+5;
g) Before
the eighth working day after the end of the settlement cycle, the power system
and electricity market operation unit shall announce the record finalizing the
output discrepancy for the settlement cycle.
3. Requirements
for collecting metering data
a)
Metering data collected daily by the electricity metering data management unit
shall include active and reactive energy values in both delivery and receipt
directions for each 30-minute trading interval of the day, as recorded by the
main and backup meters;
b)
Metering data shall be openly shared after 24:00 on Day D+1 and fully updated
throughout the process of verifying, determining, and estimating the data, so
that electricity purchasing units and electricity selling units may access and
fully verify such data within the scope of their electricity trading
activities;
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Article
82. Verification of metering data
1. The electricity
metering data management unit shall verify the metering data collected at the metering
data collection, processing, and storage center to ensure the accuracy and
validity of such data.
2. Metering
data verification and reconciliation shall be carried out according to the
following principles:
a)
Metering data from the backup metering system shall be used for comparison and
reconciliation with data from the main metering system, after conversion to the
same metering location, as a basis for confirming that the main metering system
operates accurately and reliably with an error not exceeding 1%;
b) Meter
data read by the electricity metering system operation management unit and
transmitted to the electricity metering data management unit shall be compared
and reconciled with the data directly read by the electricity metering data
management unit as a basis for determining the reliability and accuracy of the
metering data;
c)
Electricity output data collected daily from the main and backup metering
systems shall be announced and verified and confirmed by the relevant parties
as a basis for payment calculations.
3. Where
metering data is found to be abnormal or inaccurate, the electricity metering
data management unit shall recollect such data, or request the electricity
metering system operation management unit to recollect it, and repeat the
metering data verification procedures prescribed in Clause 2 of this Article.
4. Where
metering data cannot be collected, or where verification and reconciliation
reveal discrepancies between meter data and data stored in the on-site computer
or the metering database, the electricity metering data management unit shall
take charge and cooperate with the relevant units in investigating the causes
and correcting, estimating, and offsetting any discrepancies in accordance with
the regulations on electricity transmission systems, electricity distribution
systems, and electricity metering promulgated by the Ministry of Industry and
Trade of Vietnam.
5. Where
the units disagree with the announced metering data, they may request that
their reservations be recorded, request an extraordinary audit, or lodge a
complaint with a competent authority.
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1. The
electricity metering data of a generation unit shall be determined according to
the electricity delivery and receipt formula applicable to that generation unit
and prescribed in the electricity delivery and receipt arrangement.
2. The
electricity metering data of an electricity wholesale unit for a trading
interval shall be determined as follows:
a) By
adding the following components:
- Electricity
output received from the transmission grid;
- Total
electricity output received from other electricity wholesale units;
- Total
electricity output received from generation sources connected to the
distribution grid;
- Total
electricity output from imported generation sources connected to the
distribution grid.
b) By
subtracting the following components:
- Total
electricity output delivered to the transmission grid;
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Article
84. Estimation of metering data
1. Where
accurate metering data for Day D cannot be collected in accordance with
Articles 81, 82, and 83 of this Circular, the power system and electricity
market operation unit shall estimate the metering data in accordance with the
regulations on electricity transmission systems, electricity distribution
systems, and electricity metering promulgated by the Ministry of Industry and
Trade of Vietnam.
2. After
electricity metering data has been estimated, the relevant units shall take
measures to recollect and determine accurate metering data as a basis for
collecting additional payments or making refunds for the periods in which
estimated electricity metering data was applied.
3. Where
accurate metering data cannot be determined, the estimated metering data shall
be used as the official basis for electricity payment between the relevant
units.
Article
85. Confirmation of electricity output based on final meter readings
Digital
signatures shall be used to confirm the following metering data:
1. The
total electricity output delivered and received at the upstream connection
points of an electricity wholesale unit.
2. Electricity
output purchased from the electricity market.
3. The
difference between the electricity output determined from the final monthly
meter readings and the aggregate electricity output for all trading intervals
in the month.
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Chapter
VII
CALCULATION
OF SPOT ELECTRICITY MARKET PRICES
Section 1. CALCULATION OF MARKET PRICES APPLICABLE TO
GENERATION UNITS
Article
86. Determination of market energy price applicable to generation units
1. After Trading
Day D, the power system and electricity market operation unit shall prepare the
market energy price calculation schedule for each trading interval of Day D
according to the following procedures:
a)
Calculate the system load for the trading interval by converting metered
electricity output to the generator terminals;
b)
Prepare the market energy price calculation schedule using the unconstrained
scheduling method according to the following sequence:
- Fix the
actual generation output of power plants indirectly participating in the electricity
market and power plants directly participating in the electricity market but
excluded from the electricity market during the relevant trading interval below
the base portion of the power system load curve;
- Arrange
the capacity bands in the scheduling offers of direct trading generation units.
The actual output of renewable energy power plants directly participating in
the electricity market, converted to the generator terminals, shall be
determined after the operating day on the basis of actual metering data;
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2. The market
energy price applicable to a generation unit shall equal the offer price of the
final capacity band scheduled to meet the system load in the market energy
price calculation schedule. Where the offer price of the final capacity band in
such schedule exceeds the electricity market price cap, the market energy price
shall equal the electricity market price cap.
Article
87. Full market price applicable to generation units
The full
market price applicable to a generation unit for a trading interval shall be
determined using the following formula:
FMP(i) = SMP(i) + CAN(i)
Where:
FMP(i): Full market price applicable to the generation unit for trading
interval i (VND/kWh);
SMP(i): Market energy price applicable to the generation unit for trading
interval i, determined in accordance with Article 86 of this Circular (VND/kWh);
CAN(i): Market capacity price applicable to the generation unit
for trading interval i, determined in accordance with Article 28 of this
Circular (VND/kWh).
Article
88. Determination of market energy price during intervention in electricity
market
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Section 2. SPOT ELECTRICITY MARKET PRICES APPLICABLE TO
ELECTRICITY WHOLESALE UNITS
Article
89. Market energy price applicable to electricity wholesale units
The market
energy price applicable to an electricity wholesale unit for trading interval i
shall be calculated as follows:
1. The
power system and electricity market operation unit shall calculate and announce
the electricity-loss conversion factor for trading interval i using the
following formula:
Where:
k(i): Electricity-loss conversion factor for trading interval i;
QG(i):
Total electricity output during trading interval i of power plants connected to
the transmission grid, imported power sources, and power plants connected to
the distribution grid that participate in the electricity market or have
entered into a power purchase agreement with EVN (kWh);
QL(i):
Total electricity output delivered and received at the upstream connection
points of electricity purchasing units during trading interval i, including
electricity output delivered and received between an electricity purchasing
unit, including an electricity exporting unit, and the transmission grid, and
electricity output delivered and received between such unit and power plants
connected to the distribution grid that participate in the electricity market
or have entered into a power purchase agreement with EVN (kWh).
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CSMP(i) = k(i) x SMP(i)
Where:
CSMP(i): Market energy price applicable to the electricity
wholesale unit for trading interval i (VND/kWh);
SMP(i): Market energy price applicable to a generation unit for trading
interval i, calculated in accordance with Article 86 of this Circular
(VND/kWh);
k(i): Electricity-loss conversion factor for trading interval i,
determined in accordance with Clause 1 of this Article.
Article
90. Market capacity price applicable to electricity wholesale units
The market
capacity price applicable to an electricity wholesale unit for trading interval
i shall be calculated as follows:
CCAN(i) = k(i) x CAN(i)
Where:
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CAN(i): Market capacity price applicable to a generation unit for trading
interval i, calculated in accordance with Point b Clause 3 Article 28 of this
Circular (VND/kWh);
k(i): Electricity-loss conversion factor for trading interval i,
determined in accordance with Clause 1 Article 89 of this Circular.
Article
91. Full market price applicable to electricity wholesale units
The full
market price applicable to an electricity wholesale unit for trading interval i
shall be determined using the following formula:
CFMP(i) = CSMP(i) + CCAN(i)
Where:
CFMP(i): Full market price applicable to the electricity wholesale
unit during trading interval i (VND/kWh);
CSMP(i):
Market energy price applicable to the electricity wholesale unit for trading
interval i (VND/kWh);
CCAN(i): Market capacity price applicable to the electricity
wholesale unit for trading interval i (VND/kWh).
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1. Before
09:00 on Day D+2, the power system and electricity market operation unit shall
announce the market energy price, market capacity price, and full market price
applicable to generation units for each trading interval of Day D.
2. Before
16:00 on Day D+2, the power system and electricity market operation unit shall
announce the provisional market energy price, market capacity price, and full
market price applicable to electricity wholesale units for each trading
interval of Day D.
3. Before
16:00 on Day D+5, the power system and electricity market operation unit shall
announce the official market energy price, market capacity price, and full
market price applicable to electricity wholesale units for each trading
interval of Day D.
Chapter
VIII
PAYMENTS
Section 1. PAYMENTS TO DIRECT TRADING GENERATION UNITS
Article
93. Electricity output of power plants used for payment in electricity market
1. The power
system and electricity market operation unit shall calculate the following
components of the electricity output of a power plant for each trading interval
for payment purposes in the electricity market:
a)
Electricity output paid at the offer price for a thermal power plant whose
offer price exceeds the electricity market price cap (Qbp);
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c)
Electricity output deviating from the output dispatched under dispatch
instructions (Qdu). Qdu shall not apply to a power plant with an installed
capacity of less than 30 MW, a wind power plant, or a solar power plant. For a cascade
hydropower group submitting a common offer for the entire group, where the
upstream cascade hydropower plant participates in frequency regulation, Qdu
shall not apply to the downstream cascade hydropower plant;
d)
Electricity output paid at the market energy price (Qsmp).
2. The electricity
output of a power plant deviating from the output dispatched under dispatch
instructions (Qdu) for a trading interval shall be determined according to the
following procedures:
a)
Determination of the output dispatched under dispatch instructions
The
output dispatched under dispatch instructions means the electricity output at
the generator terminals calculated on the basis of dispatch instructions issued
by the power system and electricity market operation unit for the generating
unit, taking into account the capacity specified in such dispatch instructions
and the ramp-up and ramp-down rate of the generating unit. The output
dispatched under dispatch instructions shall be determined using the following
formula:
Where:
i: The i-th trading interval;
J: Number of changes to dispatch instructions during trading
interval i;
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: The time at which the
generating unit reaches the capacity level specified in the dispatch
instruction issued by the power system and electricity market operation unit at
time 
(minutes);
ΔT: Duration
of a trading interval (minutes);
Qddi:
Output dispatched under dispatch instructions at the generator terminals for trading
interval i (MWh);
: Capacity specified by
the power system and electricity market operation unit in the dispatch
instruction issued to the generating unit at time 
(MW);
: Capacity reached by the
generating unit at time 
(MW).
The
period from the time at which the dispatch instruction specifying capacity is issued at time 
to time 
, when the generating unit reaches
capacity 
, shall be
determined as follows:
Where:
a: Ramp-up or ramp-down rate of the generating unit
registered in the scheduling offer (MW/minute).
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b) Conversion
of the output dispatched under dispatch instructions 
, as calculated in accordance with Point a of
this Clause, to the metering location;
c) Calculation
of the difference between metered electricity output and the output dispatched
under dispatch instructions using the following formula:
ΔQi=Qmqi - Qddi
Where:
ΔQᵢ: Electricity output deviating from the output dispatched
under dispatch instructions during trading interval i (kWh);
Qmqᵢ: Metered electricity output of the generating unit
converted to the generator terminals during trading interval i (kWh);
Qddᵢ: Output dispatched under dispatch instructions for the
generating unit during trading interval i, calculated in accordance with Point
a of this Clause (kWh).
Where no
dispatch instruction is issued during trading interval i, Qdd shall be
determined using the following formula:
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Qddᵢ: Output dispatched under dispatch instructions for the
generating unit during trading interval i (kWh);
: Capacity specified by
the power system and electricity market operation unit in the dispatch
instruction issued to the generating unit at time tp (MW);
ΔT: Duration of a trading interval (minutes).
d) Calculation
of the electricity output of the generating unit deviating from dispatch
instructions according to the following principles:
- Calculate
the permissible deviation using the following formula:
+ For a
generating unit with an installed capacity of less than 100 MW:
+ For a
generating unit with an installed capacity of 100 MW or more:
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ε: Permissible deviation of the generating unit for each trading
interval (kWh);
Qddi: Electricity output dispatched under dispatch instructions
at the generator terminals (kWh);
ΔT:
Duration of a trading interval (minutes).
- Calculate
the electricity output of the generating unit deviating from dispatch
instructions during the trading interval using the following formulas:
+ Where |ΔQi|
≤ ε: Qdui = 0
+ Where |ΔQi|
> ε: Qdui = Qmqi - kqd x Qddi
Where:
Qdui:
Electricity output of the generating unit deviating from dispatch instructions
during trading interval i (kWh);
Qmqᵢ: Metered electricity output of the power plant during trading
interval i (kWh);
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kqd:
Output conversion factor from the generator terminals to the metering location.
- Calculate
the electricity output of the power plant deviating from dispatch instructions
during the trading interval using the following formula:
Where:
Qduᵢ: Electricity output of the power plant deviating from
dispatch instructions during trading interval i (kWh);
Qdui,g :
Electricity output of generating unit g of the
power plant deviating from dispatch instructions during trading interval i
(kWh);
G: Total number of generating units of the power plant.
dd) Where
a generating unit or boiler of a thermal power plant is undergoing start-up or
shutdown, other than due to an incident, the electricity output deviating from
dispatch instructions during such period shall not be taken into account. Where
such generating unit or boiler is subject to a technical constraint affecting
the generation capacity of another generating unit of the power plant, the
electricity output of the affected generating unit deviating from dispatch
instructions shall not be taken into account;
e) The
meter installed at the generator terminals and the meters installed at the
auxiliary-load metering locations of the generating unit, if any, shall be
given priority for determining the actual electricity output at the generator
terminals for comparison with compliance with dispatch instructions recorded in
the dispatch instruction management system.
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a)
Identify the generating unit whose offer price exceeds the electricity market
price cap and which is included in the market price calculation schedule for trading
interval i, and identify the metering location of such generating unit;
b)
Calculate the electricity output paid at the offer price at each metering
location identified under Point a of this Clause using the following formula:
Where:
i: The
i-th trading interval;
j: The j-th metering location of the thermal power plant,
identified under Point a of this Clause;
: Electricity output paid
at the offer price at metering location j during trading interval i (kWh);
: Metered electricity
output at metering location j during trading interval i (kWh);
: Electricity output
corresponding to the capacity offered at a price lower than or equal to the electricity
market price cap during trading interval i by the generating unit connected to
metering location j, converted to such metering location (kWh);
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: Electricity output of
the generating unit connected to metering location j deviating from the output
dispatched under dispatch instructions, converted to such metering location
(kWh).
c)
Calculate the electricity output of the power plant paid at the offer price
using the following formula:
Where:
j: The
j-th metering location of the thermal power plant, identified under Point a of
this Clause;
J: Total number of metering locations of the power plant
having generating units whose offer prices exceed the electricity market price
cap and which are included in the market price calculation schedule;
Qbpi:
Electricity output of the power plant paid at the offer price during trading
interval i (kWh);
: Electricity output paid
at the offer price at metering location j during trading interval i (kWh).
4. The
incremental electricity output of a power plant during a trading interval shall
be determined according to the following procedures:
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Where Qdu
> 0:
Where Qdu
≤ 0:
Where:
: Metered electricity
output used for payment for the generating unit during trading interval i,
converted to the generator terminals (kWh);
: Electricity output of
the generating unit deviating from the output dispatched under dispatch
instructions, converted to the generator terminals (kWh);
: Electricity output
corresponding to the capacity of the generating unit included in the market
energy price calculation schedule during trading interval i (kWh);
: Electricity output
corresponding to the dispatched capacity of the generating unit during the trading
interval, determined using the following formula:
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Where:
J: Number of changes to dispatch instructions due to
constraints during trading interval i;
: The time at which the
power system and electricity market operation unit issues the j-th dispatch
instruction changing the capacity of the generating unit due to a constraint
during trading interval i (minutes). Where, at such time, the capacity of the
generating unit is lower than the capacity included in the market energy price
calculation schedule for the trading interval (
),
shall be the time at which the generating
unit reaches such scheduled capacity;
: The time at which the
generating unit reaches the capacity level specified in the dispatch
instruction issued by the power system and electricity market operation unit at
time 
(minutes).
Where, at such time, the capacity of the generating unit is lower than the
capacity included in the market energy price calculation schedule for trading
interval I (), shall be the time at
which the generating unit reaches such scheduled capacity;
ΔT:
Duration of a trading interval (minutes);
: Capacity specified by
the power system and electricity market operation unit in the dispatch
instruction issued to the generating unit at time 
. Where such capacity is lower than the capacity
included in the market energy price calculation schedule for the trading
interval (
), it shall
be taken as the scheduled capacity (MW);
: Capacity reached by the
generating unit at time 
(MW);
: The period from the time at which the dispatch
instruction specifying capacity is issued at time to time 
, when the generating unit reaches capacity , determined as follows:
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For a
generating unit providing the secondary frequency control service during the trading
interval through the AGC system, where data on the capacity levels specified in
dispatch instructions issued by the power system and electricity market
operation unit cannot be determined, such electricity output shall equal the
metered electricity output of the generating unit during the trading interval,
converted to the generator terminals.
Where a
thermal generating unit is undergoing start-up or shutdown, other than due to
an incident, the incremental electricity output of such generating unit during
the trading interval shall equal 0.
c)
Calculation of the incremental electricity output of the power plant during trading
interval i using the following formula:
Where:
: Total incremental
electricity output of the power plant during trading interval i, converted to
the metering location (kWh);
g: A generating unit of the power plant producing incremental
electricity output during trading interval i;
G: Total number of generating units of the power plant
producing incremental electricity output during trading interval i;
k: Output conversion factor from the generator terminals to
the metering location;
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d) The
power system and electricity market operation unit shall announce the reasons
for any incremental electricity output of the power plant arising from power
system constraints.
5. The electricity
output of the power plant paid at the market energy price during trading
interval i shall be determined using the following formulas:
Where the
electricity output deviating from the output dispatched under dispatch
instructions is positive (Qduᵢ > 0):
Qsmpi = Qmqi - Qbpi -
Qconi - Qdui
Where the
electricity output deviating from the output dispatched under dispatch
instructions is negative (Qduᵢ < 0):
Qsmpi = Qmqi - Qbpi-
Qconi
Where:
Qsmpi :
Electricity output of the power plant paid at the market energy price during trading
interval i (kWh);
Qmqᵢ:
Metered electricity output of the power plant during trading interval i (kWh);
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Qconi:
Incremental electricity output of the power plant during trading interval i
(kWh);
Qdui:
Electricity output deviating from the output dispatched under dispatch
instructions during trading interval i (kWh).
Article
94. Adjustment of electricity output of power plants for payment in electricity
market
1. Electricity
output used for payment in the electricity market shall be adjusted in the
following cases:
a) During
trading interval i, the metered electricity output of the power plant is less
than or equal to the contracted electricity output for that trading interval
;
b) During
trading interval i, the metered electricity output of the power plant is
greater than the contracted electricity output of the power plant for that trading
interval
, while the
electricity output of the power plant paid at the market energy price is less
than the contracted electricity output for that trading interval
.
2. The
power system and electricity market operation unit shall recalculate and adjust
the electricity output components used for payment in the electricity market
during the trading intervals prescribed in Clause 1 of this Article, based on
the following output components:
a) The contracted
electricity output of the power plant for the trading interval
, determined in accordance with
Article 38 of this Circular;
b) The
electricity output of the power plant paid at the market energy price (Qsmpᵢ)
during trading interval i, determined in accoCrdance with Clause 5 Article 93
of this Circular;
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3. Adjustment
principles
a) In the
case prescribed in Point a Clause 1 of this Article, the incremental
electricity output (Qconᵢ) and the electricity output paid at the offer price
for a power plant whose offer price exceeds the electricity market price cap (Qbpᵢ)
shall be adjusted to 0 for that trading interval (Qconi = 0;
Qbpi = 0);
b) In the
case prescribed in Point b Clause 1 of this Article, the electricity output
used for payment in the electricity market shall be adjusted on the principle
that the metered electricity output for that trading interval shall remain unchanged
and in accordance with the payment calculation procedures in the electricity
market prescribed in Appendix III enclosed with this Circular.
Article
95. Market energy payments
1. The
power system and electricity market operation unit shall calculate the total
market energy payments of a power plant, excluding wind power plants, solar
power plants, biomass power plants, and small hydropower plants, for a
settlement cycle using the following formula:
Rg = Rsmp + Rbp + Rcon + Rdu
Where:
Rg: Total market energy payments for the settlement cycle
(VND);
Rsmp: Payment for the electricity output paid at the market
energy price during the settlement cycle (VND);
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Rcon: Payment for incremental electricity output during the
settlement cycle (VND);
Rdu: Payment for electricity output deviating from the output
dispatched under dispatch instructions during the settlement cycle (VND).
2. Payment for the
electricity output of a power plant paid at the market energy price during the
settlement cycle shall be determined as follows:
a)
Calculation for each trading interval i using the following formula:
Rsmpi = Qsmpi x SMPi
Where:
Rsmpᵢ: Payment for the electricity output of the power plant paid
at the market energy price during trading interval i of the settlement cycle
(VND);
SMPᵢ: Market energy price for trading interval i of the settlement
cycle (VND/kWh);
Qsmpᵢ:
Electricity output paid at the market energy price during trading interval i of
the settlement cycle (kWh).
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Where:
Rsmp: Payment for the electricity output of the power plant paid
at the market energy price during the settlement cycle (VND);
i: The i-th trading interval of the settlement cycle;
I: Total number of trading intervals in the settlement cycle;
Rsmpᵢ: Payment for the electricity output of the power plant paid
at the market energy price during trading interval i (VND).
3. Payment
for the electricity output paid at the offer price for a thermal power plant
whose offer price exceeds the electricity market price cap during the
settlement cycle shall be determined as follows:
a)
Calculation for each trading interval using the following formula:
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Rbpᵢ: Payment for the electricity output of the power plant
offered above the electricity market price cap during trading interval i (VND);
j: The j-th offer band in the offer of a generating unit of
the thermal power plant whose offer price exceeds the electricity market price
cap and which is arranged in the market energy price calculation schedule;
J: Total number of offer bands in the offer of the thermal
power plant whose offer prices exceed the electricity market price cap and
which are arranged in the market energy price calculation schedule;
: Offer price
corresponding to offer band j in the offer of generating unit g of the thermal
power plant during trading interval i (VND/kWh);
: Highest offer price
among the offer bands of the thermal power plant arranged in the market energy
price calculation schedule during trading interval i (VND/kWh);
: Electricity output
corresponding to the capacity offered at the offer price 
in the offer of the thermal
power plant and dispatched during trading interval i, converted to the metering
location (kWh);
Qbp: Electricity output of the thermal power plant offered
above the electricity market price cap during trading interval i, converted to
the metering location (kWh).
b)
Calculation for the settlement cycle using the following formula:
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Rbp: Payment for the electricity output of the power plant
offered above the electricity market price cap during the settlement cycle
(VND);
i: A trading interval during which the power plant is
dispatched at an offer price exceeding the electricity market price cap;
I: Total number of trading intervals during which the power
plant is dispatched at an offer price exceeding the electricity market price
cap;
Rbpᵢ: Payment for the electricity output of the power plant
offered above the electricity market price cap during trading interval i (VND).
4. Payment
for incremental electricity output of a power plant shall be determined as
follows:
a)
Calculation for each trading interval using the following formula:
Where:
Rconᵢ: Payment for incremental electricity output during trading
interval i (VND);
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G: Total
number of generating units of the power plant producing incremental electricity
output during trading interval i;
: Incremental electricity
output of generating unit g during trading interval i, converted to the
metering location (kWh);
: Highest offer price
corresponding to the incremental capacity band of generating unit g during trading
interval i (VND/kWh). For a hydropower plant, where this offer price exceeds
the electricity market price cap, the electricity market price cap shall apply.
b) Calculation
for the settlement cycle using the following formula:
Where:
Rcon: Payment for incremental electricity output during the
settlement cycle (VND);
i: The i-th trading interval of the settlement cycle during
which the power plant is required to generate incremental output under dispatch
instructions;
I: Total number of trading intervals in the settlement cycle
during which the power plant is required to generate incremental output under
dispatch instructions;
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c) The
power system and electricity market operation unit shall announce the reasons
for any incremental electricity output of the power plant arising from power
system constraints.
5. Where
a hydropower plant is dispatched due to a must-run constraint and has an offer
price exceeding the electricity market price cap, or is dispatched for a
capacity band whose offer price exceeds the electricity market price cap, the
corresponding electricity output generated during that trading interval shall
be paid at the electricity market price cap.
6. Payment for
electricity output of a power plant deviating from the output dispatched under
dispatch instructions during a trading interval.
a)
Calculation for each trading interval using the following formula:
- Where
electricity output exceeds the output specified in dispatch instructions:
Where:
Rduᵢ: Payment for electricity output deviating from dispatch
instructions during trading interval i (VND);
g: A generating unit of the power plant generating above the
output specified in dispatch instructions during trading interval i;
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: Electricity output of
generating unit g generated above the output specified in dispatch instructions
during trading interval i (kWh);
Pbminᵢ: Lowest offer price among all generating units during trading
interval i (VND/kWh).
- Where
electricity output is lower than the output specified in dispatch instructions:
Where:
Rduᵢ:
Payment for electricity output deviating from dispatch instructions during
trading interval i (VND);
g: A generating unit of the power plant generating below the
output specified in dispatch instructions during trading interval i;
G: Total number of generating units of the power plant
generating below the output specified in dispatch instructions during trading
interval i;
: Electricity output of
generating unit g generated below the output specified in dispatch instructions
during trading interval i (kWh);
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Pbpi,max:
Energy price of the highest-priced generating
unit paid during trading interval i (VND/kWh).
b)
Calculation for the settlement cycle using the following formula:
Where:
Rdu: Payment for electricity output deviating from dispatch
instructions during the settlement cycle (VND);
i: The i-th trading interval of the settlement cycle during
which the thermal power plant generates output deviating from dispatch
instructions;
I: Total number of trading intervals in the settlement cycle
during which the thermal power plant generates output deviating from dispatch
instructions;
Rduᵢ: Payment for electricity output deviating from the output
dispatched under dispatch instructions during trading interval i (VND).
7. The power system
and electricity market operation unit shall calculate the market energy payment
of a wind power plant, solar power plant, biomass power plant, or small
hydropower plant during the settlement cycle using the following formula:
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Where:
Rg: Market energy payment for the settlement cycle applicable
to a renewable energy power plant (VND);
Rsmpᵢ:
Payment for the electricity output of the power plant paid at the market energy
price during trading interval i of the settlement cycle (VND);
SMPᵢ:
Market energy price for trading interval i of the settlement cycle (VND/kWh);
Qmqᵢ: Metered electricity output of the power plant (kWh);
i: The
i-th trading interval of the settlement cycle;
I: Total number of trading intervals in the settlement cycle.
Article
96. Market capacity payment
The power
system and electricity market operation unit shall calculate the market capacity
payment for a power plant during the settlement cycle according to the
following procedures:
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Rcan (i) = CAN
(i) x Qmq (i)
Where:
Rcan(i): Capacity payment for the power plant during trading
interval i (VND);
CAN(i): Market capacity price during trading interval i (VND/kWh);
Qmq(i): Metered electricity output of the power plant during trading
interval i (kWh).
2. Calculation
for the settlement cycle using the following formula:
Where:
Rcan: Capacity payment for the power plant during the settlement
cycle (VND);
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I: Total number of trading intervals in the settlement cycle;
Rcanᵢ: Capacity payment for the power plant during trading
interval i (VND).
Article
97. Contract-for-difference payment under power purchase agreement
Based on
the market energy price and market capacity price announced by the power system
and electricity market operation unit, the generation unit shall calculate the
payment under the power purchase agreement and submit it to the electricity
purchasing unit in accordance with Article 112 of this Circular for the
settlement cycle according to the following procedures:
1. Calculation
for each trading interval using the following formula:
Rc (i) = [Pc - FMP(i)] x Qc(i)
Where:
Rc(i): Contract-for-difference payment during trading interval i
(VND);
Qc(i): Contracted electricity output during trading interval i (kWh);
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FMP(i): Full market price applicable to the generation unit during
trading interval i (VND/kWh).
2. Calculation
for the settlement cycle using the following formula:
Where:
Rc: Contract-for-difference payment during the settlement
cycle (VND);
i: The
i-th trading interval of the settlement cycle;
I: Total
number of trading intervals in the settlement cycle;
Rc(i): Contract-for-difference payment during trading interval i
(VND).
Section
2
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Article
98. Calculation of electricity purchase costs at spot electricity market prices
of electricity wholesale units during trading intervals
1. The
electricity output delivered and received at the upstream connection points of electricity
wholesale unit l during trading interval i shall be determined in accordance
with Clause 2 Article 83 of this Circular.
2. The
electricity output purchased at market prices by an electricity wholesale unit
during a trading interval shall be determined as follows:
a) The
power system and electricity market operation unit shall calculate and announce
the proportion of electricity purchased from the spot electricity market by the
relevant electricity wholesale unit from power plants having power purchase
agreements with EVN and allocated to such electricity wholesale unit:
Where:
X1:
Proportion of electricity purchased at spot electricity market prices by electricity
wholesale unit l from power plants with allocated contracts (%);
Qc(g,M):
Contracted electricity output for month M of power plant g, calculated in
accordance with Articles 17, 37, and 38 of this Circular (kWh);
Qptdk(l,M):
Forecast electricity output delivered and received at the upstream connection
points for month M, provided by electricity wholesale unit l for preparation of
the next-month operation plan (kWh);
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L: Total
number of electricity wholesale units.
b) The
electricity output purchased at market prices by an electricity wholesale unit
from power plants with allocated contracts during trading interval i shall be
determined using the following formula:
Qm1(l,i)=X1 x Q(l, i)
Where:
Qm1(l,i):
Electricity output purchased at market prices by electricity wholesale unit l
from power plants with allocated contracts during trading interval i (kWh);
X1:
Proportion of electricity purchased at spot electricity market prices by electricity
wholesale unit l from power plants with allocated contracts, calculated and
announced by the power system and electricity market operation unit in
accordance with Point a of this Clause (%);
Q(l,i): Electricity output delivered and received at the upstream
connection points of electricity wholesale unit l during trading interval i,
determined in accordance with Clause 1 of this Article (kWh).
c) The
electricity output purchased at market prices by electricity wholesale unit l
during trading interval i from power plant g having a direct power purchase
agreement shall be determined using the following formula:
Qm2(l,g,i) = X2(g, i) x Q(l,i)
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Qm2(l,g,i):
Electricity output purchased at market prices by electricity wholesale unit l
during trading interval i from power plant g having a direct contract (kWh);
Q(l,i): Electricity output delivered and received at the upstream
connection points of electricity wholesale unit l during trading interval i,
determined in accordance with Clause 1 of this Article (kWh);
X2(g,i):
Electricity output proportion (%), calculated using the following formula:
Where:
Qmq(g,i):
Electricity output delivered at the delivery and receipt point during trading
interval i by power plant g, which directly participates in the electricity
market and has entered into a direct power purchase agreement with the electricity
wholesale unit (kWh);
Q(l,i): Electricity output delivered and received at the upstream
connection points of electricity wholesale unit l during trading interval i,
determined in accordance with Clause 1 of this Article (kWh);
L: Total number of electricity wholesale units having direct power
purchase agreements with power plant g;
k(i):
Electricity-loss conversion factor for trading interval i, determined in accordance
with Clause 1 Article 89 of this Circular.
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Where:
Qm(l,i):
Total electricity output purchased from the spot electricity market by electricity
wholesale unit l during trading interval i (kWh);
Qm1(l,i):
Electricity output purchased at market prices by electricity wholesale unit l
from power plants with allocated contracts during trading interval i (kWh);
Qm2(l,g,i):
Electricity output purchased at market prices by electricity wholesale unit l
during trading interval i from power plant g having a direct contract (kWh);
G: Total number of power plants having power purchase
agreements with the electricity wholesale unit.
3. Electricity
purchase costs at spot electricity market prices of an electricity wholesale
unit during trading interval i shall be determined as follows:
a) The
electricity purchase cost at spot electricity market prices of an electricity
wholesale unit from power plants with allocated contracts during trading
interval i shall be determined using the following formula:
Cm1(l,i) = CFMP(i) x Qm1(l,i)
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Cm1(l,i):
Electricity purchase cost at spot electricity market prices of electricity
wholesale unit l from power plants with allocated contracts during trading
interval i (VND);
CFMP(i):
Full market price applicable to the electricity wholesale unit during trading
interval i (VND/kWh);
Qm1(l,i):
Total electricity output purchased at market prices by electricity wholesale
unit l from power plants with allocated contracts during trading
interval i, calculated in accordance with Point b Clause 2 of this Article
(kWh).
b) The
electricity purchase cost at spot electricity market prices of an electricity
wholesale unit during trading interval i from power plant g having a power
purchase agreement with such electricity wholesale unit shall be determined
using the following formula:
Cm2(l,g,i) = CFMP(i) x Qm2(l,g,i)
Where:
g: A power plant having a power purchase agreement with the electricity
wholesale unit;
Cm2 (l,g,i):
Electricity purchase cost at spot electricity market prices of electricity
wholesale unit l for power plant g during trading interval i (VND);
CFMP(i):
Full market price applicable to the electricity wholesale unit during trading
interval i (VND/kWh);
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c) The
total electricity purchase cost from the spot electricity market of an electricity
wholesale unit during a trading interval shall be determined using the
following formula:
Where:
Cm(l,i):
Total electricity purchase cost from the spot electricity market of electricity
wholesale unit l during trading interval i (VND);
Cm1(l,i):
Electricity purchase cost at spot electricity market prices of electricity
wholesale unit l from power plants with allocated contracts during trading
interval i (VND);
g: A
power plant having a power purchase agreement with the electricity wholesale
unit;
G: Total number of power plants having power purchase
agreements with the electricity wholesale unit;
Cm2(l,g,i):
Electricity purchase cost at spot electricity market prices of electricity
wholesale unit l from power plant g during trading interval i (VND).
Article
99. Calculation of electricity purchase costs in spot electricity market of
electricity wholesale units during settlement cycles
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1. The
electricity purchase cost in the spot electricity market of electricity wholesale
unit l during settlement cycle M from power plants with allocated contracts
shall be determined using the following formula:
Where:
i: The
i-th trading interval of the settlement cycle;
I: Total
number of trading intervals in the settlement cycle;
TCm1(l,M):
Electricity purchase cost in the spot electricity market of electricity
wholesale unit l during settlement cycle M from power plants with allocated
contracts (VND);
Cm1(l,i):
Electricity purchase cost in the spot electricity market of electricity
wholesale unit l during trading interval i from power plants with allocated
contracts, determined under Point a Clause 3 Article 98 of this Circular (VND).
2. The electricity
purchase cost in the spot electricity market of electricity wholesale unit l
during the settlement cycle for power plant g having a power purchase agreement
with the electricity wholesale unit shall be determined using the following
formula:
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i: The
i-th trading interval of the settlement cycle;
I: Total
number of trading intervals in the settlement cycle;
g: A
power plant having a power purchase agreement with the electricity wholesale
unit;
TCm2(l,g,M):
Electricity purchase cost in the spot electricity market of electricity
wholesale unit l during settlement cycle M from power plant g having a power
purchase agreement with the electricity wholesale unit (VND);
Cm2(l,g,i): Total electricity purchase cost at spot electricity market
prices of electricity wholesale unit l during trading interval i from power
plant g having a power purchase agreement with the electricity wholesale unit
(VND);
UpliftM(g): Spot electricity market price adjustment component
applicable to the electricity wholesale unit for power plant g during
settlement cycle M, calculated by the power system and electricity market
operation unit on the basis of data provided by the generation unit after the
operating month using the following formula:
Where:
g: A
power plant having a power purchase agreement with the electricity wholesale
unit;
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I: Total number of trading intervals in settlement cycle M;
L: Total
number of electricity wholesale units;
Rg(M): Total market energy payments during settlement cycle M of
power plant g, as stated in the monthly electricity market payment statement
issued by the power system and electricity market operation unit, determined in
accordance with Article 95 of this Circular (VND);
Rgcan (M):
Total revenue at the market capacity price during settlement cycle M of power
plant g, as stated in the monthly electricity market payment statement issued
by the power system and electricity market operation unit, determined in
accordance with Article 96 of this Circular (VND);
Cm2(l,g,i):
Electricity purchase cost at spot electricity market
prices of electricity wholesale unit l during trading interval i from power
plant g, determined under Point b Clause 3 Article 98 of this Circular (VND);
Qm2 (l,g,i):
Electricity output purchased at market prices by electricity wholesale unit l
during trading interval i from power plant g, determined in accordance with
Point c Clause 2 Article 98 of this Circular (kWh).
3. The
total electricity purchase costs of an electricity wholesale unit in the spot
electricity market during the settlement cycle shall be determined using the
following formula:
Where:
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TCm1(l,M):
Electricity purchase cost in the spot electricity market of electricity
wholesale unit l during settlement cycle M from power plants with allocated
contracts, determined under Clause 1 of this Article (VND);
g: A
power plant having a power purchase agreement with the electricity wholesale
unit;
G: Total
number of power plants having power purchase agreements with the electricity
wholesale unit;
TCm2(l,g,M):
Electricity purchase cost in the spot electricity market of electricity
wholesale unit l during settlement cycle M from power plant g, determined under
Clause 2 of this Article (VND).
Article
100. Calculation of contract-for-difference payments under power purchase
agreements of electricity wholesale units
The
electricity seller shall calculate the contract-for-difference payment under
the power purchase agreement during the settlement cycle according to the
following procedures:
1. Calculation
for each trading interval using the following formula:
Rc(i) = [Pc -
FMP(i)] x Qc(i)
Where:
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Qc(i):
Contracted electricity output during trading interval i (kWh);
Pc: Price
under the power purchase agreement (VND/kWh);
FMPi:
Full market price applicable to the generation unit during trading interval i
(VND/kWh).
2. Calculation
for the settlement cycle using the following formula:
Where:
: Contract-for-difference payment during settlement
cycle M (VND);
i: The
i-th trading interval of the settlement cycle;
I: Total
number of trading intervals in the settlement cycle;
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Section
3. AUXILIARY SERVICE PAYMENTS AND OTHER PAYMENTS
Article
101. Payments for secondary frequency control services
The power
system and electricity market operation unit shall calculate payments to a generation
unit providing the secondary frequency control service, including:
1. For
the metered electricity output of a power plant providing frequency regulation
services during a trading interval, payments shall be calculated in accordance
with Articles 95 and 96 of this Circular.
2. The
payment at the CAN capacity price for the electricity output corresponding to
the capacity provided for the secondary frequency control service shall be
calculated as follows:
Rđt(i) = CAN(i) x Qđt(i)
Where:
Rđt(i):
Payment at the CAN capacity price for the electricity output corresponding to
the capacity provided for the secondary frequency control service during trading
interval i (VND);
CAN(i): Market capacity price applicable to a generation unit
during trading interval i (VND/kWh);
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Qđt = Max{Min ([Qcb - Qmq],
Qđtcb), 0}
Where:
Qđtcb:
Electricity output corresponding to the capacity for provision of the secondary
frequency control service announced for the next trading interval of the
generating unit, converted to the metering location during trading interval i
(kWh);
Qcb:
Electricity output corresponding to the declared capacity of the generating
unit in its scheduling offer, converted to the metering location during trading
interval i (kWh);
Qmq:
Metered electricity output of the power plant during trading interval i (kWh).
Where,
during the actual trading interval, the generating unit does not participate in
the secondary frequency control service or the generating unit experiences an
incident, the electricity output corresponding to the capacity provided for the
secondary frequency control service during that interval shall equal zero (Qđt =
0).
Article
102. Payments for fast-start reserve services, must-run services to ensure
electricity supply, voltage regulation services, and black-start services
A unit
providing fast-start reserve services, must-run services to ensure electricity
supply (including regular must-run operation and operation of a gas turbine
power plant in open-cycle mode, or operation using part or all of its backup
fuel due to a shortage of primary fuel, under instructions from the power
system and electricity market operation unit), voltage regulation services, or
black-start services shall be paid under the relevant auxiliary service
agreement in accordance with the regulations on methods for determining, and
the procedures for approving, prices of power system auxiliary services and the
principal contents of power system auxiliary service agreements promulgated by
the Ministry of Industry and Trade of Vietnam.
Article
103. Payments to hydropower plants with reservoirs having regulating capacity
of less than 2 days
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1. Electricity
market payments: Payments shall be made in accordance with Clauses 2 and 6
Article 95 and Article 96 of this Circular.
2. Contract-for-difference
payment under the power purchase agreement
a) The contracted
electricity output under the power purchase agreement for each trading interval
of such power plant shall be calculated using the following formula:
Qc(i) = Qhc(i) x α
Where:
Qc(i): Contracted electricity output of the power plant during trading
interval i (kWh);
α: Proportion of electricity output paid at the contract
price applicable to a hydropower plant with a reservoir having a regulating
capacity of less than 2 days, as prescribed by the Ministry of Industry and
Trade of Vietnam;
Qhc(i): Adjusted electricity output during trading interval i
(kWh), determined as follows:
- Where
Qdu(i)> 0, Qhc(i) = Qm(i) - Qdu(i);
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Qm(i): Electricity output at the metering location during trading
interval i (kWh);
Qdu(i): Electricity output deviating from dispatch instructions
during trading interval i (kWh).
b) The
payment under the power purchase agreement of the power plant shall be
calculated based on the contracted electricity output prescribed in Point a of
this Clause and using the formula prescribed in Article 97 of this Circular.
Article
104. Payments to renewable energy power plants directly participating in
electricity market
1. A
renewable energy power plant having a power purchase agreement with a large
electricity consumer participating in the direct power trading mechanism and
choosing to sell electricity in the spot electricity market shall be paid in
accordance with the regulations on the direct power trading mechanism issued by
the Government of Vietnam.
2. A
renewable energy power plant that does not participate in the direct power
trading mechanism but chooses to participate directly in the electricity market
shall receive the following payment components:
a) Electricity
market payments: Payments shall be made in accordance with Clause 7 Article 95
and Article 96 of this Circular;
b)
Payment under a contract-for-difference power purchase agreement:
The contracted
electricity output under the power purchase agreement for each trading interval
of such power plant shall be calculated using the following formula:
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Where:
Qc(i):
Contracted electricity output of the power plant during trading interval i
(kWh);
α: Proportion of electricity output paid at the contract
price applicable to a renewable energy power plant, as prescribed by the
Ministry of Industry and Trade of Vietnam;
Qmq(i):
Electricity output at the metering location during trading interval i (kWh).
c) The
payment under the power purchase agreement of the power plant shall be
calculated based on the contracted electricity output prescribed in Point a of
this Clause and using the formula prescribed in Article 97 of this Circular.
Article
105. Other payments to power plants having contracts with EVN
1. Where
the monthly metered electricity output provided by the electricity metering
data management unit in accordance with Clause 2 Article 83 of this Circular
differs from the total daily metered electricity output for that month provided
by the electricity metering data management unit in accordance with Clause 1
Article 83 of this Circular, the difference in electricity output shall be paid
in accordance with the power purchase agreement entered into between EVN and
the generation unit.
2. Where
a thermal generating unit is required to shut down or to shut down one boiler
to reduce its output in accordance with Clause 3 Article 67 of this Circular,
or where a transmission line is under repair or construction, the start-up
costs shall be paid as agreed in the power purchase agreement between EVN and
the generation unit. The power system and electricity market operation unit
shall confirm such event for the generating unit, as notified by the generation
unit, so that the electricity purchasing unit may use such confirmation as the
basis for paying the start-up costs.
3. Where
a power plant has a generating unit undergoing testing, the entire power plant
shall be excluded from the electricity market during the testing intervals. The
entire electricity output delivered by the power plant to the grid during the
testing intervals shall be paid in accordance with the power purchase agreement
with EVN corresponding to the generating unit configuration and type of fuel
used.
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5. Where
a power plant has a generating unit disconnected from the grid and operating in
islanded mode at the request of the power system and electricity market
operation unit, the entire electricity output of the power plant during the
relevant trading intervals shall be paid in accordance with the power purchase
agreement with EVN.
6. Where
a power plant has a generating unit disconnected from the national power system
and connected to a grid importing electricity from abroad, based on the results
of the year-ahead power system operation calculations of the power system and
electricity market operation unit, the participation of such power plant in the
electricity market in the following year and payments to such power plant shall
be regulated as follows:
a) Where
a hydropower plant with a reservoir having a regulating capacity of less than 2
days is scheduled to connect to a grid importing electricity from abroad, the
entire power plant shall be excluded from the electricity market and shall participate
indirectly in the electricity market in the following year. The entire electricity
output of the power plant in the following year shall be paid at the
electricity price specified in the power purchase agreement entered into with EVN;
b) Except
for the case prescribed in Point a of this Clause, where, during the operating
year, a power plant has a generating unit connected to a grid importing
electricity from abroad, the entire electricity output of the power plant on
any trading day containing a trading interval during which such generating unit
is connected to the grid importing electricity from abroad shall be paid at the
electricity price specified in the power purchase agreement entered into with EVN.
7. Where
a hydropower generating unit is required by the power system and electricity market
operation unit, for reasons of ensuring electricity supply, to generate at a
capacity greater than its declared capacity in the scheduling offer for the
next trading interval, the entire electricity output delivered by the power
plant to the grid during such period shall be paid in accordance with the power
purchase agreement with EVN.
8. The
power system and electricity market operation unit shall provide complete and
timely information concerning the operation of BOT power plants, imported power
plants, and power plants providing auxiliary services at EVN's request, for
payment purposes in accordance with the power purchase agreements between EVN
and the relevant generation units. The information to be provided is specified
in detail in Appendix III enclosed with this Circular.
Article
106. Other payments to power plants having direct contracts with electricity
wholesale units
1. Other
payments to a power plant having a direct contract with an electricity
wholesale unit include:
a) The
difference between the monthly metered electricity output provided by the electricity
metering data management unit in accordance with Clause 2 Article 83 of this
Circular and the total metered electricity output of all trading intervals in
the month provided by the electricity metering data management unit in accordance
with Clause 1 Article 83 of this Circular shall be paid as agreed in the power
purchase agreement entered into between the electricity wholesale unit and the generation
unit;
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c) Where
a power plant has a generating unit undergoing testing, the entire power plant
shall be excluded from the electricity market during the testing intervals. The
entire electricity output delivered by the power plant to the grid during the
testing intervals shall be paid as agreed in the power purchase agreements with
the electricity wholesale unit corresponding to the generating unit
configuration and type of fuel used;
d) Where
a power plant has a generating unit undergoing AGC system testing at the
request of the power system and electricity market operation unit, the entire
power plant shall be excluded from the electricity market, and the entire
electricity output delivered by the power plant to the grid during the testing
intervals shall be paid in accordance with the power purchase agreement with
the electricity wholesale unit. Before December 1 of Year N−1, the power system
and electricity market operation unit shall prepare and announce to the electricity
market participants the list of generating units expected to undergo AGC system
testing in Year N;
dd) Taxes
and fees payable to a power plant having direct contracts with electricity
wholesale units during the monthly settlement cycle M, including water resource
tax, forest environmental service fees, environmental protection fees for
industrial wastewater, payments for the use of sea areas for dumping dredged
materials, land rent, and other taxes and fees, if any;
e) Where
a generating unit has an approved outage schedule but is still required to
generate electricity at the request of the power system and electricity market
operation unit to ensure electricity supply, the entire power plant shall be
excluded from the electricity market for the period during which it generates
electricity at the request of the power system and electricity market operation
unit. The entire electricity output delivered by the power plant to the grid
during such period shall be paid as agreed in the power purchase agreement
between the electricity wholesale unit and the generation unit;
g) Where
a power plant has a generating unit disconnected from the grid and operating in
islanded mode at the request of the power system and electricity market
operation unit, the entire electricity output of the power plant during the
relevant trading intervals shall be paid as agreed in the power purchase
agreement between the electricity wholesale unit and the generation unit;
h) Where
a power plant has a generating unit disconnected from the national power system
and connected to a grid importing electricity from abroad, based on the results
of the year-ahead power system operation calculations of the power system and
electricity market operation unit, the participation of such power plant in the
electricity market in the following year and payments to such power plant shall
be regulated as follows:
- Where a
hydropower plant with a reservoir having a regulating capacity of less than 2
days is scheduled to connect to a grid importing electricity from abroad, the
entire power plant shall be excluded from the electricity market and shall participate
indirectly in the electricity market in the following year. The entire
electricity output of the power plant in the following year shall be paid at
the electricity price specified in the power purchase agreement between the electricity
wholesale unit and the generation unit;
- Except
for the case prescribed in Point a of this Clause, where, during the operating
year, a power plant has a generating unit connected to a grid importing
electricity from abroad, the entire electricity output of the power plant on
any trading day containing a trading interval during which such generating unit
is connected to the grid importing electricity from abroad shall be paid at the
electricity price specified in the power purchase agreement between the electricity
wholesale unit and the generation unit.
i) Where
a hydropower generating unit is required by the power system and electricity market
operation unit, for reasons of ensuring electricity supply, to generate at a
capacity greater than its declared capacity in the scheduling offer for the
next trading interval, the entire electricity output delivered by the power
plant to the grid during such period shall be paid as agreed in the power
purchase agreement between the electricity wholesale unit and the generation
unit.
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Where:
L: Total
number of electricity wholesale units;
Rkh(l,g,M):
Other payment allocated to electricity wholesale unit l from power plant g
having a direct power purchase agreement during the monthly settlement cycle M,
as agreed in the power purchase agreement between the two parties (VND);
Rkh(g,M):
Total other payments prescribed in Clause 1 of this Article for power plant g
having a direct power purchase agreement with an electricity wholesale unit
during monthly settlement cycle M (VND);
Q(l,M):
Electricity output delivered and received by electricity wholesale unit l
during the monthly settlement cycle M (kWh).
3. The other payments
prescribed in Points c and d Clause 1 of this Article shall be allocated among
the electricity wholesale units in proportion to their electricity output
delivered and received during the relevant trading interval, as announced by
the power system and electricity market operation unit, and determined using
the following formula:
Where:
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i: A trading interval within the period during which power
plant g experiences an event prescribed in Point c or d Clause 1 of this
Article;
Rkh (l,
g, i): Other
payment prescribed in Point c or d Clause 1 of this Article allocated to electricity
wholesale unit l during trading interval i (VND);
Q(l,
i): Electricity output delivered and
received by electricity wholesale unit l during trading interval i (kWh).
Article
107. Payments during intervention in electricity market
1. Where
an intervention in the electricity market occurs as prescribed in Article 71 of
this Circular, the electricity purchasing unit shall make payments to a generation
unit having a direct contract as agreed in the power purchase agreement. The power
system and electricity market operation unit shall confirm the relevant event
so that the generation unit may complete the payment dossier for submission to
the electricity purchasing unit.
2. Where
the dispatch schedules of power plants are adjusted to ensure electricity
supply as prescribed in Clause 2 Article 71 of this Circular, the power system
and electricity market operation unit, the electricity purchasing unit, and the
generation unit shall calculate and make payments in accordance with Articles
95, 96, and 97 of this Circular.
Article
108. Payments during suspension of spot electricity market
During
the suspension of the spot electricity market, the electricity purchasing unit
shall make payments to a generation unit having a direct contract as agreed in
the power purchase agreement. The power system and electricity market operation
unit shall confirm the relevant event so that the generation unit may complete
the payment dossier for submission to the electricity purchasing unit.
Section 4. PAYMENT PROCEDURES
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Before 09:00
on Day D+2, the power system and electricity market operation unit shall
compile and provide the electricity purchasing unit and the generation units
with data used for calculating payments for each power plant.
Article
110. Electricity market payment statements for trading days
1. Before
16:00 on Day D+4, the power system and electricity market operation unit shall
prepare and send the preliminary electricity market payment statement for
Trading Day D to the generation units through the Electricity Market Web Portal,
using Form No. 14 in Appendix VI enclosed with this Circular.
2. Before
16:00 on Day D+5, the power system and electricity market operation unit shall
prepare and send the spot electricity market payment statement for Day D to the
electricity purchasing units through the Electricity Market Web Portal, using
Form No. 14 in Appendix VI enclosed with this Circular.
3. Before
12:00 on Day D+6, the direct trading generation units and the electricity
purchasing units shall confirm the electricity market payment statement on the Electricity
Market Web Portal in accordance with regulations and notify the power system
and electricity market operation unit of any errors in the preliminary
electricity market payment statement.
2. Before
16:00 on Day D+6, the power system and electricity market operation unit shall
prepare and send the finalized electricity market payment statement for Day D
to the electricity purchasing unit and the generation units through the Electricity
Market Web Portal, using Form No. 14 in Appendix VI enclosed with this
Circular. The generation unit shall issue the daily payment statement and
include it in the payment dossier for the settlement cycle.
Article
111. Electricity market payment statements for settlement cycles
1. The power
system and electricity market operation unit shall compile payment data for the
trading days within the settlement cycle and verify and reconcile such data
against the record summarizing electricity output provided by the electricity
metering data management unit.
2. Within
10 working days from the last trading day of the settlement cycle, the power system
and electricity market operation unit shall announce:
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b) The
total electricity output delivered and received at the upstream connection
points of each electricity wholesale unit and the proportion of electricity
output delivered and received at the upstream connection points of the electricity
wholesale unit, calculated in accordance with Clause 2 Article 106 of this
Circular.
3. Within
13 working days from the last trading day of the settlement cycle, the power
system and electricity market operation unit shall prepare and issue the
electricity market payment statement for the settlement cycle to the electricity
purchasing unit and the generation unit.
4. The
electricity market payment statement for the settlement cycle shall include the
summary tables made according to Forms No. 14 and No. 15 in Appendix VI
enclosed with this Circular and the record confirming meter readings and
electricity output.
3. Method
of confirming payment statements and electricity market events: The direct
trading generation units, the electricity purchasing units, and the power system
and electricity market operation unit shall use digital signatures to confirm
and issue electricity market payment statements and confirm electricity market
events. Where a digital signature system experiences an incident, the electricity
purchasing unit and the power system and electricity market operation unit
shall directly confirm and issue the electricity market payment statements and
confirm the electricity market events, and shall reconfirm them after the
incident has been remedied.
Article
112. Payment dossier
1. A
direct trading generation unit shall prepare and send electricity market
payment documents to the electricity purchasing unit based on the electricity
market payment statement for the settlement cycle.
2. A
direct trading generation unit shall prepare and send documents for the
contract-for-difference payment to the electricity purchasing unit in
accordance with the agreement in the power purchase agreement concluded between
the electricity purchasing unit and the generation unit.
3. A
direct trading generation unit shall prepare and send a payment invoice to the electricity
purchasing unit in accordance with the power purchase agreement. The payment
invoice shall include electricity market payments and contract-for-difference
payments for the settlement cycle.
Article
113. Payment dossiers for auxiliary service agreements and other payments
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Article
114. Invoice adjustments
1. Where
an invoice contains errors, the generation unit or the electricity purchasing
unit may request that such errors be handled in accordance with the power
purchase agreement and relevant regulations within 1 month from the date of
issuance. The relevant parties shall cooperate in determining and agreeing on
the adjustment payments.
2. The generation
unit shall include the adjustment payment in the invoice for the following
settlement cycle.
Article
115. Payment
1. The electricity
purchasing unit shall make payment in accordance with the invoice issued by the
generation unit. The payment deadline shall be determined in accordance with
the power purchase agreement concluded between the two parties.
2. The generation
unit and the electricity purchasing unit shall agree on the payment method in
the electricity market in conformity with this Circular and relevant regulations.
3. By the
20th day of each month, where the generation unit has not received the
electricity market payment statement for reasons not attributable to the generation
unit, the generation unit may prepare and send a provisional dossier and
payment invoice based on the generated electricity output and the electricity
price specified in the concluded power purchase agreement. After the
electricity market payment statement is issued, the difference between the
provisional payment amount and the final settlement amount shall be offset in
the following month.
4. Where
the electricity purchasing unit fails to make payment by the payment deadline,
interest shall accrue on the overdue electricity payment at the interest rate
agreed by the two parties in the concluded power purchase agreement.
Article
116. Handling of payment errors
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Article
117. Payments under power purchase agreements between EVN and electricity
wholesale units
Payments
under the power purchase agreement between EVN and an electricity wholesale
unit shall include:
1. The
spot electricity market payment between EVN and the electricity wholesale unit
for power plants with allocated contracts, as prescribed in Clause 1 Article 99
of this Circular.
2. The
contract-for-difference payment under the power purchase agreement between EVN
and the electricity wholesale unit for power plants with allocated contracts,
calculated in accordance with Article 100 of this Circular.
3. Payment
by EVN to the electricity wholesale unit at the wholesale electricity price for
the remaining electricity output delivered and received at the upstream
connection points after deducting the output paid in accordance with Article
98, Point c Clause 1 Article 106, Article 107, and Article 108 of this
Circular.
4. Other
payments as agreed in the power purchase agreement.
Chapter
IX
INFORMATION TECHNOLOGY SYSTEM SERVING
ELECTRICITY MARKET OPERATION
Article
118. Software for electricity market operation
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a) Market
simulation software;
b) Water
value calculation software;
c)
Dispatch scheduling software;
d)
Software serving payment calculations;
dd) Other
software serving electricity market operation.
2. The
power system and electricity market operation unit shall develop and operate
software serving the electricity market.
Article
119. Requirements for software for electricity market operation
1. Software
shall ensure accuracy, reliability, and security and satisfy the standards
developed by the power system and electricity market operation unit.
2. Software
shall be accompanied by complete technical instructions and operating
procedures.
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1. Software
for electricity market operation shall be developed to support the calculations
and transactions prescribed in this Circular and the electricity market
operating procedures.
2. The
power system and electricity market operation unit shall:
a)
Develop standards for software for electricity market operation;
b)
Appraise and inspect the software’s compliance with the standards prescribed in
Point a of this Clause before it is put into use;
c)
Announce the list, algorithms, and procedures for using software for
electricity market operation.
Article
121. Software audit
1. Software
serving the electricity market shall be audited in the following cases:
a) Before
the electricity market officially commences operation;
b) Before
new software is put into use;
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d)
Periodically.
2. The
power system and electricity market operation unit shall propose a qualified
independent audit unit to conduct the audit and report such matters to the
Electricity Authority of Vietnam before the audit is conducted.
3. The power
system and electricity market operation unit shall announce the audit results
to the electricity market participants.
Article
122. Structure of electricity market information system
The
electricity market information system includes the following basic components:
1. Hardware
and software systems serving the management, exchange, and security of
electricity market information.
2. Database
and data storage systems.
3. The
electronic information portal serving the electricity market, including the
internal website and the public website.
Article
123. Management and operation of electricity market information system
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2. The electricity
market participants shall invest in equipment within their respective management
scopes that satisfies the technical requirements prescribed by the power system
and electricity market operation unit, thereby ensuring connection to the
electricity market information system.
3. The electricity
metering data management unit shall develop, manage, and operate the
transmission network connecting the electricity market information system of
the power system and electricity market operation unit with the equipment of
the electricity market participants.
4. The
power system and electricity market operation unit may only operate or modify
the existing electricity market information system after it has been fully
accepted and approved by the Electricity Authority of Vietnam.
5. The
power system and electricity market operation unit shall equip the electricity
market information system with backup equipment to ensure that market
information can be collected, transmitted, and announced where the main
electricity market information system experiences an incident or cannot be
operated.
6. The
power system and electricity market operation unit shall develop and manage an
information security system to ensure the safety and confidentiality of
electricity market information.
Article
124. Provision and announcement of electricity market information
1. The generation
units, electricity wholesale units, transmission units, distribution units, and
electricity metering data management units shall provide the power system and
electricity market operation unit with information and data serving calculations
of contracted electricity output allocation, annual load forecasting, operation
planning, dispatch scheduling, and payment calculations in accordance with this
Circular through the web portal of the electricity market information system.
2. The
power system and electricity market operation unit shall provide and announce
information, data, and electricity market operation reports to the electricity
market participants in accordance with this Circular through the web portal of
the electricity market information system.
3. Levels
of access authorization shall be determined according to the functions of the
units and prescribed in the procedures for management and operation of the
information technology system for electricity market administration in Appendix
V enclosed with this Circular.
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a)
Information on the electricity market participants;
b) Load
data for each region and the system;
c) Data
on generation capacity by generation technology type and for the entire power
system;
d)
Statistical data on market prices;
dd) Other
information prescribed in the procedures for management and operation of the
information technology system for electricity market administration in Appendix
V enclosed with this Circular.
Article
125. Responsibility for ensuring accuracy of electricity market information
1. An electricity
market participant shall ensure the accuracy and completeness of electricity
market information at the time of provision.
2. Where
information already provided or announced is found to be inaccurate or
incomplete, the electricity market participant shall correct such information
and provide the accurate information again to the relevant unit.
Article
126. Confidentiality of electricity market information
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a)
Information on power purchase agreements;
b) Price
offers of a generation unit before the end of the trading day;
c) Other
information beyond its authority to disclose.
2. An electricity
market participant shall not disclose information beyond the scope that it is
authorized to provide and announce.
Article
127. Exemptions from electricity market information confidentiality
1. Information
may be provided at the request of the Electricity Authority of Vietnam or a
competent authority in accordance with the law.
2. Information
independently compiled and analyzed from information announced in the electricity
market, provided that it was not improperly supplied by other electricity
market participants in violation of Article 126 of this Circular.
Article
128. Retention of electricity market information
The power
system and electricity market operation unit shall retain records of all
information exchange activities conducted through the electricity market
information system. Such information shall be retained for at least 5 years.
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SUPERVISION OF ELECTRICITY MARKET
OPERATION
Article
129. Responsibilities for electricity market supervision
1. The
Electricity Authority of Vietnam shall conduct regular and periodic supervision
of electricity market operations by compiling and assessing operational results
based on collected data and on-site inspections of electricity market
participants. Electricity market supervision shall include:
a)
Results of electricity market operation;
b)
Assessment of compliance by the electricity market participants with
electricity market regulations.
2. The
electricity market participants shall cooperate with the Electricity Authority
of Vietnam in supervising the electricity market, and detect and report to the
Electricity Authority of Vietnam any arising issues and acts showing signs of
violations during electricity market operation.
Article
130. Announcement of electricity market operation information
The power
system and electricity market operation unit shall periodically announce
electricity market operation information in accordance with the procedures for
management and operation of the information technology system for electricity
market administration in Appendix V enclosed with this Circular, according to
the following schedule:
1. Before
15:00 each day, announce the electricity market operation report for the
preceding day.
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3. Before
the 20th day of each month, announce the electricity market operation report
for the preceding month.
4. Before
January 31 each year, announce the electricity market operation report for the
preceding year.
Article
131. Provision of data serving supervision of electricity market operation
1. Provision
of data serving supervision of electricity market operation:
a) The
power system and electricity market operation unit shall provide the Electricity
Authority of Vietnam with information and data on electricity market operation,
including:
- Data
and calculation results of annual, monthly, and weekly electricity market
operation plans;
- Data
and results of day-ahead, next-interval, and real-time electricity market
operation and payment calculations;
- Other
necessary information and data at the request of the Electricity Authority of
Vietnam for electricity market supervision.
b) An electricity
market participant shall provide information and data relating to its
activities in the electricity market at the request of the Electricity
Authority of Vietnam for electricity market supervision.
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a) The
power system and electricity market operation unit shall provide information to
the Electricity Authority of Vietnam by the following methods:
- Automatic
online synchronization between the electricity market database of the power system
and electricity market operation unit and the electricity market supervision
database of the Electricity Authority of Vietnam. The list of electricity
market information and data to be synchronized shall be prescribed by the Electricity
Authority of Vietnam;
- Where
the method of data provision prescribed in the first indent of this Point
cannot yet be applied, the power system and electricity market operation unit
shall prepare and send electricity market data files in the formats, forms, and
according to the schedule prescribed by the Electricity Authority of Vietnam.
b) An electricity
market participant shall provide information and data in written form or as
data files made according to the prescribed forms at the request of the Electricity
Authority of Vietnam.
3. Data
quality assurance
a) The
power system and electricity market operation unit shall ensure the quality of
data provided to the Electricity Authority of Vietnam, including daily reports,
weekly reports, and the contents of the electricity market database;
b) An electricity
market participant shall ensure the quality of data provided to the Electricity
Authority of Vietnam for investigation purposes, and such data shall be
certified as accurate by the data-providing unit.
Article
132. Electricity market operation reporting regulations
1. Monthly
electricity market operation reporting regulations applicable to the power system
and electricity market operation unit
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b) Report
contents: According to Form No. 01 in Appendix VI enclosed with this Circular;
c)
Reporting entity: The power system and electricity market operation unit;
d) Report
recipient: The Electricity Authority of Vietnam;
dd)
Method of report submission: Via the email system;
e) Report
submission deadline: Before the 20th day of Month M+1, the report on
electricity market operation for Month M shall be submitted;
g)
Reporting frequency: Monthly.
2. Annual
electricity market operation reporting regulations applicable to the power system
and electricity market operation unit
a) Report
title: Electricity Market Operation Report for Year N;
b) Report
contents: According to Form No. 02 in Appendix VI enclosed with this Circular;
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d) Report
recipient: The Electricity Authority of Vietnam;
dd)
Method of report submission: The report shall be submitted to the report
recipient by one of the following methods:
- Via the
electronic office system (E-office);
- Via the
email system;
- By
postal service.
e) Report
submission deadline: Before March 1 of Year N+1, the report on electricity
market operation for Year N shall be submitted;
g)
Reporting frequency: Annually.
3. Annual
electricity market operation reporting regulations applicable to direct trading
generation units
a) Report
title: Electricity Market Operation Report for Year N;
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c)
Reporting entities: Direct trading generation units;
d) Report
recipient: The Electricity Authority of Vietnam;
dd)
Method of report submission: The report shall be submitted to the report
recipient by one of the following methods:
- Via the
email system;
- By postal
service.
e) Report
submission deadline: Before March 1 of Year N+1, the report on electricity
market operation for Year N shall be submitted;
g)
Reporting frequency: Annually.
4. Annual
electricity market operation reporting regulations applicable to electricity
purchasing units
a) Report
title: Electricity Market Operation Report for Year N;
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c)
Reporting entities: Electricity purchasing units participating in the competitive
wholesale electricity market;
d) Report
recipient: The Electricity Authority of Vietnam;
dd)
Method of report submission: The report shall be submitted to the report
recipient by one of the following methods:
- Via the
email system;
- By
postal service.
e) Report
submission deadline: Before March 1 of Year N+1, the report on electricity
market operation for Year N shall be submitted;
g)
Reporting frequency: Annually.
5. Ad hoc
reports
a) Ad hoc
report upon the occurrence of electricity market intervention
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- Report
contents upon the occurrence of electricity market intervention: A detailed
report on the electricity market intervention event, including the time,
causes, intervention measures, and assessment of impacts;
- Reporting
entity: The power system and electricity market operation unit;
- Report
recipient: The Electricity Authority of Vietnam;
- Method
of report submission: Via the email system;
- Report
submission deadline: Within 24 hours from the time of electricity market
intervention.
b) The
power system and electricity market operation unit, the generation units, and
the electricity purchasing units shall submit ad hoc reports on electricity
market operation at the request of the Electricity Authority of Vietnam.
Article
133. Audit of electricity market data and compliance
1. Periodic
audit
Before
March 31 each year, the power system and electricity market operation unit
shall organize and complete the audit of electricity market data and compliance
for the preceding year. The annual audit of data and the calculation process
performed by the power system and electricity market operation unit in the electricity
market shall include:
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b)
Calculation steps;
c)
Calculation results;
d)
Compliance by the power system and electricity market operation unit with the
procedures prescribed in this Circular.
2. Ad hoc
audit
The Electricity
Authority of Vietnam may require the power system and electricity market
operation unit to organize an ad hoc audit with specific audit contents and
scope in the following cases:
a) Where
signs of abnormalities in electricity market operation are detected;
b) At the
written request of an electricity market participant, clearly stating the
contents of and reasonable grounds for requesting the ad hoc audit.
3. The
power system and electricity market operation unit shall propose a qualified
independent audit unit to perform the electricity market audit and submit such
proposal to the Electricity Authority of Vietnam for approval.
4. The electricity
market participants shall cooperate during the electricity market audit.
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a) The
power system and electricity market operation unit shall pay the audit costs in
the cases prescribed in Clause 1 and Point a Clause 2 of this Article;
b) The
unit requesting the audit shall pay the audit costs in the case prescribed in
Point b Clause 2 of this Article.
6. Within
10 days from receipt of the audit report submitted by the audit unit, the power
system and electricity market operation unit shall send it to the Electricity
Authority of Vietnam and the relevant units.
Chapter
XI
IMPLEMENTATION
Article
134. Responsibilities of Electricity Authority of Vietnam
1. Disseminate,
inspect, and supervise the implementation of this Circular.
2. Promulgate,
or submit to the Ministry’s leadership for promulgation, documents guiding the
implementation of power purchase agreements that were entered into or were
under negotiation before this Circular takes effect.
3. Promulgate,
or submit to the Ministry’s leadership for promulgation, documents providing
guidance on newly arising matters and difficulties during implementation.
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1. Invest
in, develop, install, and upgrade the electricity market information system and
software serving the electricity market in conformity with the requirements
prescribed in this Circular.
2. Issue
specific regulations on the tasks, entitlements, standards, working
regulations, and working relationships applicable to the position of
Electricity Market Trading Operation Engineer of the unit in conformity with
Articles 136, 137, 138, and 139 of this Circular; and organize training,
examinations, and recognition of such position for participation in electricity
market trading operation.
3. Guide
electricity market participants on the procedures for registering participation
in the electricity market in accordance with this Circular and upgrade the
Electricity Market Web Portal to enable generation units to apply for
participation in the electricity market online.
4. Be
responsible for compiling information provided by the units for input into the
electricity market simulation model, calculation outputs, and information
announced on the web portal serving the electricity market, ensuring accuracy,
reliability, and a practical basis in accordance with this Circular.
5. Develop
databases and provide and synchronize operational data between the power system
and electricity market operation unit and the Electricity Authority of Vietnam
to serve the supervision and assessment by the Electricity Authority of Vietnam
of the power system and electricity market operation.
6. Equip
itself with the tools and data necessary for operation planning, dispatch
scheduling, and real-time operation, including weather, meteorological, and
hydrological data for forecasting hydropower output based on inflows; renewable
energy forecasts, including capacity, output, and relevant meteorological
factors; and calculation and simulation data estimating real-time solar
irradiance from sources such as satellite cloud imagery to serve the monitoring
of rooftop solar power capacity.
Article
136. Tasks and entitlements of Electricity Market Trading Operation Engineers
1. Tasks
a) Ensure
fair and transparent electricity market operation in compliance with
regulations on power system and electricity market operation promulgated by the
Ministry of Industry and Trade of Vietnam;
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c)
Prepare year-ahead and month-ahead electricity market operation plans,
week-ahead power system and electricity market operation plans, and day-ahead,
intra-day, and next-trading-interval power source dispatch schedules, including
direct trading units and indirect trading units, in accordance with this
Circular;
d) Notify
generation units and fuel suppliers of forecast gas demand during the
preparation of week-ahead operation plans and day-ahead, intra-day, and
next-trading-interval dispatch schedules;
dd)
Announce day-ahead, intra-day, and next-trading-interval dispatch information
on the power system and electricity market website in accordance with regulations;
e)
Calculate and assess the available generation capacity of the national power
system and regional power systems, and cooperate with relevant units in
implementing measures to ensure supply-demand balance and electricity supply;
g)
Calculate payments for the electricity market participants in accordance with
this Circular;
h)
Perform other tasks specifically prescribed by the power system and electricity
market operation unit, ensuring conformity with this Circular and other
relevant laws.
2. Entitlements
a)
Request the operation management unit and relevant units to provide information
serving power system operation and electricity market administration in
accordance with this Circular and other relevant laws;
b)
Cooperate with national load dispatchers, on-duty renewable energy engineers,
and regional load dispatchers in updating real-time operational information
serving power source dispatch scheduling;
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d)
Exercise other entitlements specifically prescribed by the power system and
electricity market operation unit, ensuring conformity with this Circular and
other relevant laws.
Article
137. Regulations on training for position of Electricity Market Trading
Operation Engineer
1. Regulations
on recruitment and training for the position of Electricity Market Trading
Operation Engineer:
a) The power
system and electricity market operation unit shall organize the recruitment and
training of human resources serving electricity market operation. A person
nominated for training shall fully satisfy the conditions prescribed in Article
138 of this Circular and other conditions prescribed by the power system and
electricity market operation unit in conformity with the position and tasks to
be assigned after completion of the training;
b) The
power system and electricity market operation unit shall organize training,
refresher training, and advanced training for Electricity Market Trading
Operation Engineers and shall specifically prescribe the duration and contents
of such training.
2. After
the prescribed training contents and duration have been fully completed, the power
system and electricity market operation unit shall organize an examination and
issue an Operation Certificate to the Electricity Market Trading Operation
Engineer according to the form prescribed in the regulations on standards and
working regulations applicable to the position of Electricity Market Trading
Operation Engineer.
3. After
recognizing the position of the person nominated for training, the power system
and electricity market operation unit shall notify the relevant units of the
newly recognized position of such Electricity Market Trading Operation
Engineer.
Article
138. Conditions applicable to persons nominated for training for position of
Electricity Market Trading Operation Engineer
1. Be a
Vietnamese citizen and reside in Vietnam.
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3. Have a
clear personal record and not be subject to criminal prosecution, serving a
criminal sentence, or labor disciplinary action.
4. Be no
more than 30 years of age in the case of new recruitment, or no more than 40
years of age in other cases specifically prescribed by the power system and
electricity market operation unit.
5. Meet
the foreign-language and information-technology proficiency requirements
prescribed by the power system and electricity market operation unit.
6. Be
physically fit to work in shifts.
7. Satisfy
other conditions prescribed by the power system and electricity market
operation unit for each specific period.
Article
139. Working regulations and working relationships in power system operation
and electricity market administration
1. Working
regulations:
a) The
assignment and organization of electricity market operation shifts and the
calculation and preparation of power system and electricity market operation
plans for Electricity Market Trading Operation Engineers shall ensure the
continuous, safe, and efficient operation of the power system and electricity
market and comply with regulations on power system and electricity market
operation promulgated by the Ministry of Industry and Trade of Vietnam;
b)
Depending on the level of development, design, and infrastructure of the
electricity market and the requirements for calculation and preparation of
power system and electricity market operation plans, the power system and
electricity market operation unit shall specify the number of Electricity
Market Trading Operation Engineers in each shift performing operation-planning
calculations, which shall not be fewer than 2;
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d) The
salary, bonuses, remuneration, and allowances of Electricity Market Trading
Operation Engineers shall be graded according to the respective levels
applicable to the highest operational position within the power system and
electricity market operation unit.
2. Relationship
between the leadership of the power system and electricity market operation
unit and Electricity Market Trading Operation Engineers:
a) The
leader directly responsible for electricity market operation within the power system
and electricity market operation unit may instruct Electricity Market Trading
Operation Engineers to perform relevant tasks during electricity market
administration, provided that such instructions do not contravene this Circular
or other relevant procedures and regulations;
b) Where
an instruction of the leader directly responsible for electricity market
operation contravenes this Circular or other relevant procedures and
regulations, the Electricity Market Trading Operation Engineer may refuse to
implement such instruction, except where human life or equipment safety is
endangered. After implementing the leader’s instruction, the Electricity Market
Trading Operation Engineer shall fully record the instruction in the operation
log and shift handover log;
c) Where there
are sufficient grounds to determine that an Electricity Market Trading
Operation Engineer lacks the required operating capability, the leader directly
responsible for electricity market operation may temporarily suspend that
engineer from duty during the relevant shift and appoint another Electricity
Market Trading Operation Engineer as a replacement. The suspended Electricity
Market Trading Operation Engineer may leave the working position only after
fully handing over the operating situation to the replacement.
Article
140. Responsibilities of relevant units
1. Electricity
market participants shall complete their information equipment in conformity
with the electricity market information system in accordance with this
Circular.
2. A generation
unit participating in the electricity market shall enter into a power purchase
agreement in accordance with the regulations on methods for determining
electricity generation service prices; principles for calculating electricity
prices for implementation of power projects; and principal contents of power
purchase agreements promulgated by the Ministry of Industry and Trade of
Vietnam.
3. A
large electricity consumer participating in the direct power trading mechanism
shall comply with the regulations on the direct power trading mechanism and
other relevant laws.
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5. A generation
unit and a fuel supplier shall provide the power system and electricity market
operation unit with data on fuel supply capability, take-or-pay constraints,
and technical constraints of the primary fuel supply system for calculation of
the take-or-pay prescribed in Clause 78 Article 3 of this Circular, based on
the fuel consumption rate specified in the power purchase agreement.
Article
141. Transitional provisions
1. The
electricity market operation plan 2026, approved by the Ministry of Industry
and Trade of Vietnam, and the monthly electricity market operation plans for
2026, approved by the Electricity Authority of Vietnam, before the effective
date of this Circular, shall continue to apply. Where the power system and
electricity market operation unit considers it necessary to recalculate and
update the electricity market operation plan 2026 in accordance with this
Circular, it shall report to the Ministry of Industry and Trade of Vietnam for
consideration and decision.
2. Electricity
wholesale units currently participating in the competitive wholesale
electricity market shall continue to participate in accordance with this
Circular.
Article
142. Entry into force
1. This
Circular comes into force as of July 20, 2026.
2. Clause
2 Article 1 and Clause 51 Article 3 of this Circular shall take effect from the
date of its signing and promulgation.
3. Circular
No. 16/2025/TT-BCT dated February 1, 2025 of the Minister of Industry and Trade
of Vietnam and Circular No. 36/2025/TT-BCT dated June 3, 2025 of the Minister
of Industry and Trade of Vietnam are hereby annulled.
4. During
implementation, arising difficulties shall be reported to the Ministry of
Industry and Trade of Vietnam for implementation guidance or consideration of
appropriate amendments and supplements.
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PP. MINISTER
DEPUTY MINISTER
Nguyen Hoang Long