World Bank Document · ICR Team Leader Wendy Hughes – ICR Primary Author Wendy Hughes, Thomas...
Transcript of World Bank Document · ICR Team Leader Wendy Hughes – ICR Primary Author Wendy Hughes, Thomas...
Document of
The World Bank
Report No: ICR00003360
INTERNATIONAL BANK FOR RECONSTRUCTION AND DEVELOPMENT
AND
INTERNATIONAL DEVELOPMENT ASSOCIATION
IMPLEMENTATION COMPLETION AND RESULTS REPORT
(IDA-47110, IBRD-78680; IDA-50820, IBRD-81470; IBRD-83720)
ON A SERIES OF
THREE LOANS
IN THE AMOUNT OF US$500 MILLION
AND
TWO CREDITS
IN THE AMOUNT OF SDR 137.5 MILLION
(US$211.8 MILLION EQUIVALENT)
TO THE
SOCIALIST REPUBLIC OF VIETNAM
FOR A
FIRST, SECOND AND THIRD POWER SECTOR REFORM DEVELOPMENT
POLICY OPERATION
June 7, 2016
Energy & Extractives Global Practice
East Asia and Pacific Region
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VIETNAM GOVERNMENT FISCAL YEAR
January 1 – December 31
CURRENCY EQUIVALENTS
(Exchange Rate Effective as of February 2, 2010)
Currency Unit = Vietnamese Dong (VND)
US$1.00 = VND 18,474.5
(Exchange Rate Effective as of June 30, 2015)
Currency Unit = Vietnamese Dong (VND)
US$1.00 = VND 21,815
ABBREVIATIONS AND ACRONYMS
BOT Build, Operate, Transfer
CAN Capacity Add-on
DEP Distribution Efficiency Project
DPL Development Policy Lending
DPO Development Policy Operation
DSM Demand-side Management
DSR Demand-side Response
EE&C Energy Efficiency and Conservation
EPTC Electric Power Trading Company
ERAV Electricity Regulatory Authority of Vietnam
EVN Vietnam Electricity
GDP Gross Domestic Product
GENCO Generation Company
GoV Government of Vietnam
IOE Institute of Energy
IPP Independent Power Producer
ISR Implementation Status Report
LDU Local Distribution Utility
M&E Monitoring and Evaluation
MOF Ministry of Finance
MOIT Ministry of Industry and Trade
MOLISA Ministry of Labor, Invalids and Social Affairs
NLDC National Load Dispatch Center
NPTC National Power Transmission Company
ODA Official Development Assistance
OoG Office of Government
PC Power Corporation
PDO Program Development Objective
PM Prime Minister
PMP7 Power Master Plan VII
PPA Power Purchase Agreement
PSIA Poverty and Social Impact Analysis
PSRDPO Power Sector Reform Development Policy Operation
RD Rural Distribution Project
SB Single Buyer
SMHP Strategic Multipurpose Hydropower Plant
SMO System and Market Operator
SMP System Marginal Price
SO System Operator
SOE State-owned Enterprise
SPPA Standard Power Purchase Agreement
TA Technical Assistance
TD2 Second Transmission and Distribution Project
TOU Time Of Use
VCGM Vietnam Competitive Generation Market
VHLSS Vietnam Household Living Standards Survey
VNEEP Vietnam National Energy Efficiency Program
WEM Wholesale Electricity Market
WCM Wholesale Competitive Market
Vice President: Laura Tuck
Senior Global Practice Director: Anna M. Bjerde (acting)
Practice Manager: Julia M. Fraser
Project Team Leader: Pedro Antmann
ICR Team Leader: Wendy Hughes
VIETNAM
FIRST, SECOND, AND THIRD POWER SECTOR REFORM
DEVELOPMENT POLICY OPERATION (PSRDPO 1, 2, and 3)
TABLE OF CONTENTS
Data Sheet
A. Basic Information………………………………………………………………………….....i
B. Key Dates…………………………………………………………………………................ii
C. Ratings Summary…………………………………………………………………..………..ii
D. Sector and Theme Codes………………………………………………………………..…..iii
E. Bank Staff……………………………………………………………………….…………..iv
F. Results Framework Analysis…………………………………………………….…………..v
G. Ratings of Program Performance in ISRs…………………………………….……...…….xii
H. Restructuring…………………………………………………………………….…………xii
1. Program Context, Development Objectives and Design……………………………..………1
1.1 Context at Appraisal………………………………………………………………….……1
1.2 Original Program Development Objectives (PDO) and Key Indicators (as approved)……8
1.3 Revised PDO (as approved by original approving authority) and Key Indicators and
Reasons/Justification………..…………………………………………...…………………….9
1.4 Original Policy Areas Supported by the Program (as approved)………………………….10
1.5 Revised Policy Areas (if applicable)……………………………………………………..11
1.6 Other significant changes…………...……………………………………………………12
2. Key Factors Affecting Implementation and Outcomes……………………………………...12
2.1 Program Performance.........................................................................................................12
2.2 Major Factors Affecting Implementation……………… ………………………………..15
2.3 Monitoring and Evaluation (M&E) Design, Implementation, and Utilization…………...16
2.4 Expected Next Phase/Follow-up Operation (if any)……………………………………...17
3. Assessment of Outcomes……………………………………………………………………18
3.1 Relevance of Objectives, Design and Implementation…………………… …..………18
3.2 Achievement of Program Development Objectives……..… …………………………19
3.3 Justification of Overall Outcome Rating……………… ...……………………………48
3.4 Overarching Themes, Other Outcomes, and Impacts… ………………………………48
4. Assessment of Risk to Development Outcome………………………....……………....…..49
5. Assessment of Bank and Borrower Perfrmance……………...…………………………….51
5.1 Bank Performance ……………………………………………………………………..51
5.2 Borrower Performance……………,………………………………...…………………52
6. Lessons Learned………………………………………………….…………………………53
7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners………...…….56
Annex 1. Bank Lending and Implementation Support/Supervision Processes……………….57
Annex 2. Intermediate Outcome Indicators…………………………………………………...60
Annex 3. Summary of Borrower's ICR and/or Comments on Draft ICR………………...…...66
Annex 4. Program Performance: Prior actions and Evidence of their Fulfilment…………….77
Annex 5. Prior Actions and Indicative Triggers for each PSRDPO……………………...…...79
Annex 6. PDO indicators from Results Matrix of each PSRDPO…………...………………..83
Annex 7. Overview of the Conceptual Design of the VCGM………………………………...85
Annex 8. List of Supporting Documents………..…………………………….………………89
i
A. Basic Information
Program 1
Country Vietnam Program Name
Vietnam Power Sector
Reform Development Policy
Operation
Program ID P115874 L/C/TF Number(s) IBRD-78680, IDA-47110
ICR Date 06/07/2016 ICR Type Core ICR
Lending Instrument Development Policy
Lending (DPL) Borrower Socialist Republic of Vietnam
Original Total
Commitment US$311.80 million Disbursed Amount US$312.15 million
Implementing Agencies
Electricity Regulatory Authority of Vietnam (ERAV)
Cofinanciers and Other External Partners
Program 2
Country Vietnam Program Name Vietnam Power Sector
Reform DPO2
Program ID P124174 L/C/TF Number(s) IBRD-81470, IDA-50820,
IBRD-78680, IDA-47110
ICR Date 06/07/2016 ICR Type Core ICR
Lending Instrument DPL Borrower Socialist Republic of Vietnam
Original Total
Commitment US$200.00 million Disbursed Amount US$199.49 million
Implementing Agencies
Electricity Regulatory Authority of Vietnam (ERAV - MOIT)
Cofinanciers and Other External Partners
Program 3
Country Vietnam Program Name Vietnam Power Sector
Reform DPO3
Program ID P144675 L/C/TF Number(s) IBRD-83720, IBRD-81470,
IDA-50820
ICR Date 06/07/2016 ICR Type Core ICR
Lending Instrument DPL Borrower Socialist Republic of Vietnam
Original Total
Commitment US$200.00 million Disbursed Amount US$200.00 million
Implementing Agencies
Electricity Regulatory Authority of Vietnam (ERAV - MOIT)
ii
Cofinanciers and Other External Partners
B. Key Dates
Vietnam Power Sector Reform Development Policy Operation - P115874
Process Date Process Original Date Revised / Actual
Date(s)
Concept Review: 07/21/2009 Effectiveness: 08/13/2010 09/23/2010
Appraisal: 02/02/2010 Restructuring(s):
Approval: 04/06/2010 Midterm Review:
Closing: 08/31/2011 08/31/2011
Vietnam Power Sector Reform DPO2 - P124174
Process Date Process Original Date Revised / Actual
Date(s)
Concept Review: 07/11/2011 Effectiveness: 08/22/2012 08/09/2012
Appraisal: 01/18/2012 Restructuring(s):
Approval: 03/22/2012 Midterm Review:
Closing: 07/31/2013 07/31/2013
Vietnam Power Sector Reform DPO3 - P144675
Process Date Process Original Date Revised / Actual
Date(s)
Concept Review: 05/24/2013 Effectiveness: 10/30/2014 10/30/2014
Appraisal: 10/24/2013 Restructuring(s):
Approval: 06/30/2014 Midterm Review:
Closing: 07/31/2015 07/31/2015
C. Ratings Summary
C.1 Performance Rating by ICR
Overall Program Rating
Outcomes Moderately Satisfactory
Risk to Development Outcome Significant
Bank Performance Moderately Satisfactory
Borrower Performance Moderately Satisfactory
C.2 Detailed Ratings of Bank and Borrower Performance (by ICR)
Overall Program Rating
Bank Ratings Borrower Ratings
Quality at Entry Moderately Satisfactory Government: Moderately Satisfactory
Quality of Supervision: Moderately Satisfactory Implementing
Agency/Agencies: Satisfactory
Overall Bank
Performance Moderately Satisfactory
Overall Borrower
Performance Moderately Satisfactory
iii
C.3 Quality at Entry and Implementation Performance Indicators
Vietnam Power Sector Reform Development Policy Operation - P115874
Implementation
Performance Indicators
QAG Assessments
(if any) Rating:
Potential Problem
Program at any time
(Yes/No):
No Quality at Entry
(QEA) None
Problem Program at any
time (Yes/No): No
Quality of
Supervision (QSA) None
DO rating before
Closing/Inactive status Satisfactory
Vietnam Power Sector Reform DPO2 - P124174
Implementation
Performance Indicators
QAG Assessments
(if any) Rating:
Potential Problem
Program at any time
(Yes/No):
No Quality at Entry
(QEA) None
Problem Program at any
time (Yes/No): No
Quality of
Supervision (QSA) None
DO rating before
Closing/Inactive status Satisfactory
Vietnam Power Sector Reform DPO3 - P144675
Implementation
Performance Indicators
QAG Assessments
(if any) Rating:
Potential Problem
Program at any time
(Yes/No):
No Quality at Entry
(QEA) None
Problem Program at any
time (Yes/No): No
Quality of
Supervision (QSA) None
DO rating before
Closing/Inactive status Satisfactory
D. Sector and Theme Codes
Vietnam Power Sector Reform Development Policy Operation - P115874
Original Actual
Sector Code (as % of total Bank financing)
Transmission and Distribution of Electricity 100 100
Theme Code (as % of total Bank financing)
Regulation and competition policy 100 100
iv
Vietnam Power Sector Reform DPO2 - P124174
Original Actual
Sector Code (as % of total Bank financing)
General energy sector 100 100
Theme Code (as % of total Bank financing)
Infrastructure services for private sector development 14 14
Regulation and competition policy 86 86
Vietnam Power Sector Reform DPO3 - P144675
Original Actual
Sector Code (as % of total Bank financing)
General energy sector 100 100
Theme Code (as % of total Bank financing)
Infrastructure services for private sector development 14 14
Regulation and competition policy 86 86
E. Bank Staff
Vietnam Power Sector Reform Development Policy Operation - P115874
Positions At ICR At Approval
Vice President Victoria Kwakwa James W. Adams
Country Director Achim Foch (acting) Victoria Kwakwa
Practice
Manager/Manager Julia M. Fraser Hoonae Kim
Task Team Leader Pedro Antmann Richard Jeremy Spencer
ICR Team Leader Wendy Hughes –
ICR Primary Author Wendy Hughes, Thomas Flochel –
Vietnam Power Sector Reform DPO2 - P124174
Positions At ICR At Approval
Vice President Victoria Kwakwa Pamela Cox
Country Director Achim Foch (acting) Victoria Kwakwa
Practice
Manager/Manager Julia M. Fraser Jennifer J. Sara
Task Team Leader Pedro Antmann Beatriz Arizu de Jablonski
ICR Team Leader Wendy Hughes –
ICR Primary Author Wendy Hughes, Thomas Flochel –
v
Vietnam Power Sector Reform DPO3 - P144675
Positions At ICR At Approval
Vice President Victoria Kwakwa Axel van Trotsenburg
Country Director Achim Foch (acting) Victoria Kwakwa
Practice
Manager/Manager Julia M. Fraser Jennifer J. Sara
Task Team Leader Pedro Antmann Pedro Antmann
ICR Team Leader Wendy Hughes –
ICR Primary Author Wendy Hughes, Thomas Flochel –
F. Results Framework Analysis
Program Development Objectives (from Program Document)
PSRDPO 1. The objective of the proposed program is to support the Government of Vietnam
(GoV) in its implementation of a market for electricity generation, restructuring of the power
sector, and reform of tariffs that will facilitate effective competition, transparency, and
predictability, encourage timely generation investment, improve system operational reserve, and
provide incentives for efficient use of electricity.
Revised Program Development Objectives (as approved by the original approving authority)
PSRDPO 2. The objective of the Power Sector Reform Development Policy Operation (PSRDPO)
programmatic series is to support the GoV in the design and implementation of a competitive
market for electricity generation, restructuring of the power sector, and reform of electricity tariffs
that will facilitate effective competition, transparency, and predictability to encourage generation
investment and to implement programs and incentives for efficient use of electricity.
PSRDPO 3. The objective of the Vietnam PSRDPO is to support the GoV in the design and
implementation of a competitive market for electricity generation; to restructure the power sector
and reform of electricity tariff system that will facilitate effective competition, transparency, and
predictability; to encourage timely investment in new generation capacity; to enhance power
system efficiency and reliable operation; and to implement pricing and programs that promote the
efficient use of electricity.
These revisions in the program development objective (PDO) were made to reflect specific areas
of focus for the government at the time of each operation and did not substantially change the
direction or scope of the PSRDPO series.
vi
(a) PDO Indicator(s)
Vietnam Power Sector Reform Development Policy Operation - P115874
Indicator Baseline Value
Original Target
Values (from
approval
documents)
Formally
Revised
Target
Values
Actual Value
Achieved at
Completion or
Target Years
Indicator 1
Increase in generation availability due to market efficiency incentives
improves reserve adequacy and supply security.
Indicator: Hourly operational reserve at least 10%.
Value
(Quantitative or
Qualitative)
No hourly operational
reserve.
Hourly operational
reserve at least
10%.
– Partially achieved
Date achieved 12/31/2008 12/31/2012 – 07/31/2015
Comments
(including %
achievement)
Partially achieved
The term ‘hourly operational reserve’ is not defined in the context of this
program or in relevant GoV documents (for example, the grid code). The
industry standard term ‘operating reserve’ refers to auxiliary services to
respond in the time frame of seconds or minutes to a change in the energy
supply or demand (sometimes referred to as spinning and non-spinning, or
primary, secondary, and tertiary reserve).
Data for hourly operational reserve was not available. ERAV noted that
through PSRDPO 3 spinning reserve/frequency control has been about 2–3
percent of total available capacity of generation. In addition, data was
provided showing that the difference between demand and available
generating capacity on an hourly basis did not fall below 10 percent and
usually remained significantly above 10 percent in 2015. These data indicate
that there likely was sufficient operating reserve available to meet the
indicator target. However, based on the available information, it is not
possible to determine the actual level of operating reserve.
vii
Indicator 2
Enhanced transparency in generation contracting and pricing, creating
predictability for investors.
Indicators: (a) Contracts in place for 90 percent of demand, for non-build-
operate-transfer (BOT) generation based on pricing methodologies and
standard format published by regulator; (b) Vietnam Competitive Generation
Market (VCGM) spot market price disclosed in the system and market
operator (SMO) website to which the public has access
Value
(Quantitative or
Qualitative)
(a) No contract
coverage
(b) No spot market
disclosure
(a) Contracts in
place for 90
percent of
demand, for non-
BOT generation
based on pricing
methodologies and
standard format
published by the
regulator
(b) VCGM spot
market price
disclosed in the
SMO website to
which the public
has access
–
Overall: Largely
achieved
Sub-indicators:
(a) Achieved
(b) Partially
achieved. Published
daily on National
Load Dispatch
Center (NLDC)
website but only
accessible to
market participants
Date achieved 12/31/2008 12/31/2012 – 07/31/2015
Comments
(including %
achievement)
Largely achieved.
The first element of the indicator was achieved. The second element was
partially achieved. This indicator required making the data available to the
public (in line with Circular 30/2014 that requires that “Statistical data of
market price” be “publicly announced on public websites”). The data are
published on the SMO website, but only available to market participants.
Indicator 3
The independence and diversity of electricity generators increases, creating
conditions that enable development of effective competition and allow the
transition to wholesale competition
Indicator: No single company owning more than 40 percent of total installed
generation capacity
Value
(Quantitative or
Qualitative)
Highest proportion of
generation owned by a
single company is 70
percent.
No single
company owning
more than 40
percent of total
installed
generation
capacity
No single
company
owning more
than 45
percent of
total installed
generation
capacity
Partially achieved.
Vietnam Electricity
(EVN) owns 66
percent of total
installed generation
capacity directly
and through its
subsidiaries
Date achieved 12/31/2008 12/31/2012 – 12/31/2015
Comments
(including %
Note: PSRDPO 2 outcome changed to “The diversity of electricity generators
increases, creating conditions that enable development of effective
viii
achievement) competition and allow the transition to wholesale competition,” that is,
‘independence’ was dropped. Target was changed to ‘No single company
owning more than 45 percent of total installed generation capacity.’, that is,
the target was raised from 40 to 45 percent.
Partially (8-16 percent) achieved.
The target was a reduction of the maximum proportion of generation owned
by a single company from 70 percent to 45 percent, that is, 25 percentage
points. The reduction achieved was 4 percentage points (from 70 percent
down to 66 percent). Hence, the actual reduction achieved was 16 percent of
the targeted reduction. Note that data available at the time of the ICR showed
a maximum proportion of generation owned by a single company to be 68
percent, rather than the 70 percent noted in the Program Documents. If the
starting point is taken to be 68 percent, then the actual reduction achieved was
8 percent of the targeted reduction.
At the time of PSRDPO 2, the decision was made to postpone independence
of the generation companies (GENCOs) so that GENCOs will remain in EVN
ownership and benefit from the financial strength of the full EVN group. The
indicator was adapted by removing the word ‘independence’ (see section 3.2).
‘Independent companies’ meant companies “with no cross-ownership with
transmission or the Single Buyer (SB)” (Office of government (OoG) Notice
77/TB-VPCP of April 5, 2011), that is, independent of EVN.
The GENCOs have remained subsidiaries of EVN, so EVN as a company
remains the owner of 66 percent of installed generation capacity. With
GENCOs and Strategic Multipurpose Hydropower Plant (SMHP) owned by
EVN, it was not possible to achieve the specified target market share.
Indicator 4
The SMO provides efficient and non-discriminatory services following
VCGM rules, codes and regulations.
Indicator: SMO technical market audit by independent consultant firm
completed and report on compliance published in SMO website to which the
public has access
Value
(Quantitative or
Qualitative)
No audit (because
there is no SMO)
SMO technical
market audit by
independent
consultant firm
completed and
report on
compliance
published in SMO
website to which
the public has
access
–
Not achieved
No market audit
report
Date achieved 12/31/2008 12/31/2012 – 07/31/2015
Comments
(including %
Note: PSRDPO 3 indicator calls for the report on compliance to be “published
in SMO website”, with no reference to public access.
ix
achievement) Not achieved
Indicator 5 Tariff annual updates approved by MOIT up to 5 percent.
Indicator: Annual tariff adjustment is approved by March each year
Value
(Quantitative or
Qualitative)
No annual update
Annual tariff
adjustment is
approved by
March each year
Revised in
PSRDPO 2 to
“Annual tariff
adjustment
approved each
year” Revised in
PSRDPO 3 to:
“Tariff annual
setting
applying
market based
mechanisms,
approved by
MOIT”
Final revised target
as per PSRDPO 3
achieved through
Prime Minister
(PM) Decision 69
and MOIT Circular
12.
Date achieved 12/31/2008 12/31/2012 – 07/31/2015
Comments
(including %
achievement)
Notes:
PSRDPO 2 outcome changed to “Tariff annual updates, approved by
MOIT if up to 5 percent”. Indicator changed to ‘annual tariff adjustment’
approved each year”. PSRDPO 3 outcome changed to “Tariff annual setting applying market-
based mechanisms, approved by MOIT. Periodic adjustments (up to quarterly
and capped to 5 percent) to address changes in uncontrollable cost drivers
(fuel prices, rate of exchange of VND versus foreign currencies).” Indicator
changed to “Annual tariff determination and periodic adjustment procedures
approved.”
Achieved
The revised outcome and target indicator according to PSRDPO 3 were
achieved. The PSRDPO2 indicator would have been partially achieved.
Tariffs have been adjusted seven times from March 2010 to March 2015 in a
combination of annual and intra-annual adjustments. However, the annual
tariff adjustment in 2014 did not happen.
x
Indicator 6
Phase out of cross-subsidy between different tariff categories.
Indicators: (a) level of cross-subsidy from industrial and commercial
categories to residential reduced at least 50 percent; (b) subsidies targeted to
the poor, in both urban and rural areas.
Value
(Quantitative or
Qualitative)
(a) US$370 million
cross-subsidies from
commercial and
industrial to
residential; (b)
Subsidies to all PC
residential consumers
for first 100 kWh, and
local distribution utility
(LDU) tariffs higher
than EVN’s
(a) Level of cross-
subsidy from
industrial and
commercial
categories to
residential reduced
at least 50 percent;
(b) Subsidies
targeted to the
poor, in both
urban and rural
areas.
–
Achieved
(a) Cross-subsidy
estimated at US$40
million, that is, 89
percent reduction
compared to a
target of ‘at least 50
percent reduction’.
(b) Only poor
households and
those eligible for
social welfare using
less than 50 kWh
per month receive a
cash transfer
equivalent to the
cost of 30 kWh.
Uniform national
tariff for consumer
categories means
poor households
pay the same rate
whether in urban or
rural areas.
Date achieved 12/31/2007 12/31/2012 – 07/31/2015
Comments
(including %
achievement)
Achieved
xi
Indicator 7 :
Enhanced energy efficiency through legal framework, and adequate
monitoring and enforcement mechanisms.
Indicator: Energy efficiency target established by law, and MOIT and ERAV
has the capacity to enforce demand side management (DSM) and energy
efficiency requirements on power companies.
Value
(Quantitative or
Qualitative)
(a) No Energy
Efficiency Law,
(b) No formal DSM
obligations on PCs.
(a) Energy
efficiency
obligations
established by
law, and
(b) MOIT and
ERAV have the
capacity to enforce
DSM and energy
efficiency
requirements on
power companies
(PC).
(b) MOIT and
ERAV have
the capacity to
enforce and
PCs the
authority to
implement
demand
response
programs.
Overall: Largely
achieved.
(a) Achieved: Law
50/2010/QH12.
(b) Largely
achieved. PCs have
authority to
implement pilot
demand response
programs. ERAV
does not have
authority to enforce
DSM and energy
efficiency on PCs.
Date achieved 12/31/2008 12/31/2012 – 07/31/2015
Comments
(including %
achievement)
Note: PSRDPO 2 indicator changed to “Energy efficiency obligations
established by law, and MOIT and ERAV have the capacity to enforce and
PCs the authority to implement demand response programs.”
Largely achieved
(a) Achieved, through the passing of the Energy Efficiency and Conservation
Law 50/2010/QH12.
(b) Largely achieved. MOIT issued Decision 2447 of 2007 on approval of the
National Program of DSM; and MOIT Circular 33/2011 on content,
methodology, and procedure of load profiling and Decision 2600/2014 on the
launch of two pilot demand-side response (DSR) programs. PM Decision
1670 in November 2012 set the legal framework for the development of smart
grid projects in Vietnam, including for the implementation of a pilot demand
response program. However ERAV does not have authority to enforce DSM
and energy efficiency on PCs. MOIT decision 2447 expired in 2015, while
Decision 2600/2014 only allows for pilot DSR program. Another limitation is
that the incentive mechanism for customers requires approval of the Ministry
of Finance.
(b) Intermediate Outcome Indicator(s)
See Annex 2 for a full table of intermediate outcome indicators.
xii
G. Ratings of Program Performance in ISRs
Vietnam Power Sector Reform Development Policy Operation - P115874
No. Date ISR
Archived DO IP
Actual
Disbursements
(US$, millions)
1 04/27/2010 Satisfactory Satisfactory 0.00
Vietnam Power Sector Reform DPO2 - P124174
No. Date ISR
Archived DO
IP
Actual
Disbursements
(US$, millions)
1 06/13/2012 Satisfactory Satisfactory 0.00
Vietnam Power Sector Reform DPO3 - P144675
No. Date ISR
Archived DO IP
Actual
Disbursements
(US$, millions)
1 08/10/2015 Satisfactory Satisfactory 199.50
H. Restructuring (if any)
No restructuring.
1
1. Program Context, Development Objectives, and Design
1.1 Context at Appraisal
1. Since 1986, when the government introduced a broad package of economic reforms,
Vietnam has transitioned away from a centrally planned economy to a more market-oriented
economy. Part of the reforms have involved increasing the country’s regional and international
integration, with Vietnam joining the Association of Southeast Asian Nations in 1995, Asia-Pacific
Economic Cooperation in 1998, and World Trade Organization in 2007.1
2. These measures have stimulated economic growth in the country, with gross domestic
product (GDP) growth averaging 9 percent per year from the early to the mid-1990s and 6.2
percent per year over the past ten years (2005–2014), one of the highest growth rates in the
Association of Southeast Asian Nations region.
3. Economic reforms have focused on growth-oriented policies to develop a competitive
export driven industry. In late 2007, the country began to show signs of overheating driven by
massive capital inflows and fiscal expansion, experiencing high inflation (at its peak almost 30
percent) and a growing trade deficit. In early 2009, faced with rapidly deteriorating economic
conditions resulting from adverse effects of the global financial crisis, the government decisively
shifted its policy focus toward supporting growth. Vietnam weathered the global financial crisis
relatively well. The significant loosening of macroeconomic policies boosted exports, bolstered
credit growth, and strengthened domestic demand. GDP rose 5.4 percent in 2009 and 6.4 percent
in 2010—a respectable rate in the region.
4. In February 2011, the authorities announced a comprehensive stabilization package, which
contained a wide range of mutually reinforcing and consistent monetary and fiscal policy targets,
as well as measures to address structural factors underlying the economic difficulties, namely the
banking sector, state-owned enterprises (SOEs), and public investment. Policy interest rates were
raised in several steps and credit limits were imposed to slow credit expansion and curb
speculation, especially in the property market. Fiscal tightening was made through a combination
of cuts in non-wage current spending and compression of investment projects.
5. The 2007–2015 period was a roller coaster for the Vietnamese economy: moving from pre-
crisis overheating (2007–2008) to the global crisis (2009) to stimulus (late 2009–2010) to policy
tightening and stabilization (2011). Overtightening led to a slowdown (2012–2013) and the
economy is gradually recovering (2014–15).
Launch of Power Sector Reform
6. The impetus for power sector reform was the need to put the electricity sector on a
sustainable footing to be able to meet fast-growing demand driven by industrial expansion and
increased household access. The key driver of the country’s rapid growth has been the expansion
of industry, which more than doubled its share of GDP from less than 10 percent in 1995 to nearly
20 percent in 2004 (increasing to 38 percent in 2013). Huge expansion in access to electricity
1 Vietnam also joined the Trans-Pacific Strategic Economic Partnership in October 2015, further deepening regional
integration.
2
(access was about 50 percent in 1995 and increased to about 93 percent by 2004) added to the
increased demand. Electricity demand growth was in the range of 12 percent to 17 percent but has
fallen to a lower—though still quite high—rate of annual growth of around 10 percent to 12 percent
since 2010, as shown in Figure 1.
Figure 1. System-wide Electricity Sales and Annual Growth Rate: 1990–2014
Source: IES (2015a).
7. As early as 1998, it had been clear that the growth in demand for electric power could not
be met by the financial resources of Vietnam Electricity (EVN) and non-EVN-owned generation
started to enter the generation market in 2000 with 452 MW (7 percent of installed generation
capacity). This increased significantly in 2004 with the addition of two Build-Operate-Transfer
(BOT) plants, Phú Mỹ 2.2 and Phú Mỹ 3, both foreign private sector-owned and totaling 1,400
MW.
8. Power sector reform began in earnest with the approval of the Electricity Law on December
3, 2004 (National Assembly 2004). The law provides direction toward developing a competitive
electricity market, requiring the unbundling of the power sector by breaking up the EVN
monopoly. The approach commences with a single buyer (SB) for power, with a view to
establishing a competitive wholesale market and, finally, a competitive retail market. The law also
directs electricity tariff reforms to raise prices to attract private investment, reduce subsidies, and
improve demand-side energy efficiency. It mandates the Ministry of Industry and Trade (MOIT)
to govern the energy sector. The Electricity Regulatory Authority of Vietnam (ERAV) was set up
in 2005 as an entity under MOIT, responsible for the issuing of licenses; review of the power
system’s expansion plans and financing needs; preparation, issuance, and enforcement of
regulations; and review and recommendation of tariffs.
3
9. In 2006, the Prime Minister (PM) Decision 26 set out a 20-year “Roadmap” for developing
a competitive electricity market in three stages, each with initial pilot stages before full
implementation, including (i) competitive generation market2 (through 2014), (ii) competitive
wholesale market3 (2015–2022), and (iii) competitive retail market (after 2022). Stage 1, the
competitive generation market, was not viewed as an end point in itself, but as an important
transitional phase toward the establishment of a wholesale market. The Roadmap set out a
deliberately careful approach to rolling out power sector reform—designing each stage of the
process as a pilot to test, improve, and learn, followed by full implementation. This approach
reflected the high priority given by the government of Vietnam (GoV) to gradual, consensus-
driven change that would avoid shocks to the economy and households.
10. However, the competitive generation market only become fully operational in July 2012,
with generation companies (GENCOs) and independent power producers (IPPs) competing in a
power pool to sell to the SB—the Electric Power Trading Company (EPTC), a fully owned
subsidiary under EVN. The delay was caused by lengthy processes of developing new regulations
on power prices to be adopted in the generation market, drafting of power purchase agreements
(PPAs), and the development of information technology infrastructure required for market
operation. Adjusting to the delays, in 2013 the government updated the Roadmap with Decision
63 aiming to start the pilot wholesale electricity market (WEM) in 2015 to be fully operational in
2021. The GoV reform program specifies that the transmission system remains under public
ownership, but up to 30 percent private sector participation in the distribution companies is
allowed.
The Power Sector in 2008
11. Power sector structure. Figure 2 shows the structure of the power sector in Vietnam at
the end of 2008.
12. Generation in 2008. In 2008, EVN owned and operated two-thirds of generating capacity.4
Domestically-owned, non-EVN generators are known in Vietnam as IPPs. IPP owners included
PetroVietnam, the state-owned oil and gas group through PetroVietnam Power Corporation (PV
Power), and Vinacomin (TKV), the state-owned coal and mineral industries group. In 2008, there
were also two internationally owned, gas-fired BOT power plants. Total generating capacity by
the end of 2008 was 15,864 MW. Figures 3 and 4 show the 2008 installed generation capacity by
type and ownership.
2 Involves multiple power generators competing to sell electricity to a SB, which on-sells to distribution companies. 3 Involves multiple power generators selling power to multiple wholesale purchasers, that is, distribution companies
and eligible large off-takers. 4 Several of EVN’s power plants had been equitized, that is, the assets had been placed into a joint stock company
and shares offered for sale to the public and to EVN employees. EVN retains a majority shareholding in all equitized
power plants.
4
Figure 2. Structure of the Vietnam Power Sector at the End of 2008
Source: ICR authors.
Transmission (500 kV and 220 kV) The National Power Transmission Company
(NPTC) was established in 2008 based on the reorganization of EVN’s four
transmission companies and three power project management boards. The NPTC was
(and remains) a subsidiary, 100 percent owned by EVN, responsible for managing and
investing in the power transmission grid.
Distribution and retail in 2008. Distribution from 110 kV downwards and retail of
power was handled by 11 Power Companies, owned by EVN.
In 2008, the National Load Dispatch Center (NLDC), a unit within EVN, operated
and dispatched the grid system. The Electricity Power Trading Company (EPTC) was
established in 2008 as a unit within EVN as the SB.
13. Power demand and supply in 2008. Since the late 1990s, demand growth averaged
around 15 percent per year, only falling to 10 percent in 2008 due to the global crisis, before
picking up in 2009. Installed capacity, supplemented with some imports, had largely been able to
meet demand, although with a shrinking reserve margin.5 However, serious shortages did appear
in 2005, when drought conditions coincided with tight capacity constraints; they reappeared in
2007 and 2008. Estimates at the time suggested that Vietnam could face a shortage of up to 1,200
MW in 2010. Due to tight supply, the power system was occasionally operated with an hourly
operational reserve as low as 0 in 2008, meaning that any unplanned outage could affect large
sections of the grid, with significant implications for security of supply. Transmission and
distribution losses (including technical, nontechnical, and EVN own-usage) declined in percentage
5 Reserve margin is the difference between the nameplate installed capacity and the peak demand. Systems with
high level of hydropower may need higher reserve margin than thermal-dominated systems to cover periods of low
water availability.
5
terms during this period from 13.4 percent in 2002 to 10.8 percent in 2008. It was clear that a large
investment program would be needed to meet new demand and build up the reserve margin.
Figure 3. 2008 Capacity by Type
Figure 4. 2008 Capacity by Ownership
Source: ICR authors, based on data provided in “Background Note on Vietnam Power Sector” prepared by
PSRDPO1 project team.
Figure 5. EVN Production, Sales, Generation Capacity 2003–2008
Source: ICR authors, based on data provided in “Background Note on Vietnam Power Sector” prepared by PSRDPO1
project team.
14. Growth in demand had been driven by increased access to electricity and a shift in the
economy toward greater industrialization. Between 1995 and 2008, household access increased
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
0
10
20
30
40
50
60
70
80
2003 2004 2005 2006 2007 2008
MW
TWh
EVN (MW) non-EVN (MW)Total production (TWh) Total Sales (TWh)
6
from 50 percent to nearly 94 percent and annual per capita consumption increased from 156 kWh
to about 800 kWh.6
15. By 2008, industrial electricity use had overtaken residential consumption and accounted
for nearly 50 percent of the total. Industry increased its share of GDP from 22.6 percent in 1995
to 39.9 percent in 2008.
16. Supply and demand growth and projections in 2008. Projections for the power sector
in 2008 estimated that over US$4 billion and potentially as much as US$6 billion of investment
per year would be needed in the power sector—with the majority needed for generation to keep up
with growing demand.
Figure 6. Power Sector Demand Growth Projections in 2008
Source: ICR authors, based on data provided in “Background Note on Vietnam Power Sector” prepared by PSRDPO1
project team.
17. Electricity tariffs. In 2008, electricity tariff arrangements had a number of weaknesses.
The tariff setting process was not transparent, with decisions made at the political level after a
process of negotiation with EVN and within the GoV, without a clear reference to economic
justification. Tariff calculations did not identify separate cost components for generation,
transmission, distribution, and retail businesses. Electricity tariffs were not regularly updated when
costs increased, resulting in an average retail tariff that was too low to cover the cost of electricity
supply and new investment. Together, these diminished the attractiveness of investment in the
power sector.
6 Electricity use in Vietnam was growing from a very low base. In 1995, the total power sales of 11.2 TWh
amounted to only 156 kWh per person per year. Even after growth in electricity use to 65.9 TWh—about eight
times—by 2008, total end-use consumption was only 800 kWh per capita per year, compared with an average of
1,343 kWh per capita per year in the East Asia and Pacific region and 1,225 kWh per capita per year in low- and
middle-income countries worldwide.
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
0
50
100
150
200
250
300
350
2006 (actual) 2010 2015 2020
MW
TWh
Capacity Requirement (MW) Energy (TWh)
7
Figure 7. Power Sector Investment Projections in 2008 (US$, millions)
Source: ICR authors, based on data provided in “Background Note on Vietnam Power Sector” prepared by PSRDPO1
project team.
18. Power sector financial situation and outlook in 2008. EVN’s overall revenues were
insufficient to cover the costs of system operation and investment. The bursting of the real estate
bubble in early 2008 made it difficult for several commercial banks to recover their loans, so the
availability of domestic borrowing was limited. EVN was also facing higher outflows: the rapid
disinflation in late 2008, at a time when interest rates were still very high, substantially increased
its debt service burden, and the weakening dong raised the cost of servicing foreign-exchange-
denominated loans. The combination of the government’s stimulus measures, the fall in oil prices,
and the slowdown in economic activities had resulted in a large decline in government revenues,
limiting the GoV’s willingness and ability to support EVN.
19. Central challenges faced by the GoV. Concern about high inflation was fresh in the minds
of government officials, so avoiding price shocks was a key consideration. It was also clear that
meeting investment needs over the medium and longer term would require diversification of
financing sources, in line with the power sector reform Roadmap. The GoV’s central challenges
to be addressed in the design and implementation of the Vietnam Competitive Generation Market
(VCGM) included the following:
Ensuring stable power supply, requiring that adequate levels of investment would
be made in time to meet demand growth and avoiding abrupt changes in the structure
of the sector or its operation that could lead to interruptions in investment.
Attracting investment from new sources. The sector should increasingly rely on
investment from nontraditional sources and, in particular, from private and foreign
sources.
Increasing competition to improve efficiency and obtain reasonable prices. The
level of competition in the power market should be gradually increased to strengthen
0
5,000
10,000
15,000
20,000
25,000
2006-2010 2011-2015 2015-2020
Generation Transmission Distribution
8
incentives for efficiency.
20. Rationale for Bank assistance. The World Bank Group has had a significant engagement
in Vietnam’s power sector through investment and technical assistance (TA) operations for over
ten years. The Bank Group was also the lead development partner in the power sector reform
dialogue. Supporting reform through the Development Policy Operation (DPO) series was a
natural complement to the sector investment and TA engagements, which were organized around
the same themes: market design was supported by the System Efficiency Improvement,
Equitization, and Renewables Project (Cr. 3680 and Global Environment Facility TF051229)
(SEIER); unbundling of the transmission system and development of NPTC was supported by the
Second Transmission and Distribution project (TD2) and the development of the PCs’ distribution
operations and capacity to operate autonomously was supported by the Second Rural Energy and
Rural Distribution (RD) projects. Power Sector Reform Development Policy Operations
(PSRDPOs) supported the first pillar of the 2007–11 Country Partnership Strategy, namely to
improve the business environment by meeting demand for reliable high quality electricity.
1.2 Original Program Development Objectives (PDO) and Key Indicators (as approved)
21. The original PDO as reflected in PSRDPO 1 was to support the GoV’s implementation of
a market for electricity generation, restructuring of the power sector, and reform of tariffs that will
facilitate effective competition, transparency, and predictability, encourage timely generation
investment, improve system operational reserve, and provide incentives for efficient use of
electricity.
22. Key outcomes, indicators, and targets as reported in the Program Document for PSRDPO
1 were the following:
(a) Increase in generation availability due to market efficiency incentives improves
reserve adequacy and supply security. Indicator: Hourly operational reserve at least
10%.
(b) Enhanced transparency in generation contracting and pricing, creating predictability
for investors. Indicators: (a). Contracts in place for 90 percent of demand, for non
BOT generation based on pricing methodologies and standard format published by
regulator and (b) VCGM spot market price disclosed in system and market operator
(SMO) website to which the public has access.
(c) The independence and diversity of electricity generators increases, creating conditions
that enable development of effective competition and allow the transition to wholesale
competition. Concentration Indicator: No single company owning more than 40
percent of total installed generation capacity.
(d) The SMO provides efficient and non-discriminatory services following VCGM rules,
codes, and regulations. Indicator: SMO technical market audit by independent
consultant firm completed and report on compliance published in SMO website to
which the public has access.
9
(e) Tariff annual updates approved by MOIT up to 5 percent. Indicator: Annual tariff
adjustment is approved by March each year.
(f) Phase out of cross-subsidy between different tariff categories. Indicators: (a) level of
cross-subsidy from industrial and commercial categories to residential reduced at least
50 percent and (b) subsidies targeted to the poor, in both urban and rural areas.
(g) Enhanced energy efficiency through legal framework, and adequate monitoring and
enforcement mechanisms Indicator: Energy efficiency target established by law, and
MOIT and ERAV has the capacity to enforce demand side management (DSM) and
energy efficiency requirements on power companies.
1.3 Revised PDO (as approved by original approving authority) and Key Indicators and
Reasons/Justification
23. The PDO statement for PSRDPO 2 and 3 were revised as follows:
24. PSRDPO 2. The objective of the Power Sector Reform DPO programmatic series is to
support the GoV in the design and implementation of a competitive market for electricity
generation, restructuring of the power sector and reform of electricity tariffs that will facilitate
effective competition, transparency and predictability to encourage generation investment, and to
implement programs and incentives for efficient use of electricity.
25. PSRDPO 3. The objective of the Vietnam Power Sector Reform Development Policy
Operation is to support the GoV in the design and implementation of a competitive market for
electricity generation; to restructure the power sector and reform of electricity tariff system that
will facilitate effective competition, transparency and predictability; to encourage timely
investment in new generation capacity; to enhance power system efficiency and reliable operation;
and to implement pricing and programs that promote the efficient use of electricity.
26. In addition, in the Program Document for PSRDPO 3, the program objectives as defined
in the main text are introduced by “The objective of the Vietnam Power Sector Reform
Development Policy Operation is to support the initial phase of the long-term sector reform within
the general framework defined in the Electricity Law, including…”, highlighting that the end-point
of the PSRDPO series corresponds to an intermediate point in the GoV’s overall power sector
reform program.
Revisions to PDO
27. The reference to ‘operational reserves’ was dropped at the time of PSRDPO 2. The
reference to ‘enhanced power system efficiency and reliable operation’ was added at the time of
PSRDPO 3. These adjustments were proposed by the client to match the current internal priorities,
processes, and discussions at the time of each DPO. They did not materially affect the objective
and did not result in changes in prior actions or indicators.
10
Key Indicator Revisions
28. Reasons and implications of these revisions are discussed in section 3.2: Achievement of
Program Development Objectives.
29. Indicator 1. PSRDPO 2 outcome was changed to “Increase in generation availability due
to market efficiency incentives and increase in quality of service due to technical codes.” No
change in the indicator nor in the target value accompanied this replacement of ‘reserve adequacy
and supply security’ by ‘quality of service due to technical codes’. The change emphasizes the
focus on proper SMO functioning in relation to the grid code.
30. Indicator 3. Based on an EVN study, it became apparent fairly soon after the start of
PSRDPO 1 that independence of GENCOs, from the EVN holding company could not be achieved
without significant cash injection from the GoV, which was not forthcoming. In PSRDPO 2, the
statement of the outcome was therefore changed to remove the word ‘independence’. The target
indicator was changed to allow a higher maximum ownership percentage: no single company
owning more than 45 percent of total installed generation capacity.
31. Indicator 5. The PSRDPO 2 outcome was changed to “Tariff annual updates, approved by
MOIT if up to 5 percent”. The GoV decision on tariff reform had advanced more than expected,
from annual to also include a provision for intra-annual adjustments.7 The indicator was changed
to ‘annual tariff adjustment approved each year’ to allow more flexibility in the timing of the
annual tariff adjustments. The PSRDPO 3 outcome was changed to “Tariff annual setting applying
market based mechanisms, approved by MOIT. Periodic adjustments (up to quarterly and capped
to 5 percent) to address changes in uncontrollable cost drivers (fuel prices, rate of exchange VND
versus foreign currencies).” The indicator was changed to “Annual tariff determination and
periodic adjustment procedures approved”. This change reflected greater emphasis on getting the
tariff regulations in place, compared to implementation of the tariff adjustments.
32. Indicator 7. The PSRDPO 2 indicator was revised to “Energy efficiency obligations
established by law, and MOIT and ERAV have the capacity to enforce, and PCs the authority to
implement demand response programs”, whereas the indicator at PSRDPO 1 called for “energy
efficiency requirements on power companies”. This change reflected a renewed focus on DSM by
the GoV, as the Energy Efficiency and Conservation (EE&C) Law was passed by the National
Assembly in 2010, introducing energy savings in all economic sectors, but further regulations and
monitoring of demand were required to achieve the 5 to 8 percent energy savings target they had
set for the Vietnam National Energy Efficiency Program Phase 2 (2011–2015).
1.4 Original Policy Areas Supported by the Program (as approved)
33. The program was organized around four main policy areas essential to the reform of
Vietnam’s power sector:
7 The PM Decision 24 and accompanying MOIT Circular 31/2011/TT-BCT (called Circular 1) establish that
changes in uncontrollable cost items (fuel, currency exchange rate, market price, etc.) that trigger an average tariff
increase of less than 5 percent should be automatic.
11
Policy Area A: Development of a competitive power market. Two key issues
specifically informed the development of the policy matrix for this policy area: (a)
the need to achieve sufficient generation capacity in the medium term through new
investment and through increasing generation availability and (b) the need to address
security of supply concerns through adequate operational reserve.
Policy Area B: Power sector restructuring. Issues to be addressed by the sector
restructuring included concerns about conflict of interest (that is, cross-ownership of
generation and other functions including the SMO) and concerns about nontransparent
and discriminatory generation dispatch including strategic hydro operational
planning. Transparency—both in the availability of market information and in the
interactions among market players—and the perception of a ‘level playing field’ are
important underpinnings of a competitive market. Addressing actual and perceived
conflict of interest and increasing transparency were fundamental to the development
of a competitive market and hence were the primary areas of focus under this policy
area.
Policy Area C: Electricity tariff reform. Key issues to be addressed in the tariff
reform policy area were to move the sector to a sustainable financial footing as the
basis for attracting new investment (that is, tariffs should be set transparently and
provide revenues sufficient to cover the cost of supply including generation,
transmission, distribution, and system operation costs); to improve the targeting the
subsidy for electricity toward the poor, including in rural areas; and to significantly
reduce cross-subsidy especially from industrial and commercial categories to
residential consumers, so that prices paid by various end-user categories more closely
reflected cost of supply.
Policy Area D: Improving demand-side energy efficiency. Two factors motivated
GoV attention to demand-side energy efficiency: the need to reduce or avoid energy
shortages (which would be addressed through targeting an overall reduction in the rate
of growth of energy demand through efficiency) and the goal of limiting requirements
for new investment in capacity, implying the need to limit growth specifically in peak
demand. Recognizing that improving the price signals would depend on actions
supported in Policy Area C on tariff reform, Policy Area D focused on the
complementary areas: the enabling framework, information availability, and time of
use (TOU) tariffs.
34. The Program Performance table in section 2.1 presents the PDO outcomes associated with
each policy area, the issues motivating each area, and the corresponding prior actions for each
PSRDPO. See Annex 4 for a table of all prior actions and evidence of fulfilment and Annex 5 for
a table of prior actions and planned indicative triggers for each PSRDPO.
1.5 Revised Policy Areas (if applicable)
Not applicable
12
1.6 Other significant changes
Not applicable
2. Key Factors Affecting Implementation and Outcomes
2.1 Program Performance
Program
Performance
Issues
Prior Actions
Prior Actions under
DPO 1
Prior Actions under
DPO 2
Prior Actions under
DPO 3
Policy Area A: Development of Competitive Power Market
Increase in generation availability due to market efficiency incentives and increase in quality of service due to
application of technical codes. Enhanced transparency in generation contracting and pricing, creating
predictability for investors.
Power generating
capacity is
insufficient in the
medium term and
operational
reserve is
inadequate for
supply security
Generation prices
are not formed
transparently.
Long negotiation
in contracts with
new generation
investment due to
lack of reference
market pricing
Establishing of
design principles for
the implementation
of the VCGM
Establishing
metering systems
standards and
procedures for
generation plants
participating in the
VCGM
Establishing market
rules for the VCGM,
instructing EVN to draft
market procedures and
delegating authority for
ERAV to review and
approve market
procedures
Establishing
methodologies and
procedures to determine
and approve standard
contracts and pricing for
generation, except for
BOT and Strategic
Multi-Purpose Hydro
(SMHP)
Establishing
methodology for cost
recovery revenue
requirement of SMHPs
The commercial
operation of the
Vietnam Competitive
Generation Market has
been fully
implemented
13
Policy Area B: Power Sector Restructuring
The diversity of electricity generators increases, creating conditions that enable development of effective
competition and allow the transition to wholesale competition. The SMO provides efficient and
nondiscriminatory services following VCGM rules, codes, and regulations.
Cross-ownership
with generation
creates conflict of
interest for
incumbent
generation
investor and for
SB least-cost
purchases
Perceived conflict
of interest in
power master
plan as the
Institute of
Energy (IoE)
carrying out the
studies for MOIT
is owned by EVN
Generation
dispatch and load
shedding
perceived as
nontransparent
and
discriminatory
Establishing a sector
structure to allow
for the introduction
of the VCGM
Deciding to create
Generation Companies
(GENCOs) with
portfolio of EVN power
plants, excluding SMHP,
to later become
independent successor
companies with no cross
ownership with
transmission or Single
Buyer (SB)
All GENCOs have
started commercial
operations and
registered as market
participants in VCGM
The Borrower,
through its Prime
Minister, has issued
Decision Number
63/2013/QD-TTg
dated November 8,
2013 to set forth the
roadmap and
operational principles
for a power wholesale
competitive market
through the separation
of GENCOs and the
System and Market
Operator into
independent
companies that are not
cross-owned with
other market
participants
14
Policy Area C: Electricity Tariff Reform
Tariff annual setting applying market based mechanisms, approved by MOIT. Periodic adjustments (up to
quarterly and capped to 5 percent) to address changes in uncontrollable cost drivers (fuel prices, rate of exchange
VND vs. foreign currencies). Phase out of cross subsidy between different tariff categories.
Electricity tariffs
are not updated
when costs
increase
Costs of each
electricity activity
included in retail
tariffs are not
transparent and
investors are
uncertain on
recovery of
investment costs
Cross-subsidies
between tariff
categories lack
transparency
Subsidies to low-
income
consumers are
poorly targeted,
and do not benefit
rural consumers
(a) increasing the
average tariff in
2009 to VND
948/kWh, and (b)
implementing
transparent annual
tariff-setting from
2010-12 based on
cost recovery
principles, including
the unbundling of
the average retail
tariff into power
supply cost
components and the
delegation of tariff
changes of less than
five percent to the
MOIT
Restructuring the
residential block
tariff system to
establish the
principle of the
subsidy to the
consumer as a
percentage of
production cost and
extend the subsidy
mechanism and
residential tariff
structure to local
distribution utilities
Establishing market-
based mechanism to
adjust average electricity
tariff, including annual
update and adjustments
during the year to reflect
changes in generation
costs
Establishing
methodologies to
determine and approve
transmission revenue
requirement for NPTC,
and transmission charges
The Borrower,
through Ministry of
Industry and Trade,
has issued Circular
12/2014/TT-BCT
dated March 31, 2014,
setting forth the
methodologies for the
establishment of
annual retail
electricity tariffs
Policy Area D: Improving Demand Side Energy Efficiency
Enhanced energy efficiency through legal framework, and adequate monitoring, and enforcement
mechanisms
Demand profile
(load factor, and
high peak demand
few hours in the
year) increase cost
of supply
Lack of information
on efficiency
standards and price
incentives in retail
electricity tariffs.
Establishing energy
efficiency standards
for consumer goods
accounting for large
quantities of
electricity.
Introducing time-of-
use tariffs for
industrial zones and
commercial,
industrial, and
irrigation consumer
categories.
Establishing load
research regulations for
PCs.
The Borrower,
through MOIT, has
issued Decision
Number 2600/QD-
BCT dated March 27,
2014 to authorize a
power distribution
company to carry out
a pilot demand-
response program.
At least one power
company has begun to
pilot a demand-
response program.
15
2.2 Major Factors Affecting Implementation
Adequacy of Government's Commitment and Participatory Processes
35. Long-term perspective combined with political continuity. The ongoing but sometimes
delayed implementation is a consequence of a deliberately gradualist and long-term strategy by
the GoV. The power sector reform road map sets out three distinct stages of competitive market
development, each with a pilot phase before full operation, in a timeframe of 20 years. The
approach demonstrates a long-term view of the evolution of the power sector, combined with an
explicit imperative to implement changes gradually to avoid price or supply shocks.
36. Consensus approach. Government decision making in Vietnam is consensus-based.
Decisions are taken only after stakeholders have had the opportunity to express their views and
have reached a consensus. This has the effect of strong stakeholder engagement in the reform
program, but also requires sufficient time for discussion and reaching a consensus.
37. The combination of a gradualist and consensus-based approach leaves ample room for
thinking to evolve, which sometimes has the effect of changes, for example in sequencing of key
steps and timeline. This is evident in decisions to implement the VCGM before addressing the
issue of dominant market share, and postponing both the independence of the GENCOs and
creation of an independent SMO.
38. The continuity in leadership and ownership of the reform objectives and long-term view
have been important factors in continuing to move the reform forward. At the same time, the delays
and adjustments during the course of the PSRDPO program, discussed in section 3, together
represent some dilution of the reform effort, suggesting that the GoV’s willingness or ability to
manage disparate stakeholder views has waned during the course of the PSRDPO program.
Soundness of the Background Analysis Supporting the Operations
39. The PSRDPO program was based on extensive background analysis. TA under the System
Efficiency Improvement, Equitization and Renewables Project (SEIER, Cr. 3680 and TF051229)
and Second Transmission and Distribution Project (TD2, Cr. 4107) provided much of the analytic
underpinnings for the program. TA was also provided to assist the GoV in strengthening the
framework for the tendering process for BOT projects.8 The Bank’s power sector engagement at
the start of the program was grouped into four areas: (a) efficient and sustainable expansion of
physical system capacity: the portfolio supported expansion of generation capacity and
improvements in supply-side efficiency in transmission and distribution; (b) fostering private
sector participation: IDA and the Multilateral Investment Guarantee Agency were providing
guarantees; (c) promoting renewable energy and energy efficiency; and (d) supporting sector
reform. All the projects in this portfolio included some element of support for sector reform.
8 BOT projects are international private sector projects that in the time frame of the PSRDPO series would not be
affected by the introduction of the VCGM.
16
Assessment of the Operation’s Design and Relevance of the Risks Identified and
Effectiveness of Mitigation Measures
40. The PSRDPO 1 design took into account a number of ‘lessons learned’ with respect to
good practice principles on conditionality. Two main lessons from power sector reform operations
also clearly informed the design: the importance of ensuring that reforms do not induce shocks in
either supply or demand and the need for some flexibility to build consensus.
41. Context of the country in early stages of moving to a market economy where power
sector reform is near the forefront. One of the risks identified at appraisal was ‘complexity and
novelty’ of the reforms, with mitigation measures focusing on capacity building and gradual
implementation. An effective competitive market that attracts investment while delivering quality,
cost-effective services requires a high degree of transparency and rule-based, technical— rather
than political—decision making. This implies a fundamental change in the role of government
compared with a vertically-integrated, government-owned and -controlled power sector. The
Vietnam context at the start of the DPO series was one of central planning for many aspects of the
economy, including the power sector. While the GoV has a broader agenda to become a market-
oriented economy, albeit with a strong emphasis on social aspects, power sector reform is near the
forefront of the transition. Steps toward increasing transparency, releasing some direct government
control of the sector and economic regulation of services are novel not just for the power sector
stakeholders but for the government more broadly. While there has been progress in increasing
transparency under the PSRDPO program, it has been slower than planned. The country context
has likely been a factor in the cautious approach to increasing transparency that is evidenced in the
implementation of the reform program.
42. Rapidly changing macroeconomic situation during the course of the PSRDPO series. One important risk that was not directly highlighted as a risk at the start of the PSRDPO program
was the impact of changes in the overall economy on the reform progress. Vietnam moved from
pre-crisis overheating (2007–2008) to the global crisis (2009) to stimulus (late 2009–2010) to
policy tightening and stabilization (2011). Overtightening led to a slowdown (2012–2013) and the
economy is gradually recovering (2014–2015). This directly affected GoV decisions on
implementation of some elements of tariff reform, as discussed in section 3.2. It indirectly affected
the progress on restructuring of the power sector. Poor EVN financial situation in 2009 and 2010,
in part because of large foreign exchange losses (Mercados 2015), led to the GoV’s decision not
to proceed with making GENCOs independent on the original schedule.
43. Focus of World Bank Support. Implementation and supervision after the first PSRDPO
appear to have placed more emphasis on Policy Areas A (development of competitive power
market) and C (tariff reform), and this may have contributed to the less-than-satisfactory outcome
for Policy Area B (restructuring).
2.3 Monitoring and Evaluation (M&E) Design, Implementation, and Utilization
44. ERAV as the implementing agency for the program was responsible for overall M&E. This
entailed coordinating with and gathering information from many stakeholders: EVN, GENCOs,
PCs, NLDC, NPTC, EPTC, MOIT, and the Ministry of Finance (MOF).
17
45. The PSRDPO policy matrices set out key intermediate next steps and the medium-term
plan for each DPO and the series, providing a framework of concrete actions. The scope of the
PSRDPO series, in terms of breadth of topic, period covered, and complexity of the reform targeted
made it challenging to define a concise set of actions, milestones, and indicators that would
adequately facilitate M&E of the overall progress. In general, the policy matrices in the four areas
provided clear sequences of actions, indicative triggers, and intermediate milestones that were
relevant for monitoring progress. As the series progressed, overall these were updated to reflect
changes in pace and, in the case of Policy Area D, focus. However in Policy Area B, the
postponement of key actions could have been accompanied by new milestones or indicators
supporting alternative ways of addressing the key issues targeted in that policy area.9
46. The end-of-program indicators taken together identified a reasonable set of targets against
which to measure progress. However in Policy Area A, the first end-of-program indicator could
have benefited from a clearer definition to ensure a common understanding among all parties.10 In
Policy Area B, one of the end-of-program indicators could have been revised as the program
progressed, to better capture the progress toward outcomes.11 For two of the end-of-term
indicators, data to measure progress was difficult to find and would have benefited from a greater
focus on data collection and monitoring of progress towards these two indicators.12 It is unlikely
that quantitative monitoring of progress toward these targets played a significant role in the
implementation of the program.
47. The implementation of the M&E based on the policy and results matrices was
complemented by assessment reports undertaken during the course of the implementation.
Examples include a report that included an assessment of the outcomes of the VCGM (IES 2014),
a report which included a financial assessment of EVN companies (Mercados 2015), and a review
of the tariff structure (Groom 2014). Each report informed stakeholder discussions, in some cases
also triggering high-level dialog between the Bank and GoV to highlight the need to address
critical issues, and was used as inputs to inform the design of the next PSRDPO series.
2.4 Expected Next Phase/Follow-up Operation (if any)
48. At the start of the PSRDPO series, it was envisioned that subsequent operations would
support the next stage of power sector reform: the development of the WEM. The WEM is
arguably the most important stage in attracting investment, a key driver of the overall reform
program. While progress has been slower than what was set out in the first PSRDPO series, the
overall direction is very much in line with the original thinking and the core themes continue to be
9 Alternative milestones or triggers could have been included to support and measure progress in increasing
transparency and reducing conflict of interest, when it was agreed that the independence of the GENCOs and NLDC
would be postponed. 10 See discussion in section F, table (a) PDO Indicators. 11 Indicator 3: “Highest proportion of generation owned by a single company is 45 percent”. Agreement on
postponing the independence of GENCOs at PSRDPO 2 reduced the likelihood of a meaningful change in market
share and diversity of ownership occurring during the PSRDPO series. With GENCOs and SMHPs owned by EVN,
it was not possible to achieve the specified target market share. 12 These two indicators were Indicator 1: System is operated with hourly operational reserve; and Indicator 6: Level
of cross-subsidy from industrial and commercial categories to residential reduced at least 50 percent.
18
at the center of the dialog: transparency, elimination of conflict of interest, cost-reflective tariffs,
and efficiency improvements.
49. The government and the Bank are at the concept stage of formulating a new PSRDPO
program. A multi-sectoral programmatic series of three DPOs is envisioned. A continuation of the
same themes has been tentatively agreed for the four pillars of the proposed new program. Possible
prior actions for the first future DPO and indicative triggers for the second future DPO have been
tentatively identified. They are key elements with regard to increasing transparency, reducing
actual and perceived conflict of interest, and improving the sector financial viability. The future
DPO series would support the energy sector restructuring program that was approved by the MOIT
on December 25, 2015. The next DPO operation is currently planned for FY17, as agreed in
principle by the central government agencies.
50. A multi-year programmatic energy sector TA program is underway in parallel with
ongoing and new investment operations supporting distribution, transmission, hydropower
generation, and improvement in industrial efficiency.
3. Assessment of Outcomes
3.1 Relevance of Objectives, Design and Implementation
Rating: Substantial
51. Relevance of objectives. The objectives were fully aligned with development priorities and
circumstances at the start of the PSRDPO program and continue to be well-aligned and highly
relevant at the time of the Implementation Completion Report (ICR).
52. Alignment with Government Strategy. The Bank and GoV have jointly prepared the
“Vietnam 2035” study, proposing an approach for Vietnam’s transition to a modern, industrialized
economy. The Overview was released in early 2016, with the release of the full report expected by
mid-year. It is expected that Vietnam 2035 will provide analytical inputs for the preparation of the
strategic documents for the 12th Party Congress and to form the basis for the next Socio- Economic
Development Plan 2016-2020. It will also inform the Bank’s Systematic Country Diagnostic. The
Vietnam 2035 recognizes the role of the energy sector and the importance of energy policy reform
in achieving the desired transition. The Power Sector Reform Roadmap, first issued in 2006 and
updated in 2013, remains the government’s guiding document setting out the government’s vision
and objectives for power sector reform. The design and objectives of the PSRDPO program are
closely aligned with the approach set out in the updated Roadmap and therefore with the
government’s development priorities and strategy at the time of the ICR.
53. Alignment with Bank Strategy. The design and objectives of the PSRDPO program are also
well-aligned with the Bank strategy at the time of the ICR. In the CPS FY12-FY16, Pillar 1 on
competitiveness includes a focus on improving the quality of key infrastructure services. During
the CPS period, the Bank’s strategic priorities in the infrastructure sectors in Vietnam included
generating quality growth by combining infrastructure investments with policy reforms,
identifying the power sector as one of the areas for support. The Performance and Learning
Review of the Country Partnership Strategy completed in May 2015 confirmed that the CPS FY12-
FY16 remains highly relevant to the country’s development challenges and reconfirmed the focus
19
on power sector reform with by including Power Sector Development Policy Series II as part of
the indicative pipeline under Sub-pillar 1.2: Quality and Efficiency of Infrastructure Services.
Preparation for this second power sector reform series is underway.
54. Relevance of design. A programmatic DPO was the right instrument. The program was
launched in the context of a strong power sector engagement encompassing analytical and advisory
activities, IBRD/IDA lending and guarantees, and facilitating involvement of other parts of the
Bank Group. The series of Poverty Reduction Support Credits at the time of PSRDPO 1 also
included dialog on aspects of power sector reform. Progress in reform of the power sector required
engagement of a number of stakeholders beyond the line ministry and EVN, and a programmatic
DPO supported this broader range of stakeholder engagement.
55. The PSRDPO program was well-aligned with the principles set out by the government for
attracting investment in the longer term: transparent rules and operation to underpin fair
competition, moving toward cost-reflective tariffs, addressing concerns about conflicts of interest,
and avoiding excessive market dominance by any one participant. It also supported important steps
needed to increase energy efficiency, through both legal and regulatory frameworks and tariff
reform. The program also was well-aligned with the gradual approach13 chosen by the GoV. The
policy areas of the program reflected the core pillars of the overall power sector reform agenda:
creating the sector structure and the rules, regulations, and systems necessary for a generation spot
market; transparent tariff structure, process, and adequate level necessary to put the sector on a
financially-sustainable footing; and putting in place authority and mandate to improve demand-
side energy efficiency. There is a clear delineation in the programmatic DPO of the operations
matching key milestones in the government’s reform agenda. The overall power sector reform
agenda and the specific policy areas included in the PSRDPO program were highly relevant both
at appraisal and at the time of the ICR. The end-of-program indicators provided a reasonable set
of targets against which to measure progress. However, as discussed in Section 2.3, two of the
indicators could have been revised during the program to update the results chain to reflect
adjustments in the design.
56. Relevance of implementation. Due to the various adjustments during the course of the
PSRDPO series,14 the attractiveness of the power sector for private investment at the end of the
series was somewhat less than it would have been, had the GoV been able to adhere to the original
timeline. Given the significant private sector financing expected for new generation especially in
the next five years, it may have been appropriate to introduce a focus on ‘back-up’ approaches15
to attracting private investment, should the market approach take longer than hoped to catalyze
private interest.
3.2 Achievement of Program Development Objectives
Overall Rating: Substantial
13 Pilot followed by full implementation at each stage. 14 For example, shifting the focus from ‘achieving’ to ‘transitioning’ to ‘cost-reflective tariffs’, and postponing the
independence of the GENCOs and NLDC, all important factors in creating a market environment conducive to
private sector investment. 15 For example, support for stronger and quicker process for assessing, negotiating, and approving long-term PPAs,
with provisions to integrate these into the wholesale market at some time in the future.
20
57. The overall achievement of the PDO is rated as Substantial. This rating takes into account
achievement of the PDO indicators, the progress under each policy area considering the outcomes
sought, and a qualitative assessment of the specific elements noted in the PDO.
Progress in the Vietnam Power Sector since 2008
58. It is useful to consider the assessment of achievement of the PSRDPO PDOs in the context
of the overall progress in the power sector since 2008, keeping in mind the central challenges faced
by the GoV in the lead up to PSRDPO 1, specifically adequate investment in generation capacity
and attracting investment from new sources, in order to meet demand during the course of the
PSRDPO series and to be positioned to meet demand going forward, including through improved
efficiency.
59. Real GDP growth averaged around 5 percent per year between 2008 and 2014, somewhat
slower than the 2000–2008 period. Demand grew more slowly than was anticipated in 2008 with
a commensurate reduction in the rate of new generation investment required. Actual demand
growth through 2013 and projected growth through 2020 are shown in Figure 8. The updated
forecasts are fairly consistent, projecting a demand of 250,000 GWh in 2020, representing about
an 11 percent growth rate from 2014 (compared with 14.1 percent used in the original Power
Master Plan VII [PMP7]). Since 2008, electricity intensity of the economy and per capita
electricity use have continued to grow. Growth in electricity intensity (kWh/2005$) has shown a
steady increase from about 0.3 in 1992 to about 1.2 in 2013.16
Figure 8. Electricity Demand Forecast
Source: Mercados 2015: Analysis based on PMP7, nonofficial update of PMP7, and consultant’s own forecasts.
Notes: PMP7 Forecast_Low: This is the low scenario demand forecast from PMP7, 2011.
Updated PMP7 Forecast_Op1: This is the unofficial GoV update of PMP7, prepared by the Institute of Energy
(department of MOIT), taking into account the slower than predicted demand growth through 2012. New demand
forecast is the forecast prepared by the consultants who prepared the “Report on Strategic Options for Enhanced
Financial Performance of EVN Power Companies”, in 2013.
16 Asian Development Bank 2015. ADB computation based on data from the NLDC (2014) and EVN (2014) for
electricity consumption; and World Bank, World Development Indicators (accessed April–October 2014) for GDP
and sector value added.
141,986
250,069
169,821
289,882
151,035
258,603
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020
GW
h
New demand forecast PMP7 Forecast_Low
Historic Demand Updated PMP7 Forecast_Op1
21
60. During the period 2008 to 2015, the supply mix shifted toward coal, a trend which is
expected to continue through 2020.17 Growth in installed capacity exceeded growth in peak
demand during the period of the PSRDPO, resulting in a significant improvement in the reserve
margin, from about 25 percent in 2008 to over 50 percent in 2014, fully addressing one of the key
medium-term challenges identified by the GoV in 2008, that is, generation investment keeping
pace with demand growth.
Figure 9. Installed Capacity, Peak Demand and Reserve Margin 2008–2014
Source: IES 2015f.
61. A second main challenge facing the GoV in 2008 was to attract more non-EVN
investments, particularly from the private sector. Between 2008 and 2010, a number of power
companies were formed into joint stock companies, with non-EVN SOE majority ownership and
some with minority private participation, referred to in the Vietnam context as IPPs. New
generation from 2010 through 2014 was comprised of 7,950 MW EVN-owned and 3,200 MW
other SOE-owned (IPPs) (IES November 2014). EVN remains the dominant owner of capacity,
including both capacity directly owned by EVN Holding and by its subsidiary GENCOs. The share
of EVN-owned compared to non-EVN-owned has decreased from 68 percent in 2008 to 66 percent
in 2015. By the end of 2015, the total number of power plants in operation was 109 (not including
small hydropower plants). Total new capacity introduced in 2015 was 4,612 MW, including new
BOT, EVN-owned and IPP-owned, bringing the total power installed capacity to 38,642 MW
(including small hydropower plants). In 2015, the total power production of the national power
system reached 164.31 billion kWh (including power production sold to Cambodia). Figures 10
and 11 shows the installed capacity by ownership and type in 2015.
17 In 2015, coal accounted for 34.2 percent of installed capacity, compared with 11.8 percent in 2008. The share of
coal-fired generation is projected to increase to 48 percent by 2020.
22
Figure 10. Installed Capacity in 2015 by
Generation Type
Figure 11. Installed Capacity in 2015 by
Ownership
Source: ERAV data, April 2016.
62. In 2012, the total share of private participation in the generation sector was estimated at
just under 10 percent (out of total installed capacity in 2012 of 26,315 MW), taking into account
the private sector minority share ownership in IPPs and GENCOs, and privately-owned BOTs
(Mercados 2015). Between 2013 and 2020, it is expected that 28 percent of the 33,000 MW new
generation investment required, will be undertaken by EVN. Most, if not all the non-EVN
investment would ideally come from the private sector, since government policy now discourages
state enterprises such as PetroVietnam from further investment in power projects. The total
expected value of non-EVN (private) investment through 2020 is over US$28 billion.
63. A third key challenge was to increase efficiency and quality of service in the power sector
through competition. Attributing specific improvements to competition based on available data is
not possible, but there are some encouraging trends in increasing power supply efficiency and
quality of service in the power sector. Over the period of the PSRDPO series, there was an
improvement in the rate of generation-related outages. In 2014, as shown in table 1, only 5 outages
were recorded in EVN’s NLDC, compared to a peak of 181 in 2010 when serious shortages
occurred due to low reserve margin and poor hydrological conditions. In 2014, the majority of load
shedding was for protection reasons during commissioning tests of new large 600 MW coal-fired
power generators in the north. Only one shortage was caused by a trip of generators.
23
Table 1. Generation-related Outages 2012–2014
Year Maximum Capacity
Shedding (MW)
Total Energy Shedding
(MWh)
Number of Load
Shedding Events
2010 3,250 563,304 181
2011 1,215 3,979 8
2012 170 792 14
2013 300 855 6
2014 600 1,409 5
Source: Lahmeyer International 2015.
64. The ratio between energy and capacity shedding amounts to 2.3 hours, or 140 minutes.
This compares favorably with an international benchmark of 120 minutes. (Lahmeyer International
2015). This is in large part a result of significantly increased reserve margin.
65. As a result of new thermal capacity, there is an increase in total megawatts from thermal
sources participating in the VCGM. EVN data confirms that in a given year, the aggregate
megawatts of thermal power available in the VCGM is higher in periods of low hydropower output
(typically from October to May), suggesting that on average, planned maintenance coincides with
periods when hydropower is more abundant and indicating some efficiency in the interaction of
hydro and thermal power.
66. Transmission and distribution losses have dropped over the past five years from 10.15
percent in 2010 to 8.5 percent in 2014, of which distribution losses are estimated at 5.5 percent.
(Lahmeyer International 2015).
67. The GoV’s overriding objective of maintaining a stable power supply and avoiding shocks
was achieved through the period of the PSRDPO and some progress was made with regard to
diversifying sources of investment and improving efficiency. The extent to which the reform and
the support provided under the PSRDPO program contributed to this progress is assessed in terms
of the specific policy areas in the following sections. Given the high expectation for private sector
investment in power generation in the next five years, the assessment also considers progress in
readying the sector to rapidly scale up private sector investment in new generation.
Achievement of the Specific PDO Indicators
68. Achievement of the specific PDO indicators is summarized in section F. Of the seven PDO
indicators, two were achieved, two were largely achieved, two were partially achieved, and one
was not achieved. Further explanation is provided in section F, table (a) PDO Indicators.
Progress under Each Policy Area (Efficacy)
69. An assessment of progress in each policy area is presented below. In summary, target areas
of change that were most ambitious with regard to behavior and institutional change proved most
difficult to achieve: increasing transparency, reducing conflict of interest, and creating effective
competition in a sector where these concepts had little precedent and in the context of an economy
with limited experience of economic regulation of services. Progress was made in all these areas,
though not as much as was initially targeted. Changes that depended more on sound technical work
and stakeholder consensus, particularly under Pillar 4, were largely achieved, albeit with some
delay. Progress in the area of tariff reform – which involved both increasing transparency and
24
taking politically sensitive decisions including in adjusting the tariff structure, overall level, and
targeting of subsidy—was important. This progress, in some respects, exceeded initial targets (for
example, introduction of periodic tariff adjustments), while in others fell short of the original
outcomes (for example, regular annual tariff adjustments and cost-reflective tariffs). Progress in
the Tariff Reform Policy Area was particularly sensitive to the broader macroeconomic context.
Policy Area A: Development of a Competitive Power Market
Rating: Substantial
70. An achievement supported by the PSRDPO series was the conceptualization, design, and
operation of the VCGM. Key steps in this process are shown in Figure 12, which also shows key
steps in the process of establishing the VCGM that were supported by prior actions. Two other
achievements not shown in the diagram were also critical in developing the VCGM: setting up
the information technology and trading infrastructure, as well as building the human capacity in
NLDC and in the individual power plants’ and GENCOs’ market units. Box 1 provides a quick
summary of the major features of the VCGM design. Further detail is provided in Annex 7.
Figure 12. Timeline of Key Steps in Design and Launch of VCGM
Source: ICR authors.
Box 1. Summary of Conceptual Design and Key Steps leading to the Launch of the VCGM
The VCGM is a cost-based gross power pool. Direct participation is mandatory for all power generation entities
with a capacity in excess of 30 MW, with two exceptions: BOTs and SMHP plants. Foreign-invested BOTs have
long-term PPAs with the EPTC (the SB). These will be indirect participants, with the EPTC bidding on their
behalf (no impact on the existing PPAs). EVN owns 6,700 MW of SMHP plants. These are dispatched directly by
NLDC and the SMO, based on water valuation optimization modeling.
NLDC schedules dispatch through a security-constrained least-cost dispatch based on cost-based bids made on a
day-ahead basis. The hourly energy System Marginal Price (SMP) is calculated ex post as the highest bid
accepted in an unconstrained least-cost generation schedule. Energy generated is valued hourly at the spot price,
except for generation constrained-on due to system security and reliability that is valued at its bid price. To
enable recovery of fixed costs for efficiency generation reserves, a Capacity Add-On (CAN) payment is made,
25
except during off peak periods with low demand. The capacity to be paid to each generating unit is determined
through an ex post, next day unconstrained schedule to supply actual demand plus an operational reserve margin.
The CAN price varies per hour and is set to create incentives for generation to be available and provide
operational reserves in hours with higher demand.
All direct participants must have a standard VCGM contract (Standard Power Purchase Agreement - SPPA) with
the EPTC. For a new generation plant, the SPPA duration is up to 10 years from the contracted commissioning
date.
The SPPA is designed as a financial contract to hedge generators and the EPTC (the single buyer) against market
spot price volatility and reduce incentives for anticompetitive behavior such as increasing spot prices by
exercising market power. The contract coverage target is set by ERAV:
July to August 2012, contract levels: 95 percent (for all direct participants);
September 2012 to March 2013: 90 percent (for all direct participants);
From April 2013, revised market rules became effective, which allowed ERAV to set separate
contract levels for thermal power plants and hydropower plants:18
90 percent for thermal power plants;
80 percent for hydropower plants with storage greater than 2 days; and
90 percent for hydropower plants with storage of less than 2 days.
Target contract coverage has been gradually reduced to increase the exposure of both sellers (generating plants)
and purchasers (currently the EPTC, but in the future the PCs and eligible consumers) to transactions in the spot
market, working toward an actually competitive market.
To avoid excessively high or volatile spot prices, the VCGM design includes the following provisions:
Thermal generation is subject to a bid cap based on the fuel costs and efficient heat rate
(efficiency) of each generation technology, plus an allowance to cover variable operation and
maintenance costs.
Hydro generation bids are capped at the highest allowed thermal bid plus a small uplift. To
promote efficient use of hydro generation in a market environment, a floor to hydro bids is set in a
range of +/- 10 percent of hydro opportunity cost (calculated with a water value model/software).
An overall price cap applies to the spot market, designed to deliver an acceptable maximum price.
Generators are permitted to bid above this level and be paid the bid cap if their energy is
generated, but bids above the price cap do not set the SMP.
71. Two key issues specifically informed the development of the policy matrix for this policy
area: (a) the need to achieve sufficient generation capacity in the medium term through new
investment and increasing generation availability; and (b) the need to address security of supply
concerns through adequate operational reserve.
72. (a) Achieving sufficient generation in the medium term. Prior to the start of the
PSRDPO program, prospective non-EVN domestic generation project developers (that is, IPPs)
were encountering a lengthy negotiation process when attempting to sign PPAs with the EPTC,
sometimes only concluding a short while before plant commissioning. The lack of transparency
and delay in securing a PPA were viewed as major obstacles to attracting non-EVN investment.
18 In the original VCGM design (Decision 6713/QD-BCT, December 2009), the contracting level was specified to
be 0.9 to 0.95 in the first year, to be reduced in the following years (but not below a minimum level of 0.6). In
February 2013, Circular 03/2013/TT-BCT was issued in which the contracting level was specified to be in the range
from 0.6 to 0.95 and applied for each type of generator. Based on this Circular and the current hydrological
situation, the contracting level for hydropower plants with a large reservoir from April 2013 was set at 0.8 to reduce
the risk of low water availability in the dry season.
26
The VCGM was designed to address problems faced by non-EVN investors and thereby support
investment in the medium term, through mandating the development and use of standard
contracts for all direct VCGM participants. In 2010, transparent methodologies and procedures
to determine and approve the standard contracts and pricing for direct VCGM participants (that is,
EVN and IPPs) were established. Foreign-owned generation, BOTs, are not directly traded, and
the long-term PPAs are negotiated by the General Directorate of Energy in MOIT in a separate
process.19 Hence, the VCGM design does not directly facilitate new foreign investment. However
the VCGM, together with the restructuring and tariff reform, provided the potential for building a
track record of transparency, proper system and market operation according to the grid code and
market rules, and regular tariff adjustments. Such a track record will be important in attracting
both domestic and foreign private investment into the WEM in the longer term.
73. Effectiveness of the VCGM in attracting non-EVN investment in generation can be
assessed by considering: the extent of the contracting, (relating to PSRDPO Indicator 2); non-EVN
experience and views on the standard contracts; and the level of non-EVN investment that can be
attributed to the VCGM.
74. The extent of the contracting. Currently 51 percent of installed generation capacity
participates in the VCGM directly. ERAV confirmed that all of the direct VCGM participants are
now operating under standard contracts. Data on quantity of energy contracted and quantity of
energy metered in MWh through mid-2015 is shown in Table 2. The average rate is about 89
percent. Challenges in achieving the targeted contract levels (noted in Box 1) include: demand
forecast errors that are at times significant between the Month-Ahead Plan, which is used as the
basis for Qcontract determination, and actual demand (Qmetered); differences in hydrological
conditions; and alignment of planned maintenance and contract allocation. NLDC is working to
address these identified issues. An average contract level of 89 percent of VCGM directly-traded
capacity under contract (based on installed MW) is approximately equivalent to 90 percent of
the demand20 (the value set for PDO Indicator 2). With regard to the extent of contracting, both
the ERAV target levels and the PSRDPO indicator have been met.
Table 2. Quantity of Energy Contracted and Quantity of Energy Metered Through Mid-2015
July 2012–
December 2012
January 2013–
December 2013
January 2014–
December 2014
January 2015–
June 2015
MWh
Qcontract/
Qmetered
(%)
MWh Qcontract/ Qmetered
(%) MWh
Qcontract/
Qmetered
(%)
MWh
Qcontract/
Qmetered
(%)
Qm 22,953,306
85
53,462,441
90
62,626,418
85
35,177,791
89
Qc 19,437,489 48,311,073 53,447,007 31,228,111
Source: ERAV
19 Separate to the PSRDPO Program, the Bank provided TA related to the BOT contracting process. 20 Since the 2014 reserve margin is about 50 percent.
27
75. Assessment of experience with the standard contracts. There have been some reported
difficulties for generators with regard to the contract quantity allocation, such as contract levels
inappropriate for their technologies and (in some cases) fuel contracts, although it is not clear
how frequently these issues are encountered. The Bank-financed consultancy to develop the
GENCO Equitization Strategy21 (ITAC 2015, ongoing) included a market sounding exercise.
Some specific concerns noted by the private sector with respect to standard PPAs included the
following:
The maximum duration of the SPPAs is 10 years, not a long enough tenor given the
much longer plant lifetimes and the need to have an assured revenue stream for a longer
period to recover costs.
There are differences between the SPPAs and the PPAs for BOT projects. As the reform
progresses and as greater private sector investment is sought through the SPPAs, this
is somewhat of an artificial difference that creates the impression of a ‘non-level
playing field’.
The SPPAs need to provide for adequate adjustment for changes in foreign exchange
rate and fuel costs.
Flexibility is needed with respect to fuel supply agreements.
Some of the terms and conditions of the SPPAs are a concern for potential private
investors, for example, the handling of force majeure.
There is a need to incorporate some form of payment risk mitigation.
Based on this feedback, the study recommended a complete PPA review, including a focus on cost
pass through, capacity payments, and investor protections against changes.
76. The level of non-EVN investment that can be attributed to the VCGM. While there
was good progress on investment during the period of the PSRDPO series, almost all the new
investment through 2014 was committed ahead of the launching of the VCGM. The investment
decisions that could be credited to the VCGM would be those projects for which the VCGM was
known about prior to final investment decision and that face exposure to the VCGM. As shown
in Figure 13, of the 21,000 MW incremental capacity from 2010 and expected through 2017,
investment decisions for almost 7,000 MW would likely have factored in the VCGM. Of these
projects, 1,200 MW are directly exposed to the VCGM. A further nearly 6,000 MW are not
immediately exposed to the VCGM, but likely will be in the future. The directly-exposed 1,200
MW are EVN-owned. The rest is a combination of EVN and IPP projects that will initially not
be exposed, but in the longer-term can expect to be. (IES, 2014). Based on these figures, it can
be concluded that the VCGM has not had a significant impact on attracting non-EVN investment.
21 Based on market feedback covering both existing and greenfield investments from 24 industry participants, of
which eight have invested in Vietnamese power plants, representing Vietnamese, regional, and international
companies.
28
Figure 13. Projection of Committed Generation Capacity (Cumulative) Based on Projects under
Construction
Source: ICR authors, based on IES 2015f
77. Overall, there has been good progress in developing and putting in place the standard
power purchase contracts and procedures, although a review and revision of the SPPA may be
needed to make it a more ‘bankable’ instrument. Evidence suggests that, to date, the VCGM has
not played a strong role in attracting non-EVN investment.
78. Addressing security of supply concerns through adequate operational reserve. Mention of the operational reserve in the PSRDPO 1 PDO reflects the importance attached to
improving the operation of the grid in this respect. The policy matrix for the first operation
included a milestone for issuance of a grid code, which was accomplished in April 2010. The
Grid Code defines various levels of reserve including frequency regulation reserve, spinning
reserve, fast start, cold start, black start, reliability must run and voltage regulation. ERAV issued
the Procedure for Planning, Scheduling, Frequency Reserve and Spinning Reserve in 2015, in
which, NLDC is responsible for calculating and publishing the total demand of frequency reserve
and spinning reserve for the next year, next month, next week, and next day. The total capacity of
the spinning reserve is defined based on demand of power system and available capacity of
generating units depending on the time/period of calculation. From PSRDPO 3 until end-2015,
spinning reserve/frequency control reserve has been about 2–3 percent of total available capacity
of generation. Improving the hourly operational reserve was the focus of PDO Indicator 1. It is a
measure both of improvement in overall security of supply and of the proper application of the
grid code by the system operator (SO).
79. Market efficiency incentives were specifically included to improve the availability of
individual thermal power plants through the design of the capacity payment. The Capacity Add-
on price varies per hour and is set to create incentives for generation to be available in hours with
higher demand.
80. The proper functioning of NLDC as the System Operator was also the focus of PDO
Indicator 2b, focusing this time on transparency in the VCGM by setting a target that the VCGM
spot market price would be disclosed on the SMO website to which the public has access. NLDC
0
5000
10000
15000
20000
25000
2010 2011 2012 2013 2014 2015 2016 2017
VCGM Factored in Planning VCGM Did Not Factor in Planning
29
publishes the spot market price daily on its website and the website of the electricity market. The
information is available to market participants, but not the public as per the indicator.22
81. It is worth noting that the assessment of the operation and outcomes of the VCGM referred
to above and carried out at the end of 2014 (when the VCGM had been in operation for about 2.5
years), identified some critical aspects of the VCGM that were not yet working properly. The
assessment was commissioned by ERAV, with Bank support, as a specific input to the design of
the WEM. As such, all the issues identified will be considered and will inform the ongoing work
to design the WEM. For completeness, the main areas identified at the end of 2014 as needing to
be addressed moving forward with the WEM included the following:
(a) Overall, less than half the installed capacity participates directly in VCGM and this
prevents the market price from adequately representing the marginal price of the
system overall.
(b) The relationship between the System Marginal Price (SMP) for energy and the
demand is sometimes weak, in part because many generators bid most of their
energy at either the floor or the ceiling of the price cap, and the SMHPs follow a
fixed hourly generation profile. There is some evidence that the SMP cap is too low
to allow the entry to the direct market of some of the generators that are currently
indirectly traded.
(c) In the generation spot market, NLDC handles a large volume of disputes, particularly
in contract quantities, and this contributes to delays in publishing the settlements
(typically six days after the transactions take place). Demand and price projections
were sometimes observed to not be accurate.23
(d) The approach for determining marginal water values for the large hydro plants
remains challenging and water values are not consistently reflective of the prevailing
hydrological conditions (IES 2014). As a result, the predictability and transparency
with respect to the spot market quantities and pricing still needs improvement.
82. Generators and NLDC are continuing to gain experience in participating in and operating
an electricity market. ERAV is actively assessing the performance as an input to improving the
VCGM and to inform the design of the WEM. As an intermediate stage in the process of
developing the WEM, the VCGM is a valuable and significant step.
83. The rating for this policy area takes into account:
the value of the VCGM as a learning process in a country that has no previous
experience in power markets, and where the VCGM is an intermediate stage in the
22 Related to the goal of increasing transparency, which is critical for market operation (both the VCGM and the
WEM), the 2014 assessment of VCGM outcomes highlighted some other areas where transparency could be
improved: information made available to the public could be increased and information dissemination to market
participants could be less restricted (participants mainly can only see their own outcomes, but not those of others)
(IES, 2014) 23 Day-ahead and hour-ahead demand projections tend to systematically overestimate the required amount of
demand (IES 2014).
30
power sector reform, with the major competition and resulting benefits expected
with the implementation of the WEM;
the achievement of several important steps including putting in place the standard
contracts, and the trading infrastructure and knowhow;
achievement of the specified indicators (one fully achieved, one largely achieved);
important issues identified that limit the effectiveness of the VCGM, but at the same
time the importance of having undertaken an objective assessment as an input to
WEM design; and
little clear evidence of impact of the VCGM on power system performance.
Based on the above, the overall rating for this component is Substantial.
Policy Area B: Power Sector Restructuring
Rating: Modest
84. Issues to be addressed by the sector restructuring included concerns about conflict of
interest (that is, cross-ownership of generation and other functions including the SMO) and
concerns about nontransparent and discriminatory generation dispatch including strategic hydro
operational planning. Transparency—both in availability of market information and in the
interactions among market players—and the perception of a ‘level playing field’ are important
underpinnings of a competitive market. Addressing actual and perceived conflict of interest and
increasing transparency were seen as fundamental to development of a competitive market and
hence were primary areas of focus under this policy area.
85. The original concept for the restructuring policy area envisaged several measures to
address conflict of interest and market power concerns: planned independence of GENCOs with
limits on market share,24 VCGM standard contracts with standard pricing methodologies to ensure
similar treatment for all generators directly participating in the VCGM, regardless of ownership;
plans to ring-fence costs, revenues, and information for NPTC and NLDC until separated into
independent companies (in the case of NLDC, until it became the independent SMO),25 and
creation of an independent SMO.26 Figure 14 shows the timeline for key steps in the restructuring
process anticipated at the time of DPO 1, as well as the actual progress in sector restructuring.
Figure 16 shows the sector structure in 2015 at the completion of the PSRDPO series.
86. The planned timeline for the transition to independent GENCOs and an independent SMO
was ambitious, both in the context of Vietnam and considering experience in other countries. As
24 DPO 1 indicative trigger for DPO 3: “MOIT establishes each successor independent Generation Company as a
One Member Company 100% State owned, with no cross ownership with transmission or SB, and registered as
market participants in VCGM.” 25 This was included in DPO 1 as an indicative trigger for DPO 2: “Ring fencing regulations of costs, revenues, and
information for NPTC and for NLDC until separated into independent companies.” It was subsequently dropped as a
prior action. Elements were included as milestones and the regulation was issued. 26 PSRDPO 1 indicative trigger for DPO 3.
31
an illustration of the time needed for power sector reform in other countries, Figure 15 shows the
timeline for key steps in the power sector reform process in Turkey. The timeline for Turkey’s
power sector reform begins in 1994 when the integrated power utility was first restructured in
preparation for the market, with the fully liberalized power market achieved some 22 years later.
The same diagram shows the timeline for key steps in the Vietnam power sector reform to date,
beginning in 2004 when the Electricity Law was introduced. While the sequencing of the reform
steps in the two countries is different, the point of the comparison is that current progress and plans
for the Vietnam power sector reform—even taking into account the delays that occurred during
the PSRDPO program— project a timeline for full reform that is similar to the duration of power
sector reform in Turkey.
87. While the schedule was delayed, the importance of these key steps continued to be
recognized in the issuance of the updated Power Sector Reform Road Map (November 2013)
which confirms the GoV’s intention to follow through on creating GENCOs and the SMO as
independent entities.
Figure 14. Timeline of Planned and Actual Steps in Power Sector Restructuring
Source: ICR authors.
88. As shown in Figure 14, there has been some progress in unbundling EVN since the start of
the PSRDPO program: EVN generation has been separated into three generation subsidiaries
(GENCO 1, 2, and 3) and the SMHP, which remain under the direct ownership of EVN.
Additionally, the 11 EVN power distribution companies have been consolidated into five Power
Corporations, wholly-owned27 subsidiaries of EVN, while absorbing some of the LDUs. This was
an important step to create distribution companies of similar size and customer mix to be ready to
become viable buyers in the wholesale market. The Electric Power Trading Company (EPTC –
27 One of the former 11 distribution companies had been equitized some years ago but not successfully and was
absorbed by the PC.
32
acts on behalf of EVN to carry out the function of the single buyer) and the National Load and
Dispatch Center (NLDC – the system and market operator) remain as units within EVN. The
National Power Transmission Company (NPTC) remains as a wholly-owned subsidiary of EVN,
with regulatory accounting requirements in place on costs and revenues.
Figure 15. Timeline for Key Steps in the Power Sector Reform in Turkey Compared with the Timeline in
Vietnam’s Power Sector Reform
Source: ICR authors.
89. Despite this progress, two factors form the basis for the Modest rating: (a) as a result of the
postponement of independence of GENCOs and SMO, progress in addressing conflict of interest
and transparency issues with respect to interactions among EVN-owned entities was limited and
(b) lack of evidence of proper functioning of the SMO based on the market rules and Grid Code
meant that progress in addressing perceptions of conflict of interest and lack of transparency with
respect to system and market operation was also limited. These points are explained below.
33
Figure 16. Structure of Power Sector in 2015
Source: ICR authors.
90. Based on an EVN study, it became apparent during preparation of PSRDPO 2 that
independence of GENCOs from the EVN holding company could not be achieved without
significant equity injection from the GoV, which was not forthcoming. The GoV decided to
initially keep GENCOs as EVN subsidiaries because of concerns that being new companies,
GENCOs would not be able to obtain financing, which could jeopardize investment in new
generation needed to meet demand and which EVN could support financially if the GENCOs
remained subsidiaries. Following discussions and consultations, in April 2011, the government
required MOIT to instruct EVN to “develop the proposal for the establishment of the three
GENCOs as subsidiaries fully owned by EVN, to be separated later into companies independent
of EVN and to start equitization and gradually separate for all to become independent GENCOs
(no EVN ownership) by 2014 for the start of the WEM period” (PSRDPO 2 prior action). This
revised target timeline has been extended given the complexity of the process and the need for
development of a strategy. The GENCOs remain under EVN ownership.28
28 In parallel and with separate TA funding, the GoV with Bank support is undertaking an assessment of the
structuring and options for equitization and divestiture of the GENCOs. The resulting report will inform the next
steps on GENCO equitization and divestiture as part of the proposed follow-on PSRDPO series currently under
preparation. The study considers options for the size of stake to be retained by EVN. The MOIT issued Decision No.
551/QD-BCT of February 5, 2016 on equitization of GENCO 1, Decision No. 1125/QD-BCT of March 24, 2016 on
equitization of GENCO 2.
34
91. GENCO independence and SMO independence would have created financial and decision-
making separation between generation and system and market operation and would have reduced
the maximum generation market share owned by a single entity. The postponement of
independence of the GENCOs and postponement of establishment of an independent SMO
resulted in the continuation of the dominant position of EVN in all activities in the power sector.
No new milestones or prior actions were added to address conflict of interest and transparency
when the postponement of the GENCO and SMO independence was agreed, so the design of the
PSRDPO program did not directly compensate for this lost opportunity to reduce conflict of
interest and increase transparency.
92. The PSRDPO program included an emphasis on developing the proper functioning of the
SMO, aiming to have a well-functioning and credible SMO ready to become an independent entity
ahead of the start of the WEM. After the decision to postpone the creation of an independent
SMO,29 this restructuring step was still recognized as essential for the next stage, the WEM. The
indicators on developing transparency and proper operation of the SMO remained relevant, and a
PSRDPO 1 milestone30 supported the establishment of the methodology and procedures to
calculate and approve system and market operation costs (SMO fee). The procedures and
regulations on SMO fees were important steps in providing NLCD some predictability with regard
to revenues.
93. One of the outcomes sought in this policy area was for the SMO to provide “efficient, and
nondiscriminatory services following VCGM rules, codes, and regulations.” The primary way to
demonstrate definitively that the SMO was providing this quality of service was through a publicly
available independent market audit report (PDO Indicator 4). This would have served to
compensate to some extent for lack of SMO independence, in terms of building investor
confidence in fair market operation. However, this audit was not undertaken.
94. NPTC regulatory accounting. Another aspect of the restructuring was the establishment
of regulatory accounting methodology and procedures for accounting separation of each electricity
licensee, including PCs and NPTC (MOIT Circular).31 By establishing regulatory accounting, the
licensee is required to present its financial results separating costs and revenues from other
activities and therefore costs and revenues for tariff setting are ring-fenced or ‘unbundled’ from
other business. One of the goals of introducing regulatory accounting was to ensure financial
independence and improved financial performance of NPTC. As additional assurance, a financial
29 PSRDPO 1 included an indicative trigger for PSRDPO 3 for MOIT to “establish the independent SMO as a One
Member Company 100 percent state-owned and with no cross-ownership with other electricity activities”. This
indicative trigger was not included in PSRDPO 2, reflecting a GoV decision that establishing an independent SMO
would take longer to achieve. 30 MOIT Circular 13/2010/TT-BCT of April 15, 2010. 31 PSRDPO 1 included an indicative trigger for PSRDPO 2 on ring-fencing regulations of costs, revenues and
information for NPTC and NLDC, until separated into independent companies. Note that as NPTC was already a
wholly owned subsidiary of EVN before the PSRDPO series started, ring-fencing was already implied but not
happening in practice. However, the issue to be addressed was clear: ensuring NPTC financial independence and
improved financial performance. The trigger was eliminated because (a) concerns on NPTC were addressed through
the financial action plan in TD2 additional financing (VN Loan 8026 AF) where NPTC was required to collect
transmission charges based on its costs independently of EVN parent company, and (b) NLDC on its own was not
considered critical to merit a prior action on ring-fencing.
35
action plan was included in the Second Transmission and Distribution Project additional financing
(VN Loan 8026 AF) where NPTC was required to collect and EPTC required to pay “transmission
charges based on its costs independently of EVN parent company.” However, in spite of the
regulation, the financial action plan appears not to have been fully implemented and revenues to
NPTC remain below what is needed for operation and investment (Mercados 2015).
95. Overall there has been progress in providing increased market information, including
publishing market data on the SMO website.32 However, there remain a number of areas where
greater transparency is needed especially in terms of transparency in the interactions among the
various EVN-owned entities. NLDC remains a fully dependent unit within EVN and is subject to
approvals and decisions by the EVN Board. For example, NLDC must seek EVN Board approval
prior to issuing reports. Consequently EVN is able to influence NLDC operation should it choose
to do so. The implementation of standard contracts between EPTC and direct participant generators
in the VCGM helped to address some important aspects of actual and perceived conflict of interest
by non-EVN generators (IPPs), as discussed above. Further work is needed to address the conflict
of interest concerns especially with respect to the governance arrangements. EVN subsidiaries
effectively operate as units of EVN with very limited autonomy, and boards appointed by EVN
headquarters. Cash flow is managed centrally and allocation of liabilities between companies can
easily be altered to change the performance of an individual subsidiary (Mercados 2015). While
these arrangements remain, the perception of conflict of interest is likely to persist.
96. Although there has been progress in improving market transparency, overall the
interactions in terms of costs, revenues and decision-making among the EVN-owned entities are
not transparent. With respect to the operation of the SMO, the restructuring has not been successful
in addressing concerns about lack of transparency.
97. The direction and key elements of the restructuring needed to implement the WEM remain
unchanged although the ambitious timeline for the restructuring was adjusted during the course of
the operation as the challenges became more evident. By itself, this delay in making the GENCOs
and SMO independent would not necessarily affect the rating, had there been more substantial
progress addressing concerns about conflict of interest and lack of transparency, the key issues
motivating action in this policy area. The ‘modest’ rating reflects the lack of progress in addressing
these issues, rather than the delay in the implementation of the restructuring.
Policy Area C: Electricity Tariff Reform
Rating: Modest
98. The 2004 Electricity Law directs that electricity tariff reforms be undertaken to raise prices
to reflect costs of supply, to be at par with countries in the region to attract private investment.
Before the start of the PSRDPO series, electricity tariffs were not regularly updated when costs
increased, resulting in a situation where the average retail tariff was too low to cover the cost of
electricity supply and new investment. Tariff increases were promulgated by decision of the PM,
following nontransparent negotiation between EVN and the government and then within the
32 The NLDC public website (google-translate version of the Vietnamese site) shows the load (MW) and market
price (VND/kWh) on an hourly basis for north, central, and south regions for the previous day.
36
government itself. Both the tariff level and the nontransparent process of tariff adjustment
represented deterrents to new, especially private sector, investment. Large cross-subsidies existed
between tariff categories.33 Subsidies intended to help low-income consumers were poorly targeted
and many poor rural consumers did not benefit from the subsidy.
99. Objectives of tariff reform. Key objectives of the tariff reform were to move the sector
to a sustainable financial footing as the basis for attracting new investment (that is, tariffs should
provide revenues sufficient to cover the cost of supply including generation, transmission,
distribution, and system operation costs); to improve the targeting of subsidy for electricity to
reach the poor, including in rural areas, without providing subsidy to wealthier consumers; and to
significantly reduce cross-subsidy especially between industrial and residential and commercial
and residential, so that prices paid by various end-user categories more closely reflected the cost
of supply.
Reform of the Average Retail Tariff
100. From the point of view of attracting investment and financing, several aspects of tariff
reform were critical. In particular, it was important to build the perception among potential
investors and lenders that regulated tariffs would support recovery of costs, including debt
servicing, and generate a return on investment.34 Three elements of reform were particularly
important in this regard:
(a) Putting in place tariff regulations setting out a clear, transparent method for
determining the regulated elements (transmission, distribution and system operation);
a mechanism for passing through efficient generation costs to the retail tariff; and
technical determination of average retail tariff that takes the above into account;
(b) Putting in place a tariff adjustment process that is transparent and timely and
demonstrates application of the regulations;
(c) Achieving average retail tariff level that covers costs, including a return on
investment.
101. Tariff regulatory framework and tariff adjustment process. Table 3 shows the key
steps that have been accomplished in reforming the tariff regulatory framework, building from the
2004 Electricity Law that directed that electricity costs should reflect the cost of supply and that
decision-making authority for retail tariffs would remain with the PM.
33 Estimated cross-subsidies from industrial and commercial consumers were at US$370 million in 2007. 34For investors and lenders of projects exposed to the market, it is important that regulated tariffs reflect the market
price of generation. For investors and lenders not directly exposed to the market but instead relying on long-term
PPAs (such as for BOT projects), the price for the electricity specified in the contract would be critical. However
even in these cases, if the regulated tariff levels are perceived to be too low (or the tariff adjustment process too
uncertain) to cover the overall power supply costs, investors’ perceptions of the payment risk could be heightened,
which could deter investment or increase the returns expected.
37
Table 3. Tariff Regulatory Framework Key Elements Relevant for Attracting Private Investment
Instrument
Key Elements Relevant for Attracting Private Investment
Cells with light shading: Positive from the perspective of attracting new investment
through a market approach
Cells with dark shading: May require revision from the perspective of attracting
new investment through a market approach
Electricity Law
2004
Directs electricity tariff reforms to raise prices to reflect costs of supply
PM retains tariff decision-making authority
PM Decision 26:
(December 2006)
The Road Map
Sets out transformation to market-based, cost-reflective tariffs
From 2010, the electricity retail price would be based on the market price
PM Decision 21
(February 2009)
Tariffs will be updated annually
Transparent annual tariff-setting from 2010–2012 based on cost recovery principles,
including power supply cost components
Annual average retail adjustments within a range of 5 percent of the last approved
average sales price delegated to MOIT.
MOIT Circular 13
(April 2010)
Sets system market operator fees
MOIT Circular 14
(April 2010)
Establishes regulations to determine and approve NPTC transmission revenue and
tariffs based on a cost-plus approach
PM Decision 24
(April 2011)
Intra-year tariff adjustments to reflect changes in generation costs; up to one
adjustment in a 3-month period
Tariff adjustments shall be managed taking into consideration efforts to maintain
macroeconomic stability and contain inflation
MOIT Circular 31
(August 2011)
Retail tariff to be adjusted according to basic input parameters and fuel price.
Amended Electricity
Law (effective July
2013)
Emphasizes public and transparent adjustment of the electricity retail price regarding
changes of component elements
Formalizes coordination with the MOF when MOIT prepares the price frame of the
average electricity retail price, mechanism of adjustment of price, and structure of the
electricity retail price table
Introduces formal role of the MOF in approving as well as in guiding the methods for
setting the prices brackets of generation, wholesaling, transmission, auxiliary
services, regulation, and administration
PM Decision 69
(December 2013)
MOIT approval if the cost increase is 7 to 10 percent and still within the approved
tariff range; Cost increases over 10 percent or beyond the established range for
average tariffs still require PM approval
If the cost increase is less than 7 percent, EVN must wait until the next tariff
adjustment to recover the cost
A mandatory 1-year delay for cost recovery of any increase over 7 percent
Revised retail tariffs are calculated every 6 months instead of every 3 months as
previously allowed
Circular 12 (March
2014)
Defined methodologies and procedures for the annual average retail tariff setting
based on costs of generation, transmission, distribution, retail, administration, and
ancillary services.
The calculation and explanation of total cost of retail distribution for the PCs in the
years N-1 and N included.
102. In line with the move to a market approach, the 2006 Power Sector Reform Road Map
specified that retail tariffs should be based on market cost. PM Decision 21 in February 2009 set
out the principles to transition toward market-based, cost-reflective tariffs by stipulating the
separation of the average electricity retail tariff into the cost components: generation, transmission,
system operation, and distribution. The same decision set out important elements of the new
38
process for tariff adjustments: adjustments of up to 5 percent were delegated from the PM to the
Minister of MOIT; tariff adjustments would take place annually; and specification of a process in
which tariff adjustments are proposed by EVN and reviewed by ERAV, before ERAV makes a
recommendation to MOIT or the PM. Regulations setting out the determination of system
operation fees and the determination and approval of transmission revenues and tariffs followed
in 2010.
103. Continuation of the tariff reform process in 2010 and 2011 took place in the context of a
macroeconomic environment in which the GoV policies shifted from supporting growth to
restoring macroeconomic stability through a comprehensive stabilization package announced in
February 2011 (see section 1.1). PM Decision 24 in April 2011 setting out further direction for
tariff reform reflected both the GoV focus on macroeconomic stability and the recognition of the
impact of volatility (for example, in inflation, exchange rate) on the cost of generation. Decision
24 introduced intra-year adjustments—up to one adjustment in a three-month period—to reflect
changes in generation costs.35 This was a very positive step from the point of view of allowing
revenues from the sale of electricity to keep pace with the changing costs of supply, and
demonstrating to potential investors that regulated retail tariffs would provide sufficient sector
revenue to cover the changing costs of generation.
104. Decision 24 also made electricity tariff adjustments subject to larger considerations of
macroeconomic stability and containing inflation. This step was fully consistent with the GoV
objective of implementing power sector reform following a gradual approach, avoiding shocks or
disruptions to the economy. However, it was less positive from the point of view of building
investors’ confidence in the tariff regime, by setting macroeconomic considerations ahead of the
principle of cost recovery tariffs, at least in the short term. The amended Electricity Law (effective
in July 2013) introduced formal consultation with the MOF in the process to approve any circular36
on tariffs. PM Decision 69 in December 2013 pulled back somewhat on earlier progress, extending
the period between intra-year tariff adjustments from 3 to 6 months and delaying tariff response to
changes in costs by specifying that if the cost increase is less than 7 percent, EVN can recover the
cost in the next tariff adjustment, and by putting in place a mandatory 1-year delay for cost
recovery of any increase over 7 percent. This delay in tariff adjustment had a negative effect on
the overall power sector financial situation by mandating a significant lag between changes in costs
and changes in revenues37.
105. A very significant, positive step in establishing the tariff regulatory framework was
achieved with MOIT Circular 12 (March 2014) which set out the methodology (that is,
regulations), sequencing, and procedures for annual adjustment of the average electricity retail
tariff level. Circular 12 defines the methodologies and procedures for determining the allowed
revenues of the PCs for electricity supply to end users. The allowed revenues are determined to
ensure the PCs will recover all reasonable costs of provision of electricity services to their
customers, including energy purchases, transmission services provided by NPTC, own distribution
and retail services, and sector administrative costs. The Circular sets out the methods for
calculating the cost of generation, administration and auxiliary services, and distribution / retail. 35 Transmission, distribution, system operation, and administration costs would continue to be adjusted annually. 36 Circulars are used to set methodologies (that is, regulations) and to specify tariff increases approved by MOIT. 37 It also has the potential to increase the risk of the need for large tariff adjustments when adjustments do take
place.
39
However for generation in particular, there is a lack of clarity in terms of what is included and how
the specific elements are determined.
106. The transparency of the formal tariff setting process has been improved since 2008. The
process now involves EVN submission of a tariff request for ERAV review. ERAV reviews and
makes its recommendation to MOIT/PM including justification of costs. Information is made
available to the public, in some cases stimulating extensive discussion in the media (as was the
case for the 2011 tariff adjustment). However the tariff process still lacks full transparency. NPTC
and the five PCs submit cost proposals to EVN Holding Company, which reviews and then submits
a joint tariff proposal reflecting its own opinion to ERAV for appraisal and approval by MOIT.
The final decision sets out the cost/revenue for each component. Transmission tariffs are calculated
and charged separately, as are auxiliary services but criteria for performance-based transmission
rates are not yet established. Recent analysis (Mercados 2015) suggests that the current regulatory
scheme under ERAV for PCs and the NPTC (Circulars 12 and 14) to ensure distribution and
transmission business receive a reasonable return are not fully enforced.38
107. There remain some important further steps to complete the tariff framework39 and
enforcement, and to put in place a process40 which would assure potential investors that tariffs
would support cost recovery. However, the progress so far, culminating in the regulations and
procedures for annual adjustment of the average electricity retail tariff level (Circular 12),
represents a transformation in the calculation of retail tariffs and puts in place the major elements
of the first experience of economic regulation of basic infrastructure services in Vietnam.
108. Implementation of tariff adjustments. Figure 17 shows the average retail tariff
adjustment history since 2005. By the time of the tariff adjustment in July 2008, tariffs had been
kept constant for 18 months. Even with the 2008 increase, EVN incurred a net loss of VND 7,319
billion (US$438 million) in 2008 on net sales revenue of VND 63,732 billion (US$3.82 billion),
primarily due to a VND 10,126 billion (US$606 million) foreign exchange loss on EVN’s foreign
currency debt, resulting from impacts of the financial crisis. EVN did not meet either the self-
financing or debt service covenants specified in Bank projects at that time. The tariff increase of
6.57 percent in March 2009 (a prior action for DPO 1), brought the tariff to VND 948/kWh, which
reportedly reflected the actual cost of supply in 2008.
38 Bulk supply cost has been recently regulated by Circular 12/2014, transmission tariffs are regulated by Circular
14/2009, and amendments and SPPAs are regulated by Circular 42/2010. 39 ‘Cost recovery’ is based on ‘efficient costs’, the definition of both terms have yet to be set out. (Mercados 2015). 40 For a market to function effectively and attract investment, tariff decisions should be insulated from
considerations other than strictly economic and financial. It is likely that achieving the full benefit of a wholesale
market, including attracting investment from private sector, will require putting in place a system and demonstrating
a track record of transparent and prompt tariff adjustments that take into account cost of supply. This could be
achieved, for example, through transfer of tariff-setting authority to an independent regulator. Also allowing more
timely adjustment of costs, for example, not waiting a year to make adjustments that are less than 7 percent will
likely be important.
40
Figure 17. Average Retail Tariff in Nominal VND and US$, 2005–2015
Source: ICR authors.
Note: Monthly average exchange rate from OANDA.com; average retail tariffs in Vietnamese
dong and effectiveness dates from legal documents.
109. As per PM Decision 21 the electricity tariff was adjusted in March 2010 to VND 1,058
/kWh. The method used to calculate this increase was based on the principles set out in the PM
Decision of February 2009. However, the expected costs for 2010 on which the March 2010 tariff
increase was based, turned out to be much lower than actual 2010 costs. Drought in 2010 led to
increased reliance on thermal generation, significantly increasing EVN’s cost of generation and
power purchase. In addition, as in 2008, power sector costs were also affected by high inflation
and currency depreciation.
110. Recognizing the 2010 shortfall, the annual tariff increase proposed by EVN for March,
2011 included the recovery of actual costs in 2010 as well as the forecast 2011 costs. After ERAV
review, MOIT/ERAV submitted to the government tariff increases under three scenarios on
recovery of pending 2010 costs. Due to an over-riding concern about inflation, the PM decided to
approve an average retail electricity tariff in March 2011, covering expected costs for the next 12
months but not 2010 pending costs and losses, noting that these would be recovered in the future.
The measures introduced in PM Decision 24 for intra-year adjustments, were intended to help
avoid the accumulation of a backlog going forward. A second electricity tariff increase of 5 percent
was approved at the end of 2011 to apply as of December 20, 2011, to cover forecast costs of
supply for 2012, but again without recovery pending costs and exchange losses of EVN.41
111. Tariffs were adjusted twice in 2012. While nominal average electricity tariffs increased by
53 percent from January 2010 to January 2015, cumulative inflation for the same period was
41 The MOIT Circular announcing the electricity tariff as from December 20, 2011, recognizes pending costs (to be
recovered in future tariff increases) and notes that the average electricity tariff required to recover all pending costs,
and include 10 percent return of equity for EVN, would be VND 1,584.1 /kWh, which would have represented a
27.5 percent tariff increase.
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0
200
400
600
800
1000
1200
1400
1600
1800
Average Retail Tariff in VND and USD (2005 to 2015)(average monthly USD/VND exchange rate)
avg retail tariff (VND) avg retail tariff (USD)
41
approximately 56 percent. The combination of the shortfall in costs recovered by the 2010 tariffs
and the fact that real tariffs were significantly eroded by inflation between 2010 and 2015, made
it clear that further real term increases in tariffs would be needed to allow for full cost recovery
and create an environment that would attract private investors. A 5 percent increase took place in
August 2013, followed by no further increase until March 2015 when tariff was adjusted by 7.5
percent.
112. The most recent in-depth analysis available (largely based on 2013 data and hence not
taking into account the 2015 tariff increase) shows that the current tariff is substantially below cost
recovery levels, noting that “between now (2014) and the second half of 2016 there is an
overwhelming need to increase the retail tariffs by up to the 10 percent maximum allowed under
Circular 2165 each semester.” (Mercados 2015).
113. Support under the PSRDPO series for reform of cost recovery tariffs. Prior actions in
the PSRDPO program supported critical steps in the reform of the regulatory framework,
specifically PM Decision 21 (DPO 1, Prior Action 4 and Prior Action 5), Decision 24 (DPO 2,
Prior Action 5) and Circular 12 (DPO 3, Prior Action 4). The PSRDPO program initially aimed to
‘maintain cost recovery’ tariff levels, following from Decision 21, which put in place the 2009
tariff adjustment (DPO 1, Prior Action 4) setting tariffs at 2008 cost recovery levels and specified
implementation of transparent annual tariff setting from 2010–2012 based on cost recovery
principles. However, recognizing the challenges with regard to achieving macroeconomic stability
and the GoV decision to prioritize macro considerations over achieving full cost recovery in
electricity tariffs in the near term, the focus of the PSRDPO program shifted to ‘a gradual transition
to cost recovery levels’, with emphasis on getting the necessary framework in place while
recognizing that reaching full cost recovery would take some time. The end-of-program indicator
was first revised in DPO 2 to allow for more flexibility in the timing of the annual tariff
adjustments. Finally, in DPO 3, the end-of-program indicator for the Tariff Reform Policy Area
was revised to focus on the approval of critical procedures for annual tariff determination and
periodic adjustment, rather than implementation of an annual adjustment. The revised end-of-
program indicator was achieved.
Targeting Electricity Subsidies to Reach the Poor, Including in Rural Areas
114. Up until 2008, all EVN residential customers paid the same subsidized rate (VND 550
/kWh) for the first 100 kWh of electricity. The second block of monthly consumption of 100–150
kWh was also slightly subsidized. Approximately 50 percent of rural consumers were supplied by
LDUs, private sector or cooperative suppliers receiving supply from PCs at medium voltage and
on-selling to consumers at low voltage. Until March 2009, tariffs were set by the LDUs with
provincial government oversight. Formally, these tariffs were capped by the PM at VND 700/kWh,
but anecdotal evidence suggested that some LDUs charged more. Targeting of the subsidy was
weak and many poor rural consumers did not benefit from the subsidy at all.
115. In March 2009, Decision 21 introduced two important changes. It mandated national
uniform tariffs, applying to all distribution companies, ensuring rural residential consumers paid
the same tariff as their urban counterparts. Decision 21 also modified the national residential
incremental block tariff structure. The first 50 kWh per month of consumption was subject to a
‘lifeline’ tariff to be between 60 percent and 65 percent of the average sale price of electricity.
42
Accordingly, the lifeline tariff was set at VND 600/kWh (that is, 63 percent of the average tariff,
VND 948.5/kWh). The 51–100 kWh block tariff was set at the average cost price without profits
or VND 865/kWh in 2009, which was equivalent to 91 percent of the average sale price of
electricity. Higher blocks of consumption were priced above average costs (including profits) to
cover the subsidy for lower consumption blocks. Decision 21 noted that there would be further
improvements in the targeting of the subsidy, as non-poor households also benefitted from the
subsidy in their first 50 kWh consumption.
116. These further improvements were brought about by PM Decision 268 in February 2011.
Eligibility to the lifeline tariff was restricted to residential customers with average consumption
not greater than 50 kWh per month, measured on a rolling three-month basis. Households had to
register with their electricity retailer (PC or LDU, as applicable) to be eligible to receive the lifeline
tariff. In February 2011, another PM decision (Decision 269) approved a 17.4 percent average
tariff increase to recoup losses in the sector. The highest increase was in the first two tariff blocks,
raising concerns about its potential impact on the poor as the lifeline rate was increased to VND
993/kWh). To compensate for the reduced subsidy for the lifeline customers, an explicit subsidy
of VND 30,000/month was introduced for the registered poor and social welfare recipients, in the
form of a cash transfer under the responsibility of the Ministry of Labor, Invalids and Social Affairs
(MOLISA). Tariffs for all other blocks were set at cost (for first block of 1–100 kWh) or above
cost, to provide for the cross-subsidy for the lifeline tariff. The lifeline tariff remained at the 2011
level through 2013, while average retail tariff increased.
117. In April 2014, the tariff structure was revised again (Decision 28/2014), introducing a tariff
structure differentiated by end-use application, voltage, and time-of-day (normal, peak and off-peak
loads) for both wholesale and retail tariffs. Also the number of residential tariff blocks was reduced.
The residential tariff still follows an increasing block tariff structure but with six rather than seven
blocks, essentially eliminating the lifeline tariff. The residential price for all households for the
first block of 50 kWh is priced at 92 percent of the national average price and the price for the
second block (from 50 to 100 kWh) is set at 95 percent of the national average price. Other blocks
are priced above average, to encourage conservation and efficiency in household consumption.
Poor households based on the criteria specified by the PM, as well as those households eligible for
social welfare on the criteria specified by MOLISA and consuming less than 50 kWh per month,
are supported with a monthly cash transfer equivalent to the electricity bill for the use of 30 kWh
at the cost of the first block. The targeting therefore excludes social welfare recipients with a
consumption above 50 kWh and is targeted at the poor based on socioeconomic criteria set by the
PM. A recent report found that the design of support for the poor is considered best practice, while
there is some room to improve the coverage and reduce the leakage.42 Table 4 shows the evolution
of the tariff structure from 2009 to the present.
42 Mercados 2015, based on a desk study of recent research: “Best practices in subsidy provision are already been
used in Vietnam such as the increasing block tariff alternative and conditional cash transfer based on the MOLISA
list. Though coverage and leakage rate can be improved a bit, the efficiency of the subsidy is relatively good.”
43
Table 4. Evolution of Tariff Structure from 2009 to the Present (VND/kWh)
Source: ICR authors, based on data from EVN (2015) and GoV legal documents (PM Decisions 21/2009, 268/2011,
28/2014, and MOIT Decisions 4887/2014, 2256/2015).
118. These successive tariff reforms have substantially improved the targeting of the subsidy,
making sure that only poor households receive the subsidy and that all poor consumers—rural and
urban— have the same opportunity to benefit from the subsidy. Furthermore, the cost of the lower-
than-average price for blocks 1 and 2 is covered within the residential block tariff structure. Both
these factors suggest that it will be sustainable.
119. Support under the PSRDPO series for improved targeting of the subsidy to the poor. Prior Action 5 in DPO 1 supported restructuring the residential block tariff system to establish the
principle of the subsidy to the consumer as a percentage of production cost and extending the
subsidy mechanism and residential tariff structure to LDUs. The end-of-program indicator,
“Subsidies to the poor are targeted to low-income consumers,” was fully achieved.
Reducing Cross-Subsidies from Industrial and Commercial to Residential
120. Prior to the program, large cross-subsidies existed between tariff categories.43 In 2009, PM
Decision 21 called for residential electricity tariffs to be raised at a rate higher than the average
electricity sale price, and ‘production’ electricity tariff at a lower rate in order to progressively
eliminate the cross-subsidy from commercial and industrial toward residential use. Cross-subsidies
from industrial and commercial customers’ tariffs to residential customers’ tariffs were to be
phased out over five to six years. This has been gradually implemented with residential tariffs
increased proportionately more than commercial and industrial in each tariff adjustment, apart
from the last tariff increase when the residential tariffs increase was lower than the commercial
one.
121. Based on analysis by Macro Consulting, it is possible to obtain a rough estimate of the
cross-subsidy from commercial and industrial users to residential users in 2015.44 The share of the
cross-subsidy from one type of user to another is estimated by comparing the actual ratio of
residential tariff to commercial and to industrial tariffs in Vietnam, with the cost-reflective ratio.
43 Estimated cross-subsidies from industrial and commercial consumers were at US$370 million in 2007 [PSRDPO
1 Program Document]. 44 Calculation from Pardina (2015) presentation for the Distribution Efficiency Project P125996 (DEP). The exact
source of data and methodology used do not allow a precise estimate, but it is precise enough for the purposes of
evaluating whether the cross-subsidy was reduced by 50 percent as called for by the DPO indicator.
Regulation/year
% of
average
VND/k
Wh
% of
average
VND/k
Wh
% of
average
VND/k
Wh
% of
average
VND/k
Wh
% of
average
VND/k
Wh
lifeline (0-50kWh) 63.3% 600 80.00% 993
0-50 kWh 92% 1,388 92% 1,388 91% 1,484
51-100 kWh 95% 1,434 95% 1,433 95% 1,533
101-150 kWh 120% 1,135 105% 1304
151-200 kWh 158% 1,495 133% 1651
201-300 kWh 171% 1,620 144% 1788 138% 2,082 138% 2,082 138% 2,242
301-400 kWh 183% 1,740 154% 1912 154% 2,324 154% 2,324 154% 2,503
401 kWh + 189% 1,790 158% 1962 159% 2,399 159% 2,399 159% 2,587
110% 1,786
4887/2014 2256/2015
91% 865 100% 1242
21/2009 268/2011 28/2014
110% 110% 1,6601,660
44
As the actual cost-reflective ratio for Vietnam is not available, as an approximation, the study used
ratios in the United Kingdom: 1.09 for residential-to-commercial, and 1.62 for residential-to-
industrial. The size of the subsidy transfer is then calculated by multiplying the difference between
actual and cost-reflective ratios by the total revenue from each consumer category. Using this
methodology and converting at today’s exchange rate, yields subsidies from industrial and
commercial to residential users of approximately US$13 million and US$27 million.
122. The indicator targeted the level of cross-subsidy from industrial and commercial categories
to residential to be reduced at least 50 percent. According to baseline value for the indicator, the
size of cross-subsidy was US$370 million in 2007. The size of the cross-subsidy, while not very
precise, is estimated at US$40 million, representing a reduction of nearly 90 percent. Even with a
wide margin of error (for example, because United Kingdom ratios may not provide a good proxy
for Vietnam) it is highly probable that this indicator has been met.
123. The following considerations informed the rating:
Annual tariff adjustments are not yet happening regularly. However, the tariff
regulations now provide a relatively good basis upon which to implement cost-
reflective tariffs. Tariff reform was intended to facilitate effective competition,
transparency, and predictability. However there remains a lack of transparency in
terms of what is included in the costs that are incorporated in tariff calculations. There
remains a lack of predictability in the timing and process of the application of the tariff
adjustments. The gap between actual tariff level and the tariff level needed to achieve
cost recovery suggests that it may be several years before tariff reach a level to attract
new investors and this will impede the development of competition.
There has been a significant reduction in the cross-subsidies from industrial and
commercial consumers to residential consumers.
Targeting of subsidy to the poor and rural areas has improved significantly.
124. Overall, there has been important progress in tariff reform, especially in terms of setting
an enabling framework. However, work remains to be done to make the tariff adjustment process
more transparent and predictable.
Policy Area D: Improving Demand Side Energy Efficiency
Rating: Substantial
125. The electricity intensity of Vietnam’s economy has been growing fast since 2000,45 driven
by growth of the industrial sector as a share of Vietnam’s economy. A rapid increase in access,
below-cost tariffs, and cross-subsidization have contributed to fast growth in household demand
as well. The National Strategic Program on Energy Saving and Efficient Use approved by the PM
in 2006 included targets on energy savings up to 2015 and instructed MOIT to draft and submit to
the National Assembly the Energy Efficiency Law during the period 2008–2010.
45 Growth rate is over 6 percent in most years, dropping to 5.63 kWh/2005US$ in 2013.
45
126. Two factors motivated the GoV’s attention to demand-side energy efficiency: the need to
reduce or avoid energy shortages (which would be addressed through targeting an overall reduction
in the rate of growth of energy demand through efficiency) and the goal of limiting requirements
for new investment in capacity, implying the need to limit growth specifically in peak demand.
127. TA supported by the Bank evaluated past energy efficiency programs and identified key
areas needing attention to incentivize demand-side energy efficiency in the context of the overall
sector reform, specifically, improving price signals, improving regulation (in particular to
incentivize PCs to promote energy efficiency) and improving information available to consumers
about energy efficiency of equipment through standards and labeling. In determining the scope
and targets for Policy Area D to be supported under the PSRDPO program, it was recognized that
improving the price signals would depend on actions supported in Policy Area C on tariff reform.
Demand-side energy efficiency implementation would to a large extent track progress in tariff
reforms that is, reducing cross-subsidy, better targeting subsidy to the poor, and achieving a
regulated tariff level that reflected cost of supply.
128. It was therefore decided that Policy Area D would focus on the complimentary areas: the
enabling framework, information availability, and TOU tariffs. The final outcome for the policy
area focused on the legal framework, monitoring, and enforcement. Intermediate actions aimed to
ensure that up-to-date and high quality information would be available to support implementation
and to ensure that TOU tariffs were introduced. Milestones of progress included submission by
MOIT of a draft Energy Efficiency Law to the PM and completion by ERAV of a load research
study and submission of draft procedures for the periodic implementation of load research studies
by the PCs to MOIT.
129. Prior actions for PSRDPO 1 targeted important elements of the enabling framework, that
is, establishing energy efficiency standards for consumer goods accounting for large quantities of
electricity and introducing TOU tariffs for industrial zones and commercial, industrial, and
irrigation consumer categories. The MOIT Circular provided for the case of TOU customers
without TOU metering, establishing that the normal hourly tariff would apply. To achieve the price
signal needed to affect peak demand, therefore, the necessary metering would need to be put in
place.
130. During preparation of PSRDPO 2, preparation of the Vietnam Climate Change DPO series
was also launched. It was agreed with the government that this climate change DPO would cover
actions on the EE&C Law and its implementation regulations to promote EE&C in the industrial
sector, while the Power Sector Reform DPO actions would focus on measures to enhance
electricity pricing to promote efficient use and demand response by electricity consumers, as these
regulations fall under the responsibility of MOIT/ERAV. This resulted in a revision to the end-of-
program indicator to focus more directly on establishing the obligations and authority for demand
response programs: “Energy efficiency obligations established by law, and MOIT and ERAV have
the capacity to enforce and PCs the authority to implement demand response programs.”
131. The prior action for PSRDPO 2 in this policy area sharpened the focus on measures to
create the framework for demand response by putting in place the load research regulations for
PCs. Accordingly, in September 2011 MOIT Circular 33 established load research regulations for
PCs. The regulations mandate periodic load data collection activities by PCs, which is to be
46
transmitted to EVN. EVN is responsible for management of the National Load Research Database.
Load profiling and demand forecasts will be used to set the TOU tariffs for customer categories
where TOU tariffs are applicable. The EE&C Law was passed in the National Assembly in 2010,
and its implementation decree and sanctions decree required for enforcement, were approved in
2011.
132. One of the PSRDPO 2 Policy Area D milestones, completed in 2010, was the grouping of
distribution companies into five regional PCs. This facilitated the provision of support to PCs to
help them meet load research and demand response obligations. The Bank-supported DEP was
approved in September 2012. It included support to PCs for introduction of smart grid technologies
to provide real-time data from both the supply and the demand side, as well as TA, including on
the regulatory aspects, together facilitating generation of the information needed to contribute to
load research and to make effective use of the TOU provisions.
133. PM Decision 1670/QĐ-TTg (2012) set out the Smart Grid development roadmap,
stipulating that one of smart grid programs is the implementation of demand-side response (DSR)
for distribution power corporations and PCs.46 MOIT leads the Smart Grid Steering Committee.
ERAV is the Standing Smart Grid Steering committee tasked with developing and monitoring the
implementation of DSR programs. In 2014 and 2015, MOIT issued special decisions for approval
of implementation of pilot DSR programs in Ho Chi Minh City PC (HCMPC) (MOIT Decision
No 4425, May 2015: Approval on detailed design of pilot demand-response programs at HCMPC;
MOIT Decision No 4426, May 2015: Approval on incentive mechanism to implement pilot
demand response programs at HCMPC).
134. However ERAV does not have authority to enforce DSM and energy efficiency on PCs.
MOIT Decision 2447 of 2007 approved the National Program of DSM and Decision 2600/2014
the launch of two pilot demand-side response (DSR) programs. MOIT decision 2447 expired in
2015, while Decision 2600/2014 only allows for pilot DSR programs. Another limitation is that
the incentive mechanism for customers requires approval of the Ministry of Finance.
135. PM Decision No 28 April 2014 authorizes MOIT to implement the demand response
program and the electricity retail tariffs for commercial and industrial customers are TOU.
Electricity retail tariffs are uniform nationwide, meaning that the TOU is applied for all five PCs.
136. Key next steps envisioned as milestones for DPO3 were: establishing the load research
procedures, and establishing regulations for PCs to implement demand-response programs. In line
with the GoV’s ‘pilot before full launch’ approach to many aspects of the power sector reform, the
relevant prior action for PSRDPO 3 was “authorization by MOIT for a power distribution company
to carry out a pilot demand-response program.” The second prior action in this policy area, in line
with the indicative trigger in PSRDPO 2, was “at least one power company has begun to pilot a
demand-response program.”47
46 The Decision provided the legal basis for PCs to implement pilot DSR projects based on the application of
Automated Metering Infrastructure to record and monitor consumption of large customers. 47 Note that the Program Document for PSRDPO 3 defined the evidence that this prior action had been met as
“Issuance of MOIT Decision committing to implement specific pilot program in one Power Company”. So while
this prior action was achieved, the first pilot program did not actually begin until mid-2015.
47
137. Two demand-response programs directed at large industrial users in the Ho Chi Minh City
area are being piloted, through a Curtailable Load Program and a Voluntary Emergency Demand
Response Program. Both programs aim to reduce peak demand. Customers are incentivized to
participate through bill rebates (Mickle 2015). The launch of the pilots was delayed pending MOF
agreement with the proposed incentive mechanism and source of funding. The programs began in
mid-2015, with support provided under the DEP. Data on the impact of the pilots are not yet
available.
138. Considering the achievement of the end-of-program target indicator: “Energy efficiency
obligations established by law and MOIT and ERAV have the capacity to enforce and PCs the
authority to implement demand response programs”, substantial progress has been made. The
EE&C Law establishes rights and obligations for energy efficiency. Decision 1670 authorizes the
implementation of demand response pilots. ERAV is receiving capacity-building support under
the DEP program related to demand-response programs. However, ERAV does not have authority
to enforce DSM and energy efficiency on PCs, so the target for indicator 7 was not fully achieved.
As noted above, achieving energy efficiency outcomes depends critically not only on the enabling
framework (supported under this policy area) but also the progress in tariff reform.48 However,
with regard to readying the enabling environment for demand-response aspects of energy
efficiency, progress under this policy area has been good.
Achievement of the PDO
139. The PDO is complex and includes both outcomes and intermediate result. The rating of
Achievement of Program Development Objectives is “Substantial” and takes into account:
achievement of the PDO indicators (of the seven PDO indicators, two were achieved, two
were largely achieved, two were partially achieved, and one was not achieved);
progress under each policy area considering the outcomes sought:
o Policy Area A: Development of a Competitive Power Market: Substantial
o Policy Area B: Power Sector Restructuring: Modest
o Policy Area C: Electricity Tariff Reform: Modest
o Policy Area D: Improving Demand Side Energy Efficiency: Substantial
140. The rating also takes into account the contribution of the PSRDPO Program to achieving
the longer-term reform program. In the Program Document for PSRDPO 3, the program objectives
in the main text are introduced by “The objective of the Vietnam Power Sector Reform
Development Policy Operation is to support the initial phase of the long-term sector reform …”,
highlighting that the end-point of the PSRDPO series corresponds to an intermediate point in the
GoV’s overall power sector reform program and explicitly recognizing that the VCGM is an
intermediate step toward development of the WEM, rather than the end point in itself. An
important measure of whether the program achieved the development objectives is whether it was
successful in maintaining momentum needed for continued progress toward the subsequent stage.
48 The DEP includes an indicator of consumption reduction by consumers with new Automated Metering
Infrastructure meters. However, as the meters have yet to be installed, no data on this indicator is available (DEP
ISR#5, June 2015).
48
From this perspective, the program has been successful in supporting advances in all key policy
areas toward preparing for the transition to the WEM.
141. Importantly, the progress in reforming the power sector has been achieved while continuing
to provide a power system that operates reliably and safely, supplying adequate electricity for
socioeconomic development, without market operation mishaps or causing shocks to the economy
or households.
3.3 Justification of Overall Outcome Rating
Ratings: Moderately Satisfactory
Based on:
Relevance: Substantial
Achievement of objectives: Substantial
3.4 Overarching Themes, Other Outcomes, and Impacts
(a) Poverty Impacts, Gender Aspects, and Social Development
142. The impacts of successive tariff reforms on the poor are estimated by looking at the
evolution of the tariff structure by consumption blocks compared with the average consumption
of households organized by income bracket. During preparation of each operation, a Poverty and
Social Impact Analysis (PSIA) was conducted using updated data on consumption aggregates and
electricity expenditures from the latest Vietnam Household Living Standards Survey (VHLSS) to
calculate the share of household expenditures on electricity. In general, a threshold of 10 percent
of household expenditure on electricity is used to determine whether electricity is affordable.
143. The latest PSIA (2012) set out to estimate the impact on the poor of a full increase to the
top bracket planned under Decision 2165 of November 2013 for the 2013–2015 period, with and
without the social protection measures in place. The poor were found to be adequately protected
by the lifeline tariff and cash transfer. On average, the poor spent 2.4 percent of their total
expenditure on electricity, compared with a 2.1 percent national average. The PSIA assessed the
impact of one or two 5 percent increases in electricity tariffs in scenarios with and without the cash
transfer and allowing the lifeline tariff to increase 5 percent while holding fixed electricity
consumption at the 2012 VHLSS levels. The share of electricity spending in total expenditure
slightly increases from the VHLSS 2012 baseline. Additional simulations assuming even higher
price increases in 2014 raising the tariff to 26 percent above the July 2013 level (so higher than set
for 2015 by Decision 2165) concluded that electricity remained affordable for all income groups.
Other studies reviewed in the Mercados report find that even an increase of 100 percent in average
retail tariffs would not raise electricity costs high enough for the share of water and electricity to
be more than 5 percent in total expenditure of the two lower quintiles. The PSIA analysis also
shows that the difference in terms of the share of electricity expenditure is small between male and
female-headed households.
144. Note on migrants and renters. Each PSIA included a section on migrants and temporary
renters, as groups that are particularly vulnerable to high electricity tariffs. These groups do not
pay the government regulated price, but instead negotiate electricity prices with their
49
owner/landlord. As a result, these groups pay a much higher price than average, and their tariffs
rise along with the official tariffs. Interviews conducted by the Vietnam Academy of Sciences
showed that these residents could pay charges up to VND 3,000–4,500/kWh. As their consumption
was found to be limited, this amounts to approximately 3–4 percent of their total revenue, posing
a significant threat in periods of unemployment.
(b) Institutional Change/Strengthening
145. ERAV is a very substantial technical advisor to MOIT, though not yet taking on the role
of an independent regulator. Going forward, increasing the independence of ERAV will be
important as part of the overall increase in transparency that is needed in the sector. This will also
be important if ERAV is to become the independent power sector regulator in the future. A longer-
term issue to be considered is the need for increased technical capacity at MOIT, in preparation
for the transition of ERAV from technical advisor to independent regulator.
146. NLDC capacity has developed rapidly. Further capacity building, particularly on dealing
with hydro dispatch and dispute and settlements issues would benefit NLDC. Substantial
institutional change is still needed to complete the financial, decision making, and legal separation
of competitive elements of the sector (in particular generation) from entities providing services
(transmission, system and market operation).
147. Power plant operators are developing some capacity in participating in the market. For the
WEM to move forward there will need to be similar capacity-building efforts for the new WEM
players (for example, PCs).
(c) Other Unintended Outcomes and Impacts (positive or negative, if any)
None.
4. Assessment of Risk to Development Outcome
Rating: Significant
148. Reform of the power sector is progressing, although not as fast as envisioned in the GOV
Roadmap or at the start of this PSRDPO Program. There have been delays, for example in the
independence of the GENCOs and SMO, and in achieving tariffs that reflect full cost recovery.
The GOV is still committed to moving forward to the next stage of the reform—the Wholesale
Electricity Market – as evidenced by the active engagement in the next PSRDPO series currently
under preparation.
149. Key steps before the WEM can be expected to deliver the full benefits (that is, increased
efficiency and attracting new sources of investment) of a competitive market include the following:
Creating generator entities that are independent of EVN and each other to address
concerns about market dominance. Substantial analytic work is ongoing in the
preparation for moving to independent GENCOs but this will likely take several years
to achieve.
50
Establishing an independent SMO with no cross-ownership/benefit with other market
participants and addressing technical issues faced in operating the generation spot
market. This is essential for a properly functioning market. There is no decision yet
as to the form and timing of an independent SMO.
Raising tariffs to full cost-recovery levels. While recognizing the importance attached
by GoV to ensuring that raising tariffs to cost recovery levels does not negatively
affect macroeconomic stability, nevertheless, this is an essential step in launching a
credible market and attracting private investment.
Reducing or ideally eliminating political control over key aspects of the power sector,
for example, allowing an independent regulator to set tariffs according to the agreed
processes.
150. These steps will require not only substantial technical work, but also willingness of the
GoV and key stakeholders to yield some control of the sector to independent entities. Since the
start of the reform process, notwithstanding a huge amount of technical work and decision making
on some sensitive issues, the GoV still retains the authority to influence all aspects of the power
sector directly or indirectly. Achieving the outcomes and objective of the PSRPDO program over
the longer term—especially with regard to attracting investment— and achieving the full benefits
of power sector reform, will require the GoV’s role to change substantially. The GoV has not yet
taken any steps that materially change its role, so there is no track record to demonstrate that the
GoV will follow through on the necessary change in role, implying some risk in this regard.
151. Assuming that the key steps and decisions are taken as needed, it will likely still take some
years before the WEM delivers on one of the core outcomes sought for the overall reform effort:
attracting new sources of investment, particularly international private sector. This will require
time because investors will want to see a track record of a well-functioning market. There is a risk
that over time, the GoV commitment to the reform wanes as expected benefits take longer than
expected to materialize. There is also a risk that contracting arrangements, outside the WEM
framework, will need to be put in place to achieve the level of private investment required and this
could require substantial GoV support (for example, through guarantees).
152. Risk of macroeconomic fluctuations. If the currency devalues, the progress made on
power sector financial viability could be eroded, which would undermine the progress in sector
reform. The GoV is clearly cautious with regard to significant tariff increases and there remains
concern within the GoV that sharp tariff increases could affect inflation. If high tariff increases
become necessary, there is a risk that achieving cost-reflective tariffs will be further delayed. This
would also delay transition to a successful WEM and would likely affect the interest from private
sector investors.
51
5. Assessment of Bank and Borrower Performance
5.1 Bank Performance
(a) Bank Performance in Ensuring Quality at Entry
Rating: Moderately Satisfactory
153. The program was built on a strong base of analytic work—bringing worldwide experience
but also customizing to Vietnam’s context—and a substantial, long-term dialog in the power
sector. The Bank also closely coordinated and exchanged views with other development partners.
This facilitated a set of prior actions and that were meaningful and had GoV ownership. The design
showed the willingness of the Bank to be flexible in tailoring the approach to the context and GoV
priorities: it was fully in line with the GoV’s specific requirement of a gradual approach to avoid
shocks. There was also some compromise on the Bank side in the design of the program. During
preparation of the PSRDPO program, TA provided to ERAV proposed a structure establishing an
independent SO while initially maintaining generation within EVN. However, the GoV decided to
initially retain the SO under EVN control and instead create three generation companies
(GENCOs) which would be made independent of EVN and each other (that is, separate ownership,
though still under public ownership) to promote competition. The approach chosen by GoV, while
customized to the situation in Vietnam at the time, departed from the more ‘text book’ type of
approach proposed in the study. Transparency, a goal of the reform in any case, was therefore
particularly important to build confidence and make adjustments as needed in a novel approach.
This probably increased the risk of achieving a fully successful outcome. However, it facilitated a
constructive engagement with strong GoV ownership, which provided renewed momentum for
power sector reform.
154. Substantial changes in the restructuring policy area were agreed during the preparation of
PSRDPO 2. While some consequences of this change (for example, reduced competition
potentially leading to higher power prices) were addressed preemptively in the market design
(bidding and price caps), another important consequence—reduced transparency in governance
and financial interactions among the EVN-controlled entities—was not explicitly addressed in
PSRDPO 2 or PSRDPO 3. Missing the opportunity to build in alternative approaches to increase
transparency (an important element in proper market functioning and in developing a track record
to attract future investment) to compensate for delays in independence of the GENCOs and SO,
reduced the effectiveness of subsequent operations in supporting effective reform. Due to the
various adjustments during the course of the PSRDPO program, the attractiveness of the power
sector for private investment at the end of the series was less than it would have been, had the GoV
been able to adhere to the original timeline. Given the significant private sector financing expected
for new generation especially in the next five years, it may have been appropriate to introduce a
focus on ‘back-up’ approaches to attracting private investment, should the market approach take
longer than hoped to catalyze private interest.
(b) Quality of Supervision
Rating: Moderately Satisfactory
52
155. The Bank’s valuable and effective coordination role among development partners has
strengthened over the course of the PSRDPO series, helping to provide consistent development
partner input to the reform process. Throughout the course of the PSRDPO program, the Bank
maintained an active, constructive dialog with a range of power sector stakeholders from the
technical level through to high-level political counterparts. The Bank did an excellent job in
providing complimentary TA through grants and embedded in-parallel lending operations and in
mobilizing Bank technical expertise to review and provide input across a range of detailed
technical reports and assessments.
156. There was less focus on working with the client to monitor and assess progress toward the
specific key indicators, and this contributed to some important aspects of the PSRDPO receiving
insufficient attention. For example, one of the end-of-program indicators that was not achieved
was “SMO technical market audit by independent consultant firm to be completed and the report
made available for public access”. An independent market audit showing application of market
rules and proper market functioning would have been a powerful, positive indicator for potential
investors. Shortcomings identified through such an audit would have provided valuable guidance
on areas requiring more attention. Failure to undertake this audit represents a missed opportunity
to build confidence in the sector reform process. Greater attention during supervision could have
helped ensure that this audit was undertaken. Also, end-of-program Indicator 1 appears to have
received insufficient attention as data to fully assess the achievement could not be obtained.
Implementation status reports (ISRs) were sometimes late and could have been used more
effectively as monitoring and reporting tools, including in more careful assessment and
explanation of the ratings and achievements reported in the ISRs.
(c) Justification of Rating for Overall Bank Performance
Rating: Moderately Satisfactory
157. Bank performance in ensuring quality at entry: Moderately Satisfactory; Bank performance
in quality of supervision: moderately satisfactory; overall: Moderately Satisfactory.
158. Overall, the Bank has consistently maintained a strong engagement supported by
substantial technical analysis and active dialog. In the program design, the Bank has
accommodated GoV preferences, some of which have lowered the overall ambition and
achievement of the reform effort to date, such as delaying the independence of the GENCOs and
the SMO and focusing on ‘transitioning to’ rather than achieving cost-reflective tariffs. On the
other hand, the engagement has supported meaningful progress in power sector reform and helped
maintain GoV momentum on the reform. Effects of one important change, (that is, the decision to
postpone GENCO and SMO independence) affected multiple areas of the reform (for example,
effective competition, level of transparency, and perceived conflict of interest) and were not fully
addressed or compensated for in other parts of the program. Greater attention to the monitoring
tools could have helped to highlight some of these areas.
5.2 Borrower Performance
(a) Government Performance
Rating: Moderately Satisfactory.
53
159. The GoV has been effective in coordinating and building consensus among power sector
reform stakeholders. The GoV has continued to make advances on all fronts of the broad-based
power sector reform agenda although some decisions have resulted in delays compared to the plan
at the start of the program. A number of important decisions issued by the PM and MOIT
demonstrate GoV ownership of the reform program and concrete steps to put in place the enabling
framework and environment for the reform to proceed.
160. Areas where more determined GoV action could have led to greater progress with the
reforms was seeking greater transparency with regard to governance among the EVN-owned
entities, implementation of tariff decisions particularly in recent years, and in operation of the
market. Providing ERAV with greater authority to require reporting and data submission to support
the M&E of the progress under the PSRDPO program could have allowed ERAV to make more
effective use of the M&E framework.
(b) Implementing Agency or Agencies Performance
Rating: Satisfactory
161. ERAV has been a solid implementing agency for the program. ERAV has been responsible
for drafting numerous circulars, regulations, briefings, etc. through a combination of in-house
expertise and selecting specialist consultants. They have also successfully managed the selection
and supervision of a number of technical consultant reports and assessments covering all aspects
of the reform program. They have a key role in coordinating the consultation and consensus
building needed for these documents, which they have fulfilled effectively. ERAV also has a
monitoring and reporting role for the reform program. Their ability to perform this function is
dependent on reporting and submissions from various stakeholders, for example, NLDC and EVN.
As evidenced through data gathering during the ICR process, ERAV has limited ability to enforce
requests for information from the other power sector stakeholders and this weakens their
effectiveness in overall monitoring.
(c) Justification of Rating for Overall Borrower Performance
Rating: Moderately Satisfactory
162. This is based on: Borrower - Moderately Satisfactory; Implementing Agency - Satisfactory;
and Resulting Aggregate Rating - Moderately Satisfactory.
163. Progress has been slower than originally expected, but still substantial, especially in the
area of tariff reform and the technical aspects of setting up a generation spot market. In other areas,
for example, increasing transparency and reducing conflict of interest in the sector, there has been
some progress, though substantial further progress is needed to make the sector attractive for non-
EVN investors. Overall, the GoV and ERAV continue to demonstrate commitment both to the
overall, longer-term power sector reform, and to implement the steps agreed in the program.
6. Lessons Learned
164. Comprehensive power sector reform such as is taking place in Vietnam—that is, moving
from a vertically-integrated, public-sector dominated sector structure to a market-based approach
54
with private participation—requires time for design, consultation, and implementation, as well as
to take advantage of ‘windows of opportunity’ for changes which may have significant effects on
households or the overall economy. It requires parallel effort on multiple fronts (for example, tariff,
sector structure, and market implementation) and it involves a combination of both political and
technical change. Adjustments during the process will be needed and should be expected. In this
context, two lessons from the PSRDPO program may be useful for subsequent engagement and
for other countries.
From both the government and Bank perspectives, it is important to keep an overview
of the overall reform progress to make sure that significant adjustments or delays in
one area are adequately reflected in corresponding adjustments as needed in other
areas and in the overall expectations for short- and medium-term outcomes and
objectives.
It is important to maintain a balance between technical and political progress,
especially as adjustments to the reform process and timeline are made. There is a good
rationale for proceeding with design and implementation of technical aspects of
reform in advance of steps that may be particularly politically sensitive. However, a
balanced approach is needed. If technical aspects advance too far ahead of the
corresponding political steps, the reform may begin to appear ‘hollow’. For example,
a situation in which the technical aspects of a market (for example, market rules,
information technology systems, and actual trading) are in place but the corresponding
political steps (for example, reducing political control over tariff adjustment levels
and timing) are lagging, there is a risk that the reform process will not deliver on
expectations and/or will give the impression to prospective market participants that
the government is not serious about fundamental reform of the government role.
165. Realism in the level of ambition of the timing of sector reform at the time of
preparation is essential. In this PSRDPO program, the results and ambition were scaled back
from the first operation to the second, and from the second to the third, but despite these
adjustments, some still proved to be too optimistic. A DPO series, by design, signals future
tranches of budget support which a government may factor into medium term budget planning.
The pressure on the Bank to provide needed budget support in some cases may outweigh the lack
of progress in sector reform. If the Bank team’s assessment at the start of a DPO series is that the
Government’s planned pace of reform too optimistic, some adjustment in the operation should be
made to signal to the government that the Bank does not share their assessment. Ideally the Bank
and government would reach agreement on a timeline that both parties consider to be realistic. If
the government’s and Bank’s assessments of a realistic pace of reform cannot be fully reconciled,
one option is to delay launching the operation until steps have been taken by the Government to
make the proposed timeline more realistic. Where the timing is important in order to take
advantage of a window of opportunity, an alternative may be to reduce the amount of the budget
support provided.
166. Transparency is critical for successful reform as a means to maintain effective
coordination, as a requirement for proper market functioning and as a necessary element in
building confidence among current and potential future market participants. In terms of
coordination, a high level of transparency is important when there are substantial changes to the
55
approach or timing of key aspects of the reform process, to ensure that coordinated adjustments
are made as needed in related areas. Transparency is also critical for proper functioning of a
market, as participants need accurate and timely information on supply, demand and prices in order
for market signals to yield the desired efficiencies. Potential investors will look for a track record
of proper market functioning in evaluating risk and making investment decisions. Transparency in
decision-making (e.g. around tariffs) and market operation is an essential component of developing
a positive track record to attract investment. Given the important role of transparency in successful
reform, consideration should be given to emphasizing increased transparency through indicators,
milestones and/or prior actions in DPOs supporting power sector reform.
167. Resources needed for Bank team preparation and supervision should not be
underestimated. The complex, long-term adjustments covering core aspects of the energy sector,
with potential impacts on poverty and the overall economy, require a very substantial Bank effort.
A large number specialist consultant teams generate documents (for example, assessments, design
documents, regulations, etc.), many of which are technically complex and need to be tailored to
the particular country context and all of which should contribute to a coherent overall reform
program. From the Bank side this requires both broad and deep engagement in review and in
helping to ensure that design of Bank support is well-aligned with recommendations and new
information.
168. Adequate TA is essential. Many of the discussions during preparation of the ICR
highlighted the value of TA support during the first PSRDPO series and the critical importance of
TA in addressing immediate issues and in preparing for the next stage of reform. While the Bank
can play a role in helping to mobilize grant funding for some of these requirements, it is also
important that the GoV allocate the necessary resources to enable ERAV and others to obtain the
specialist TA needed to develop and implement the reform program. It is clear that substantial,
ongoing technical support will be needed to support the next stage of the reform. Some examples
of the support needed include the following:
ERAV has indicated the need for TA on many aspects of the WEM.
NLDC indicated a need for TA to (a) improve the approach to water valuing and
hydropower dispatch and (b) to determine how best to incorporate ancillary services
in the market.
169. More generally, a comprehensive engagement made up of different types of lending
engagements, as well as analytical work and technical assistance, is important in supporting a
strong policy reform dialogue. A broader engagement can help address specific obstacles to
reform, such as the need to strengthen the transmission infrastructure. It also allows for “deep
dive” engagement, in some cases with a subset of the larger stakeholder group, so that decision-
makers are well-informed about the details of specific issues and the implications of various
options.
170. A simple PDO and consistent, clearly stated indicators and outcomes are important to
set clear expectations and to ensure that the monitoring framework is as effective as possible. In
cases similar to this PSRDPO program, where the target end-point of the PSRDPO series
corresponds to an intermediate point in the overall power sector reform program, it would be
56
helpful to clarify the objective of the DPO series as distinct from the objective of the overall power
sector reform which will take longer to achieve.
7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners
(a) Borrower/Implementing agencies
171. The Borrower’s ICR is attached as Annex 3. Consistent with the ICR, the Borrower’s ICR
highlights the need for investment to meet growth in power sector demand as a driver of sector
reform, noting “the diversification of financing sources, including private sector investment, is
very important to ensure the investment with reasonable prices, and the diversification of private
power generators is needed to ensure the competitive prices”. The Borrower ICR summarizes the
overall outcome of the PSRDPO program as a step in a longer progress of reform, noting that
“After over four years of implementing the program DPL, the policy conditions, which have been
performed by MOIT as committed with WB, contribute to construct a unified policy framework
in order to form a basis for developing the sustainable power sector”. The critical role of technical
assistance for the implementing agency, ERAV, is highlighted, as well as the need for continuing
technical assistance going forward: “ERAV (with the role of managing and evaluating unit) has
been highly reliant on Technical Assistance to bolster its capacity for the implementation of this
program. We hope such sources of assistance will be available at the time of implementing the
next DPL programs”.
(b) Cofinanciers 167. There was no co-financing.
(c) Other partners and stakeholders
(e.g. NGOs/private sector/civil society)
168. Beneficiary surveys and stakeholder workshops were not carried out for this core ICR.
57
Annex 1. Bank Lending and Implementation Support/Supervision Processes
(a) Task Team Members
P115874 - Vietnam Power Sector Reform Development Policy Operation
Names Title Unit Responsibility/
Specialty
Lending
Richard Spencer Lead Energy Specialist GEEDR Task Team Leader
Beatriz Arizu de Jablonski Senior Energy Specialist
GEEDR
Co-task
Team Leader
Robert J. Gilfoyle Senior Financial Management
Specialist GGODR Financial Specialist
Douglas J. Graham Senior Environmental Specialist GENDR Environmental
Specialist
Valerie J. Kozel Senior Economist GPVDR Poverty Economist
Keiko Kubota Lead Economist GMFDR Economist
Hoi-Chan Nguyen Senior Counsel LEGES Legal Counsel
Anh Nguyet Pham Senior Energy Specialist GEEDR Team Member
Cung Van Pham Senior Financial Management
Specialist GGODR Financial Specialist
Ky Hong Tran Senior Energy Specialist GEEDR Team Member
Mai Thi Phuong Tran Senior Financial Management
Specialist GGODR Team Member
Supervision
Beatriz Arizu de Jablonski Senior Energy Specialist GEEDR Task Team Leader
Sameena Dost Senior Counsel LEGES Legal Counsel
Lien Thi Bich Nguyen Program Assistant GEEDR Program Assistant
Anh Nguyet Pham Senior Energy Specialist GEEDR
Team Member, Co-
task
Team Leader
Mai Thi Phuong Tran Senior Financial Management
Specialist GGODR Financial Specialist
P124174 - Vietnam Power Sector Reform DPO2
Names Title Unit Responsibility/
Specialty
Lending
Beatriz Arizu de Jablonski Senior Energy Specialist GEEDR Task Team Leader
Anh Nguyet Pham Senior Energy Specialist GEEDR Co-task
Team Leader
Sameena Dost Senior Counsel LEGES Legal Counsel
Defne Gencer Energy Specialist GEEDR Team Member
Hung Tien Van Senior Energy Specialist GEEDR Team Member
Valerie J. Kozel Senior Economist GPVDR Poverty Economist
Keiko Kubota Senior Economist GMFDR Economist
Lien Thi Bich Nguyen Program Assistant GEEDR Program Assistant
58
Teresita G. Velilla Temporary GGODR Team Member
Robert J. Gilfoyle Senior Counsel LEGES Legal Counsel
Supervision
Same as above
P144675 - Vietnam Power Sector Reform DPO3
Names Title Unit Responsibility/
Specialty
Lending
Pedro Antmann Lead Energy Specialist GEEDR Task Team Leader
Franz Gerner Lead Energy Specialist GEEDR Co-task
Team Leader
Thi Ba Chu Consultant GEEDR Team Member
Valerie J. Kozel Senior Economist GPVDR Poverty Economist
Daisuke Miura Energy Specialist GEEDR Team Member
Lien Thi Bich Nguyen Program Assistant EACVF Program Assistant
Habib Nasser Rab Senior Economist EASPV Economist
Cung Van Pham Senior Financial Management
Specialist GGODR Financial Specialist
Son Duy Nguyen Senior Operations Officer EACVF Team Member
Hung Tien Van Senior Energy Specialist GEEDR Team Member
Supervision
Same as above
(b) Staff Time and Cost
P115874 (Vietnam Power Sector Reform Development Policy Operation)
Stage of Project Cycle
Staff Time and Cost (Bank Budget Only)
No. of Staff Weeks US$, thousands (Including
Travel and Consultant Costs)
Lending
FY09 8.45 46.29
FY10 24.64 168.87
Total: 33.09 215.16
Supervision/ICR
Total: 0.00 0.00
Total for P115874 33.09 215.16
P124174 (Vietnam Power Sector Reform DPO2)
Stage of Project Cycle
Staff Time and Cost (Bank Budget Only)
No. of Staff Weeks US$, thousands (Including
Travel and Consultant Costs)
Lending
FY11 8.65 52.93
FY12 22.72 156.38
Total: 31.37 209.31
59
Supervision/ICR
Total: 0.00 0.00
Total for P124174 31.37 209.31
P144675 (Vietnam Power Sector Reform DPO3)
Stage of Project Cycle
Staff Time and Cost (Bank Budget Only)
No. of Staff Weeks US$, thousands (Including
Travel and Consultant Costs)
Lending
FY13 12.80 118.97
FY14 25.15 163.61
FY15 3.41 24.90
Total: 41.36 307.48
Supervision/ICR
FY15 22.08 142.19
FY16 9.27 45.64
Total: 31.35 187.83
Total for P144675 72.71 495.31
60
Annex 2. Intermediate Outcome Indicators
Vietnam Power Sector Reform Development Policy Operation - P115874
Indicator Baseline Value
Original Target
Values (from
approval
documents)
Formally
Revised Target
Values
Actual Value
Achieved at
Completion or Target
Years
Indicator 1:
(a) ERAV completes draft VCGM Rules and submits to MOIT for consultation and
approval
(b) MOIT issues a circular promulgating the Grid Code
Value
(Quantitative or
Qualitative)
(a) No VCGM Rules
draft submitted
(b) No Grid Code
Circular issued
– –
(a) ERAV document
submitted to MOIT
minister
(b) Grid Code Circular
issued by MOIT on
April 15, 2010,
(Circular 12/2010/TT-
BCT)
Date achieved 04/06/2010 – – 06/30/2011
Comments
(including % achievement) Achieved
Indicator 2:
(a) EVN submits recommendations on independent GENCOs to PM
(b) MOIT issues circular on methodology and procedures to calculate, review, and
approve dispatch, system operation, and market operation costs (SMO fee), to ensure
adequate resources and expert-skilled staff
Value
(Quantitative or
Qualitative)
(a) No
recommendation on
independent GENCOs
submitted to PM
(b) No circular on
SMO fees issued
– –
(a) Recommendation
submitted on December
3, 2010
(b) Circular on SMO
fees issued by MOIT on
April 15, 2010
(Circular 13/2010/TT-
BCT)
Date achieved 04/06/2010 – – 12/03/2010
Comments
(including % achievement) Achieved
Indicator 3:
(a) PM Decision promulgates regulations on methodology to calculate and procedures
for appraisal of electricity market prices, following market mechanism stipulated in
2009 PM Decision 21/2009/QD-TTg
(b) ERAV submits to MOIT minister the proposed regulations for transmission revenue
requirement and transmission charges, for NPTC to finance transmission investment
program
Value
(Quantitative or
Qualitative)
(a) No regulations on
methodology for
market-based prices
(b) No proposal for
transmission revenue
requirement regulation
– –
(a) Decision
24/2011/QD-TTg dated
15 April 2011
(b) Circular
14/2010/TT-BCT dated
April 15, 2010
Date achieved 04/06/2010 – – 04/15/2011
Comments
(including % achievement) Achieved
61
Indicator 4:
(a) MOIT submits draft of the Energy Efficiency Law to PM.
(b) ERAV completes load research study and drafts procedures for PCs' periodic
implementation
Value
(Quantitative or
Qualitative)
(a) Draft Energy
Efficiency Law not
submitted
(b) Load research
study incomplete
– –
(a) Draft Energy
Efficiency Law
submitted by MOIT to
PM
(b) Load research study
complete and
procedures drafted for
PCs to continue
Date achieved 04/06/2010 – – 06/30/2011
Comments
(including % achievement) Achieved
Vietnam Power Sector Reform DPO2 - P124174
Indicator Baseline Value
Original Target
Values (from
approval documents)
Formally
Revised Target
Values
Actual Value
Achieved at
Completion or Target
Years
Indicator 1:
(a) ERAV completes draft VCGM Rules and submits to MOIT for consultation and
approval
(b) MOIT issues a circular promulgating the Grid Code
Value
(Quantitative or
Qualitative)
(a) No VCGM Rules
draft submitted
(b) No Grid Code
Circular issued
– –
(a) ERAV document
submitted to MOIT
minister
(b) Grid Code Circular
issued by MOIT on
April 15, 2010,
(Circular 12/2010/TT-
BCT)
Date achieved 04/06/2010 – – 06/30/2011
Comments
(including % achievement) Achieved
Indicator 2: (a) MOIT submits recommendations to PM on generation structure for VCGM
(b) Establishing methodology and procedures to calculate and approve SMO fee
Value
(Quantitative or
Qualitative)
(a) No
recommendations
(b) No methodology
or procedures for
SMO fee
– –
(a) Recommendation
submitted on December
3, 2010
(b) Circular on SMO
fees issued by MOIT on
April 15, 2010
(Circular 13/2010/TT-
BCT)
Date achieved 04/06/2010 – – 12/03/2010
Comments
(including % achievement)
Note: The ISR for DPO2 reports different first milestones: “(a) EVN submits
recommendations on independent GENCOs to PM”.
Achieved
62
Indicator 3:
(a) MOIT submits to PM the draft regulation for annual market-based tariff mechanism
and tariff adjustments during the year to reflect differences between forecasted and
actual power generation costs
(b) ERAV submits to MOIT the draft regulations to set transmission revenue
requirement and transmission charges for NPTC
Value
(Quantitative or
Qualitative)
(a) No regulations on
methodology for
market-based prices
(b) No proposal for
transmission revenue
requirement
regulation
– –
(a) Draft submitted in
January 2011 for
Decision 24/2011/QD-
TTg dated April 15,
2011
(b) Draft submitted in
March 2010 for
Circular 14/2010/TT-
BCT dated April 15,
2010
Date achieved 04/06/2010 – – 04/15/2011
Comments
(including % achievement) Achieved
Indicator 4:
(a) PM submits the EE&C Law to the National Assembly
(b) ERAV submits load research regulations to MOIT for periodic implementation of
PCs
(c) PCs grouped into five regional PCs to absorb less efficient rural distribution units
and reduce losses through rehabilitation of low-voltage networks
Value
(Quantitative or
Qualitative)
(a) PM has not
submitted the EE&C
Law in the National
Assembly
(b) ERAV has not
submitted the
regulations to MOIT
(c) PCs not grouped
yet
– –
(a) Done
(b) Done
(c) Done
Date achieved 04/06/2010 – – 06/30/2011
Comments
(including % achievement) Achieved
Vietnam Power Sector Reform DPO3 - P144675
Indicator Baseline Value
Original Target
Values (from
approval
documents)
Formally
Revised
Target
Values
Actual Value Achieved at
Completion or Target
Years
Indicator 1:
(a) SMO issues settlement report on results of first month of VCGM’s full commercial
operation
(b) ERAV prepares market monitoring report.
Value
(Quantitative or
Qualitative)
The settlement and
market monitoring
reports were submitted to
the Bank.
– –
(a) & (b) The settlement
and market monitoring
reports were submitted to
the Bank.
Date achieved Not available – – Not available
Comments
(including %
achievement)
Achieved
63
Indicator 2: Completion of transfer from EVN to GENCOs of contracting arrangements regarding
both the existing power plants (PPAs) and projects under construction
Value
(Quantitative or
Qualitative)
GENCOs generation
assets not transferred – –
GENCOs are fully running
commercial operations, and
are registered as
participants in the VCGM
in accordance with MOIT
Decisions 3203, 3204,
3205/2012/QD-BCT. The
transfer of assets and
liabilities from EVN to
GENCOs is completed.
Date achieved Not available – – 06/01/2012
Comments
(including %
achievement)
Achieved
Indicator 3:
(a) Submission of an unaudited financial statement of each GENCO for the first nine
months of 2013
(b) Commitment by EVN to submit 2013 audited annual financial statement of each
GENCO by June 2014
Value
(Quantitative or
Qualitative)
(a) Financial statements
not submitted
(b) No EVN commitment
– –
(a) EVN submitted to the
Bank the unaudited
financial statements for
each GENCO for the first
three quarters (January to
September) of 2013. The
Bank experts reviewed the
reports and found them
acceptable.
(b) On January 22, 2014,
EVN submitted a letter to
the Bank committing to
provide the audited
financial statements of
each GENCO for 2013 by
June 30, 2014.
Date achieved Not available – – 01/22/2014
Comments
(including %
achievement)
Achieved
64
Indicator 4: Government decision defining the timing for the separation of GENCOs and SMO into
independent companies with no cross-ownership with other market participants
Value
(Quantitative or
Qualitative)
No clear timing for
separation of the
GENCOs and SMO
– –
PM Decision 63 issued on
November 8, 2013 states
that as preconditions for
the transition from VCGM
to pilot WCM, from 2015:
(a) GENCOs have to
separate into independent
generation entities, with no
cross-ownership with SB,
SMO, or transmission
company and (b) the SMO
will become an
independent entity with no
cross-ownership with
market participants.
Date achieved Not available – – 11/08/2013
Comments
(including %
achievement)
Achieved
Indicator 5: Circular issued by MOIT on methodologies for annual setting of average electricity retail
tariff level and procedures for their effective application (so called ‘Circular 2’).
Value
(Quantitative or
Qualitative)
No methodology for
annual retail tariff setting – –
MOIT Circular
12/2014/TT-BCT on
‘guiding the calculation of
average electricity retail
tariff’ defines the
methodologies and
procedures for the annual
setting of the average retail
tariff level (allowed
revenues of the PCs for
electricity supply to end
users).
Date achieved Not available – – 03/31/2014
Comments
(including %
achievement)
Achieved
65
Indicator 6: Issuance of MOIT Decision establishing regulations for PCs to implement demand-
response programs
Value
(Quantitative or
Qualitative)
No regulatory framework
for demand-response
programs
– –
MOIT Decision 2600/QD-
BCT ‘on approval of the
pilot implementation plan
for demand-response
programs’ defines the types
of programs to be
implemented, and clearly
establishes roles and
responsibilities of the
involved sector agents
(ERAV, EVN, and PCs)
Date achieved Not available – – 03/27/2014
Comments
(including %
achievement)
Achieved
Indicator 7: Issuance of MOIT Decision setting the timeline for each PC for full development of its
pilot DSR program
Value
(Quantitative or
Qualitative)
No timeline for
implementation by each
PC of the pilot program
– –
MOIT Decision 2600/QD-
BCT of March 27, 2014
‘on approval of the pilot
implementation plan for
demand-response
programs’ approves the
plan for implementation by
PCs of pilot demand-
response programs in
2014–2015.
Date achieved Not available – – 03/27/2014
Comments
(including %
achievement)
Achieved
66
Annex 3. Summary of Borrower's ICR and/or Comments on Draft ICR
MINISTRY OF INDUSTRY AND TRADE
ELECTRICITY REGULATORY AUTHORITY OF VIETNAM
REPORT
Implementation results of program “Development Policy Lending 1, 2, 3”
To: World Bank
1. According to World Bank (WB) request of reporting results of implementation results of
the Program Development Policy Lending phase 1, 2, 3 (DPL1-2-3), Electricity Regulatory
Authority of Vietnam (ERAV) has summarized the implementation results with specific contents
as follow:
Overview of the program DPL1-2-3
Objectives of the program
2. Development of sustainable energy is essential to contribute economic growth and poverty
reduction. In Vietnam, the electricity demand reached an average growth rate of 14,4% per year
in the period of 2001-2010, and fell to 10% per year in the period of 2011-2013 due to the global
economic crisis. Meanwhile, the insufficiency of power system installed capacity led to the load
shedding in the period 2008-2010, especially at the peak time of dry season. By calculating, it has
been shown that the power sources reservation rate should reach over 15% to fulfill system
demand. Therefore, we need solutions to ensure the investment progress of new power sources
project in the period of 2011 - 2015, especially we need to ensure the sufficiency of fund for
implementing the project. The investment need for power sector in the period 2011 - 2015 is
estimated at about US$5 billion/year, in which 60% investment use for power sources. Official
development assistance (ODA) has been accounted for a large proportion of the total investment
capital mobilized for power sector, with about 1,5-2,0 billion US dollars per year, the remaining
investment comes from domestic and foreign funds. Besides, the diversification of financing
sources, including private sector investment, is very important to ensure the investment with
reasonable prices, and the diversification of private power generators is needed to ensure the
competitive prices.
3. From 2010, WB has implemented the power sector development policy lending (DPL
program) with aim of providing loans to support Vietnam Government to implement power
competitive market, restructure the power sector and construct a new tariffs structure, in order to
encourage the effective competition, timely invest in the power sector, especially in the generation
stage, and enhance the efficiency of electricity use to achieve the goal of providing adequate
electricity for economy with lowest cost, while improving the living standards of people by
establishing supporting mechanisms in electricity tariffs for the poor and rural electrification.
Program design
67
4. The total loans of the program is equivalent to US$712 million for 03 phases, including:
(i) US$312 million for phase 1 (DPL1); (ii) $200 million for phase 2 (DPL2) and (iii) $200 million
for phase 3 (DPL3). The program mainly focus on these 4 policy areas as following:
Development of power competitive market;
Restructuring of the power sector;
Reforming the electricity tariff;
Promoting effective use of energy from demand side.
5. The 3 phases DPL was started from 2010.
Implementation and Achievements
6. After over four years of implementing the program DPL, the policy conditions, which have
been performed by MOIT as committed with WB, contribute to construct a unified policy
framework in order to form a basis for developing the sustainable power sector.
7. The policy conditions during the period of implementing DPL1, DPL2, DPL 3, were
completed as committed with WB by MOIT. The changes in policy have been applied since 2010,
which contributed to improve the performance of the power sector, in terms of the following:
Developing the competitive market
8. Electricity Regulatory Authority of Vietnam (ERAV) completed the Conceptual design of
competitive electricity market, submitted to MOIT for approving the Decision 6713/QD-BCT
dated 31 December, 2009, which defined the conceptual design of Vietnam competitive electricity
market; Circular 18/2010/TT-BCT dated 26 April, 2010, regulating the operation of VCGM
(which has been revised annually and up to now, it has been placed by Circular 30/2014/TT-BCT
dated 2 October 2014); and the related instruction procedures, these are the basis to operate the
pilot VCGM since 1 July, 2011, and operate the full VCGM since 1 July, 2012. The electricity
metering system (stipulated in the MOIT’s Circular 27/2009/TT-BCT dated 25 September 2009)
and information-communication technology infrastructure (according to the decision 6941/QĐ-
BCT dated 30 December 2010 of the MOIT’s Minister) are upgraded in order to meet the
requirements of VCGM. Up to now, the generation stage has been operated under competitive
market, the market-oriented power sector enhance the transparency and efficiency in performance
of power generation companies;
Restructuring the power sector
9. According to the instruction of the Prime Minister on restructuring the power sector, the
committed policies under DPL was completed as follow: (i) The Institute of Energy has been being
under MOIT since 1 January, 2010 (Decision 5999/QĐ-BCT dated 27 November, 2009, issued by
Minister of MOIT); (ii) Established 03 independent accounting generation companies to EVN,
officially operated from 1 January, 2012 (Decision 3023/QĐ-BCT, Decision 3014/QĐ-BCT;
Decision 3025/QĐ-BCT, issued on 1 June, 2012 by Minister of MOIT); (iii) Issued the roadmap
of separating the electricity generation corporations and system-market operator (known as SMO)
into independent units. The restructuring stages were consistent with the reforming power sector
68
roadmap of the Government, gradually clarify all stages of electricity manufacture and business
without any major disturbance and ensure the stability in the sector;
Restructuring the electricity tariff
10. Decision 21/2009/QĐ-TTg was issued on 12 February 2009 by the Prime Minister,
regulated the electricity tariff in 2009 and the year from 2010 to 2012, which the sector was
operated under market mechanism, the average retail tariff was went up to 948,5 VND/kWh, while
the industrial and commercial customers were applied the time-of-use (ToU) tariffs, subsidized
rate was applied for the low-income households and subsidize for block from 0 to 50 kWh;
Decision 24/2011/QD-TTg dated 15 April, 2011 on the tariff adjustments following market
mechanism, so far it has been replaced by the Decision 69/2013/QĐ-TTg dated 19 November 2013
which regulates the adjustments on average retail tariff. MOIT issued the Circular 14/2010/TT-
BCT dated 15 April, 2010 prescribed the method of formulating the electricity transmission price,
procedures of constructing, issuing and managing the transmission price; Circular 41/2010/TT--
BCT dated 14 December, 2010 prescribed the method of formulating electricity tariff, as well as
the procedures of constructing, issuing the framework of generation tariff, and approval of the
power purchase agreement (so far, it was replaced by Circular 56/2014/TT-BCT dated 19
December, 2014; Circular 46/2011/TT0BCT dated 30 December, 2011 regulated the established
method, procedures of evaluating and approving the annual cost norms of the multi-purpose
strategic hydropower plants; Circular 12/2014/TT-BCT dated 31 March, 2014 prescribed the
calculation for average electricity retail tariff. Up to now, the average retail tariff has been
increased by about 59% compared to the year 2009, the details are specified as statistic below:
Approval 3/2009 3/2010 3/2011 12/2011 6/ 2012 12/2012 8/2013 3/2015
VNĐ/kWh 948,5 1.058 1.242 1.304 1.369 1.467 1.508,85 1.622,01
US cents/kWh 4,7 5,3 6,2 6,5 6,8 7,03 7,1 7,6
Increase - 11,5% 17,4% 5,0% 5,0% 5,0% 5,0% 7%
11. The Government promulgated these mentioned legal documents to show the willing to
reform the electricity tariff policies as committed. These actions contributed to the transparency of
electricity tariff, and gave the right/correct reflection the cost and demand–supply balance.
Promoting the efficient use of electricity on the demand side
12. After the program Vietnam energy efficiency and conservation program (VNEEP) which
was approved in 2006, the Government established a chain of activities with aim of promoting the
economical and efficient use of energy. The Law which regulated on the economical and efficient
use of energy (Law 50/2010/QH12 dated 17 June, 2010, effective date on 1 January 2011) was
overcome the shortcomings of the Resolutions, Decisions and Decrees that were issued earlier
related to the orientations of the national energy development of Vietnam. The Law on economical
and efficient use of energy is applied for organizations, households and individuals using energy
in Vietnam, this Law is to promote the renewable energy development for adapting the potentials
and conditions of Vietnam, to ensure the energy security and protect the environment. The
Government has also issued the decision which promulgated the list of devices and equipment
subject to energy labeling and application of the minimum energy efficiency, and the
implementation (Decision 51/2011/QĐ-TTg dated 12 September, 2011). The pilot demand
response program DSR using ToU is implemented by HCMC Power Corporation under the
69
Distribution Efficiency Project (DEP) granted by the World Bank (according to Decision
2600/QĐ-BCT dated 27 March, 2014).
II. Assess the criteria and effectiveness of the program
1. Indicator 1 - Hourly operational reserve of electricity generating capacity not less than 10
percent at all hours (from a 2008 baseline of periods with zero hourly reserve)
13. From 2008 to 2014, the capacity reserve of Power system is gradually increased from 0%
(2008) to 20-40% (2014) compare with the available capacity of generation. With the high growth
rate of demand consumption in Vietnam, the capacity reserve depend on some conditions such as
maintenance plan, hydrology, fuel, network congestion, dry and wet seasons, etc. and determine
base on the result of Power adequacy system assessment in medium and short term.
14. At present, in national power system, because the distribution of generation is not balanced
between each region, particularly the South region, so it still happens the unbalance of demand
and supply in the South. Hence, sometimes, during the power system operation, the capacity
reserve in the southern area is very small.
2. Contracts in place for 90 percent of demand, for non-BOT generation based on pricing
methodologies and standard format published by regulator, and the competitive generation spot
market price being published by the system and market operator (2009 baseline: no such contracts,
and no spot market)
15. According to Circular stipulating in market rules (Circular 18/2010/TT-BCT dated in 10th
May 2010; 45/2011/TT-BCT dated in 30th December 2011; 03/2013/TT-BCT dated in 08th
February 2013; currently is Circular 30/2014/TT-BCT dated in 02nd October 2014), the market
directed-trading generators’ rate of generated energy covered by contracts had been 95% in the
beginning of VCGM (by 01st July 2012) and reduced gradually year by year. Until now, this rate
is 90% for thermal power plants and hydropower plants with the under-2-day regulated water
reservoir; is 80% for hydropower plants with the over-2-day regulated water reservoir. In general,
the averaged rate is around 90% achieved the committed rate of DPL1, 2, 3 indicators.
16. By 14th December 2010, MOIT issued Circular 41/2010/TT-BCT stipulating in the method
for determining generation price, the procedures and order for setting up and issuing generation
price bracket and approving the power purchase agreement (replaced by Circular 56/2014/TT-
BCT and 57/2014/TT-BCT dated in 19th December 2014). All of the market directed-trading
generators have signed Power Purchase Agreements (PPA) with EPTC (EVN) complying
regulations in Circular 41/2010/TT-BCT (the list of these generators can be found in Decision
125/QĐ-ĐTĐL dated in 26th December 2014). In addition, EPTC also signed PPAs with other
IPPs which have the setting capacity from 30MW and over. The calculation of contract price
complied with the method regulated in MOIT Circulars.
17. Regarding to publishing of the competitive generation spot market price, NLDC published
daily the spot market marginal price in its website (www.nldc.evn.vn) and the interval website of
the electricity market.
3. The number and diversity of electricity generation companies is increased, with no single
company owning more than 45 percent of capacity (from a baseline of 70 percent in 2008)
70
18. From 2008, when the program DPL1 was being prepared to start, the power generation
market share of EVN accounted for 70%; ;PVN, TKV and other independent power producers
(IPPs) (including BOT power plants) shared the remaining 30% of market share. When the VCGM
was officially operated (1 July, 2012), there were 32 power plants directly bid in the market with
total capacity of 9.312MW, which was accounted for 39% over total capacity of the system. By
the end of June 2014, the number of power plants which directly bid in the market was raised up
to 51 above 102 of total operating power plants, and the total capacity is 12.478MW/29.940MW
which accounted for 41.7% of total system capacity (increased 4.4% compared with the year
2012).
19. According to the Prime Minister’s Decision 26/2006/QD-TTg dated 26 January, 2006
regulated the roadmap and conditions for establishing and developing a competitive electricity
market in Vietnam. The precondition in operating the full VCGM is “The total capacity of a power
generator should not be exceed 25% over the whole system”. However, this goal is difficult to
achieve in practice due to the equalization of power generators owned by EVN should be
implemented gradually and cautiously. So that in the process of preparing for the DPL program,
the objectives and given indicators were carefully considered and given at 45%. Up to June 2012,
3 Power Generation Corporations (GENCO) were established but they are still subsidiaries under
EVN and EVN managed 100% of their charter capital. During the negotiation process of DPL2
and DPL3, the separation of GENCOs was considered as non-feasible, therefore, it was converted
into commitments on implementation roadmap and it has been concretized in Decision
63/2013/QD-TTg dated November 8, 2013 by Prime Minister, which defined the roadmap,
conditions and structure of the power sector to establish and develop the electricity market of
Vietnam.
4. The system and market operator follows dispatch and system operation rules to ensure no
discrimination among generators, as measured by an independent audit (2009 baseline is no audit
while power market in not yet in place)
20. Currently, the National load dispatch Center (NLDC) owned by EVN is undertaking the
function of operating the power network and power market. NLDC activities comply with the
process for national load dispatch (about operating power system function) and provision of
operating the VCGM (about operating power market function). These provisions were published
by MOIT and applied nationwide to ensure the security of power supply, power system operation
and stable power market without discrimination between participants. The monitoring and
inspecting functions are under ERAV’s responsibility.
21. During the implementation process of DPL program, the audit compliance work of NLDC
were planned to perform by an independent audit unit but it has not been conducted. In fact, NLDC
has always sent the daily operation report to ERAV, then ERAV has summarized, evaluated and
completed the monthly report then sent to MOIT. For the requests of evaluating the market
operation performed by an independent unit, ERAV has selected the IES consultant from Australia
to implement, the evaluation report of power market operation has been done and sent to WB for
reference.
5. Annual tariff adjustments are approved each year (Baseline (2008): no regulation on electricity
tariff adjustment)
71
22. In 2009, MOIT was assigned to responsible for approving the annual average tariff
adjustment (by March) with updates of up to five percent (regulated in PM Decision 21/2009/QĐ-
TTg). From 2011, the average tariff adjustment had carried out by the mechanism stipulated in PM
Decision 24/2011/QĐ-TTg dated in 15th April 2011 (replaced by PM Decision 69/2013/QĐ-TTg).
With complying of this mechanism, the average tariff adjustment is based on changes/variation of
basic input parameters, such as: fuel price, exchange rate, mix-generation structure and electricity
market price. If the adjusted average tariff changes by under 5% compared with the current average
tariff (or from 7% to under 10% and within the framework of the average electricity tariff level
issued by PM, as regulated in Decision 69/2013/QĐ-TTg), EVN is permitted to adjust the average
tariff after reporting to MOIT and approved. If the adjusted average tariff changes by 5% and over
(or by 10% and over as well as out of the framework of the average electricity tariff level issued
by PM, as regulated in Decision 69/2013/QĐ-TTg), the average tariff adjustment will be approved
by the Prime Minister. The change in regulations expressed in above is reason why indicators
amended by DPL 1, 2, 3.
23. Applying the electricity tariff adjustment mechanism stipulated in PM Decisions, from
2010 up to now, the average tariff have adjusted seven times as the below table:
Approve 3/2009 3/2010 3/2011 12/2011 6/ 2012 12/2012 8/2013 3/2015
VNĐ/kWh 948,5 1.058 1.242 1.304 1.369 1.467 1.508,85 1.622,01
US cents/kWh 4,7 5,3 6,2 6,5 6,8 7,03 7,1 7,6
Increase - 11,5% 17,4% 5,0% 5,0% 5,0% 5,0% 7%
6. Cross subsidies from industrial and commercial to residential consumers are reduced by 50
percent. Subsidies to the poor are targeted to low income consumers (Baseline in 2008: cross
subsidies from industrial and commercial consumers (approximately of $370 million for 2007), an
untargeted subsidy to all residential consumers for the first 100 kilowatt hours (kWh) of
consumption, and local distribution utility tariffs higher than Vietnam Electricity’s)
24. The electricity tariff structure is stipulated by Decision 28/2014/QĐ-TTg, in which: there
is no subsidy from industrial to residential consumers (the average price for residential customers
is higher than industrial ones and is higher than national average price); residential price for the
first block (50 kWh) is calculated to 92% national average price and price for the second block
(from 50 - 100 kWh) is calculated to 95% national average price. Therefore, there are no subsidy
for the residential customers who consume less than 100 kWh. The social households with the
electricity consumption less than 50 kWh/month and poor households are paid equivalent to the
money for consumption of 30 kWh calculated by price for the first block, the expense for
supporting is taken from national budget.
25. Related to the item "local distribution utility tariffs higher than Vietnam Electricity (EVN)",
since 2009, the electricity prices were applied for whole customers connected to the national grid
so there have been no different between local distribution utility tariffs (in rural area) and EVN's.
7. Energy efficiency obligations are established by law and the regulator has capacity to enforce
and monitor load profiling and demand response programs by power corporations (PCs).
(Baseline in 2009: no energy efficiency law, no load profiling or demand response program
obligation on PCs)
72
26. Electricity Law has been issued in 2004 and revised in 2012; and Energy Efficiency and
Conservation Law has issued in 2010. According to the Electricity Law and Energy Efficiency and
Conservation Law, the Government and MOIT issued many regulations (Decree, Decision, and
Circular) to enhance the Demand Side Management implementation. Specifically, MOIT issued
the Circular 33/2011/TT-BCT on regulations of content, sequence and procedure of load research.
From 2011 to present, EVN and five Power Corporations gradually implement the Load research
activities to scale up, assess and monitor the load profiles of load sectors, sub-sectors and
segments; the outcomes of Load Research has been used in some activities for example in
planning, demand forecast, tariff management, etc.
27. In term of Demand Side Response programs, the DSR programs for Vietnam have been
proposed by International Consultant in 2012. In 2014, MOIT has approved the conceptual design
of Pilot DSR programs for implementation in HCM Power Corporation; in addition, the detailed
design of Pilot DSR programs also developed and completed. However, the proposed incentive
mechanism was not agreed by Ministry of Finance (MOF); besides, the alternative option of
incentive mechanism proposed by MOIT has received the agreement of MOF. The pilot DSR will
start to implement by second quarter of 2015. After the Pilot DSR, the result will be assessed and
proposed for expansion, the road map as well as conditions for full implementation of DSR will
be developed after the pilot programs.
Lessons Learned
28. Because the mechanisms for implementation of DPL has been applied at the early stage, it
was difficult in evaluating the project (especially in DPL stage 1). Learned from that, in DPL phase
2, EVN concentrated in implementing the sub-projects and operated them in a short time. This
action proved effective because the implementing time was shorten, and the workload was reduced
significantly.
29. ERAV (with the role of managing and evaluating unit) has been highly reliant on Technical
Assistance to bolster its capacity for the implementation of this program. We hope such sources
of assistance will be available at the time of implementing the next DPL programs.
ELECTRICITY REGULATORY AUTHORITY OF VIET NAM
73
THE ELECTRICITY OF
VIETNAM
INTERNATIONAL
COOPERATION DEPARTMENT
SOCIALIST REPUBLIC OF VIETNNAM
Independence – Freedom - Happiness
Hanoi, March 17, 2016
COMMENTS ON THE DRAFT ICR REPORT OF VIETNAM POWER SECTOR
REFORM SERIES DPL1,2,3
_____________________
To: Vice President Dinh Quang Tri
In implementation of the Vice President’s directions on commenting the content of draft
ICR report of the first, second and third Power Sector Reform Development Policy Operation
(DPL1,2,3) at the World Bank’s request, the International Cooperation Department (ICD) has
reviewed the report and circulated among the relevant departments and the National Load
Dispatch Centre (NLDC) for their comments. The ICD would like to summarize their comments
as follows:
1. Page 32 - Policy Area B: Power Sector Restructuring: WB’s rating ‘Modest’ does not reflect
the reality. The reason might be the fact that consultant has not yet studied elaborately the
equitization of Gencos which EVN has been carrying out in accordance with the Government
and MOIT’s directions. The MOIT issued Decision No. 551/QD-BCT of February 5, 2016
on equitization of GENCO 1, Decision No. 1125/QD-BCT of March 24, 2016 on equitization
of GENCO 2. At present, EVN is scheduling the equitization of GENCO 3 on June 30, 2016.
The consultant therefore is requested to update the latest information about the equitization
and power sector reform in the report.
2. Assessment on system adequacy and hourly operational reserve of Vietnam’s power system:
The consultant assessed that the increase in generation availability due to market efficiency
incentives improved reserve adequacy and supply security. This assessment is not adequate,
for the following reasons:
- System adequacy: According to EVN’s and a number of foreign consultants’, there is
no obvious relation between the increase in the system generation availability and price
signals in the power market during the last period.
- Hourly operational reserve: In fact, it is very difficult to judge whether this indicator
increased due to market incentives in the last period or not because the proportion of
non- market participating power plants is still high (>54%).
74
3. Figure 19. Structure of Power Sector in 2015 (page 35): It is requested to name exactly the
EVN’s Distribution Power Corporations (EVNNPC, EVNCPC, EVNSPC, EVNHANOI,
EVNHCMC) not PC1, PC2, PC3, PC4, PC5.
4. Para 86 (page 35): It is requested to clarify that Electric Power Trading Company (EPTC) is
not the single buyer. It acts on behalf of EVN to carry out the function of the single buyer on
the competitive generation market.
5. Para 93 (page 37): Information about the National Load Dispatch Centre (NLDC): NLDC
presently is an EVN’s dependent unit, it is therefore to revise the sentence (i) “...NLDC
remains fully dependent on EVN as a department of EVN...” as “... NLDC remains fully
EVN’s dependent unit...” and (ii) “...EVN subsidiaries effectively operate as branches of
EVN headquarters...” as “...EVN subsidiaries effectively operate as units of EVN...”,
accordingly.
The ICD would like to report and ask the Vice President’s permission to forward the
comments to WB.
Sincerely Yours,
Authorization of EVN’s management
ICD Director
Tran Tuan Dung
75
ERAV’s comments on WB’s draft ICR report of DPO1, 2 & 3
April 4, 2016
A. Basic information, a) PDO Indicators Page vi, Indicator 1:
From 2008, the hourly operational reserve is increased time to time and fully achieved the
indicator 1 at 2014. The “hourly operational reserve” is not defined in relevant GoV documents,
but it is a simple concept and it can recalled / examined base on data recorded in national load
dispatch center.
In calculation, the frequency control is approx. 3% of total available capacity of generation
(around 850 MW in 2015) is only count for some specific generators which serve as 1st
frequency control force however it is only a part of “hourly operational reserve”. In Viet Nam,
all generator connected to transmission grid must join the frequency control at 2nd level. So at
the same time, many other generator units are operating with an amount of reserve, they do not
count in frequency reserve, but spinning reserve.
Circular 12/2012 (Grid code) stipulates 7 kinds of ancillary services. Among them, frequency
control (action in 10s) - spinning reserve (action in 25s) - fast start (action in 15 min) can count
for “hourly operating reserve”.
With the above analysis, we think that the WB’s evaluation of indicator 1 by “partially achieved”
is not completed exactly, it should be "Achieved" or at least "largely achieved" if we consider the
situation that some short time the southern part has not sufficient reserve and need support from
national grid (though 500kV system), although operational reserve is count for the whole
national system.
A. Basic information, a) PDO Indicators page xi, indicator 7:
Agreed with WB’s evaluation, please adding the below content:
ERAV does not have enough mechanism for enforcing DSM and energy efficiency on PCs. The
reasons are:
- MOIT decision 2447 on approval of the National Program of DSM finished in 2015, while
Decision 2600/2014 only allows for pilot DSR program.
- A big obstacle is incentive mechanism for customer needs approval of Ministry of Finance.
Item 59, (Page 22): Updated the power system data by 2015:
By the end of 2015, the total number of power plants in operation was 109 (not including small
hydropower plants).
Total new capacity introduced in 2015 was 4,612 MW, bringing the total power installed
capacity of 38,642 MW (including small hydropower plants) increased by 14.83% as compared
with 2014.
76
In 2015, the total power production of national power system reached 164.31 billion kWh
(including power production sold to Cambodia) which increased by 12.9% as compared to 2014.
Figures 12 and 13 shows the installed capacity by ownership and type in 2015.
Figure 3. Installed Capacity in 2015 by Generation Type
Figure 4. Installed Capacity in 2015 by Ownership
Item 99, (Page 39): It should be supplement the Circular 31/2011/TT-BCT stipulated on
changing retail electricity accordingly to input parameters.
Item 120, (Page 47): ERAV had comment on this issue in Annex 3, item 6, page 73 that there is
no subsidy from industrial to residential customers:
“The electricity tariff structure is stipulated by Decision 28/2014/QĐ-TTg, in which: there is no
subsidy from industrial to residential consumers (the average price for residential customers is
higher than industrial ones and is higher than national average price); residential price for the
first block (50 kWh) is calculated to 92% national average price and price for the second block
(from 50 - 100 kWh) is calculated to 95% national average price. Therefore, there is no subsidy
for the residential customers who consume less than 100 kWh.”
43%
34%
19%
4%
Hydro Coal fired Gas turbine Oil fired
20%
17%
12%17%
12%
4%
10%8%
EVN Genco 1
Genco 2 Genco 3
PV Power Vinacomin
77
Annex 4. Program Performance: Prior actions and Evidence of their Fulfilment
Power Sector Reform DPO 1 - March 8, 2010
List of Prior Actions from Legal Agreement/Program Document Status
1. Establishing of design principles for the implementation of the VCGM MOIT Decision
6713/QD-BCT of
December 31, 2009
2. Establishing metering systems standards and procedures for generation plants
participating in the VCGM
MOIT Circular
27/2009/TT-BCT of
September 25, 2009
3. Establishing a sector structure to allow for the introduction of the VCGM Office of
Government (OoG)
Notice 232/TB-VPCP
of July 31, 2009
4. (a) increasing the average tariff in 2009 to VND 948/kWh, and (b)
implementing transparent annual tariff setting from 2010-12 based on cost
recovery principles, including the unbundling of the average retail tariff into
power supply cost components and the delegation of tariff changes of less than
five percent to the MOIT.
PM Decision
21/2009/QD-TTg of
Feb. 12, 2009
5. Restructuring the residential block tariff system to establish the principle of the
subsidy to the consumer as a percentage of production cost and extend the subsidy
mechanism and residential tariff structure to local distribution utilities.
PM Decision
21/2009/QD-TTg of
February 12, 2009
6. Establishing energy efficiency standards for consumer goods accounting for
large quantities of electricity.
MoST Decision
2740/QD-BKHCN,
December 9, 2008
and
Decision
632/QDBKHCN,
April 20, 2009
7. Introducing time-of-use tariffs for industrial zones and commercial, industrial,
and irrigation consumer categories
MOIT Circular
05/2009/TT-BCT,
February 26, 2009).
Power Sector Reform DPO 2 – February 22, 2012
List prior actions from Legal Agreement/ Program Document Status
1. Establishing market rules for the VCGM, instructing EVN to draft market
procedures, and delegating authority for ERAV to review and approve market
procedures.
MOIT Circular
18/2010/TT-BCT of
May 10, 2010
2. Establishing methodologies and procedures to determine and approve standard
contracts and pricing for generation, except for BOT and Strategic MultiPurpose
Hydro (SMHP)
MOIT Circular
41/2010/TTBCT
of December 14,
2010
3. Establishing methodology for cost recovery revenue requirement of SMHPs MOIT Circular
46/2011/TT-BCT
of December 30,
2011
4. Deciding to create Generation Companies (GENCOs) with portfolio of EVN
power plants, excluding SMHP, to later become independent successor companies
with no cross ownership with transmission or Single Buyer (SB).
OoG Notice
77/TB-VPCP of
April 5, 2011)
(MOIT Letter
350/TTr-BCT of
November 15, 2011)
(PM Letter 138
/TTgĐMDN of
February 3, 2012)
78
5. Establishing market based mechanism to adjust average electricity tariff,
including annual update and adjustments during the year to reflect changes in
generation costs.
PM Decision
24/2011/QD-TTg,
April 15, 2011)
MOIT Circular
31/2011/TTBCT
of August 19, 2011)
6. Establishing methodologies to determine and approve transmission revenue
requirement for NPTC, and transmission charges.
MOIT Circular
14/2010/TTBCT
of April 15, 2010)
(MOIT Circular
03/2012/TT-BCT of
January 19, 2012,
amending and
complementing
Circular 14)
7. Establishing load research regulations for PCs. MOIT Circular
33/2011/TTBCT
of September 6, 2011
Power Sector Reform DPO 3 – May 27, 2014
List prior actions from Legal Agreement/ Program Document Status
1. The commercial operation of the Vietnam Competitive Generation Market has
been fully implemented.
Settlement and
market monitoring
report submitted to
the Bank
2. All GENCOs have started commercial operations and registered as market
participants in VCGM.
MOIT Decisions
3203, 3204,
3205/2012/QD-BCT.
3. The Borrower, through its Prime Minister, has issued Decision 63/2013/QD-
TTg dated November 8, 2013 to set forth the roadmap and operational principles
for a power wholesale competitive market through the separation of GENCOs and
the System and Market Operator into independent companies that are not cross-
owned with other market participants.
PM Decision
63/2013/QD-TTg
dated November 8,
2013
4. The Borrower, through Ministry of Industry and Trade, has issued Circular
12/2014/TT-BCT dated March 31, 2014, setting forth the methodologies for the
establishment of annual retail electricity tariffs
MOIT Circular
12/2014/TT-BCT
dated March 31, 2014
5. The Borrower, through MOIT, has issued Decision 2600/QD-BCT dated March
27, 2014 to authorize a power distribution company to carry out a demand-
response program
MOIT Decision
2600/QD-BCT of
March 27, 2014
6. At least one power company has begun to pilot a demand-response program MOIT Decision
2600/QD-BCT
79
Annex 5. Prior Actions and Indicative Triggers for Each PSRDPO
Prior Actions for
PSRDPO 1
Indicative Triggers
for PSRDPO 2 at
PSRDPO 1
Prior Actions for
PSRDPO 2
Indicative Triggers
for PSRDPO 3 at
PSRDPO 1
Indicative Triggers
for PSRDPO 3 at
PSRDPO 2
Prior Actions for
PSRDPO 3
Policy Area A: Development of Competitive Power Market
The Borrower has,
through the MOIT,
issued a Decision
(No. 6713-QD-BCT
dated December 31,
2009) establishing
design principles for
the implementation
of the VCGM.
The Borrower has,
through the MOIT,
issued a Circular
(No. 27/2009/TT-
BCT dated
September 25,
2009) establishing
metering systems
standards and
procedures for
generation plants
participating in the
VCGM.
MOIT issues
Circular setting out
market rules for
VCGM.
MOIT promulgates
standard contracts
and its pricing
methodology for
non-BOT
generation, and
pricing for each
SMHP.
Establishment of
market rules for the
Vietnam
Competitive
Generation Market;
issuance of
instructions to
Vietnam Electricity
(EVN) for the
preparation of
market procedures
for said Market; and
delegation of
authority to ERAV
for the review and
approval of said
market procedures.
Establishment of
methodologies and
procedures for the
development and
approval of standard
contracts and
pricing for
generation (except
for build-operate-
transfer and
strategic
multipurpose
hydropower).
VCGM commercial
operation
implemented.
SMO completes
settlement for two
months of trading in
the VCGM and SB
completes payments
to generation.
VCGM starts full
commercial
operation. (SMO
settlement
document for first
month of VCGM)
Successor Generation
Companies start
commercial
Operation and
register as market
participants in
VCGM.
The commercial
operation of the
Vietnam
Competitive
Generation Market
has been fully
implemented.
80
Establishment of
methodology for
cost-recovery-
related revenue
requirements for
strategic
multipurpose
hydropower.
Policy Area B: Power Sector Restructuring
The Borrower has,
through the OOG,
issued a Notice (No.
232/TB-VPCP
dated July 31, 2009)
establishing a sector
structure to allow
for the introduction
of the VCGM
Prime Minister
issues Decision on
successor
generation
companies’
structure for
VCGM.
MOIT issues
regulations to ring
fence costs,
revenues and
information for
NPTC, NLDC and
EPTC until they
become independent
companies.
Formal
communication of a
decision to establish
generation
companies with a
portfolio of EVN
power plants
(except for strategic
multipurpose
hydropower) and to
be independent
successor
companies in due
course with no cross
ownership with
respect to
transmission or with
the Single Buyer.
MOIT establishes
each successor
generation company
with no cross
ownership with
transmission or
Single Buyer,
except for SMHP.
MOIT establishes
SMO as a company
with no cross
ownership with
other electricity
activities.
Establishing the
timing for the
separation of
GENCOs, into
independent
companies with no
cross-ownership
with transmission or
the Single Buyer
(Office of
Government notice /
MOIT decision)
All GENCOs have
started commercial
operations and
registered as market
participants in
VCGM.
The Borrower,
through its Prime
Minister, has issued
Decision Number
63/2013/QD-TTg
dated November 8,
2013 to set forth the
roadmap and
operational
principles for a
power wholesale
competitive market
through the
separation of
GENCOs and the
System and Market
Operator into
independent
companies that are
not cross-owned
with other market
participants.
81
Policy Area C: Electricity Tariff Reform
The Borrower has,
through the Prime
Minister, issued a
Decision (No.
21/2009/QD-TTg
dated February 12,
2009): (a)
increasing the
average tariff in
2009 to Vietnamese
Dong 948 / kWh;
and (b)
implementing
transparent annual
tariff-setting from
2010-12 based on
cost recovery
principles, including
the unbundling of
the average retail
tariff into power
supply cost
components and the
delegation of tariff
changes of less than
five percent (5%) to
the MOIT.
The Borrower has,
through the Prime
Minister, issued a
Decision (No.
21/2009/QD-TTg
dated February 12,
2009) restructuring
the residential block
tariff system to
establish the
principle of the
MOIT and Ministry
of Finance (MOF)
issue joint Circular
with procedures for
retail tariff annual
adjustments.
MOIT issues
Circular with
methodologies and
procedures to
determine
transmission
revenue requirement
and approve
transmission
charges.
MOIT issues
Circular with
procedures to
determine and
approve SMO
charges.
Establishment of a
market-based
mechanism for the
adjustment of
average electricity
tariffs, including
annual updates and
adjustments during
the year as
necessary to reflect
changes in
generation costs.
Establishment of
methodologies for
the determination
and approval of
transmission
revenue
requirements for
National Power
Transmission
Corporation and
transmission
charges to be paid to
National Power
Transmission
Corporation by
transmission users.
MOIT mandates
implementation of
PBR through
approval of three
year revenue
requirements for
each PC.
Establishing
Performance Based
Regulation (PBR) to
set distribution
network tariffs of
each PC, with
multi-year allowed
cost revenue
requirement. (MOIT
Circular)
The Borrower,
through Ministry of
Industry and Trade,
has issued Circular
12/2014/TT-BCT
dated March 31,
2014 setting forth
the methodologies
for the
establishment of
annual retail
electricity tariffs.
82
subsidy to the
consumer as a
percentage of
production cost and
extend the subsidy
mechanism and
residential tariff
structure to local
distribution utilities.
Policy Area D: Improving demand side response and energy efficiency
The Borrower has,
through the MOST,
issued Decisions
(No. 2740/QD-
BKHCN dated
December 9, 2008
and No. 632/QD-
BKHCN dated
April 20, 2009)
establishing energy
efficiency standards
for consumer goods
accounting for large
quantities of
electricity
consumption.
The Borrower has,
through the MOIT,
issued a Circular
(No. 05/2009/TT-
BCT dated February
26, 2009)
introducing time-of-
use tariffs for
industrial zones and
commercial,
industrial, and
irrigation consumer
categories.
Prime Minister
sends Energy
Efficiency Law to
National Assembly.
Establishment of
load research
regulations for
power companies.
MOIT issues
implementation
decree for energy
efficiency law.
MOIT Circular
promulgates time of
use tariffs based on
load profiles.
Establishing
regulations for PCs
to implement
demand response
programs (MOIT
Circular)
One PC starts pilot
of demand response
programs within
their licensed area.
The Borrower,
through MOIT, has
issued Decision
Number 2600/QD-
BCT dated March
27, 2014 to
authorize a power
distribution
company to carry
out a pilot demand-
response program.
At least one power
company has begun
to pilot a demand-
response program
83
Annex 6. PDO Indicators from Results Matrix of Each PSRDPO
Results Matrix DPO1 Results Matrix DPO2 Results Matrix DPO3
1 Increase in generation
availability due to market
efficiency incentives improves
reserve adequacy and supply
security.
Indicator:
Hourly operational
reserve at least 10%
Increase in generation
availability due to market
efficiency incentives and
increase in quality of service due
to technical codes.
Indicator:
System is operated with hourly
operational reserve
at least 10%
Increase in generation
availability due to market
efficiency incentives and
increase in quality of service due
to application of technical codes.
Indicator: System is operated
with hourly operational reserve
at least 10 percent
2 Enhanced transparency in
generation contracting and
pricing, creating predictability
for investors.
Indicators:
1. Contracts in place for 90
percent of demand, for non BOT
generation based on pricing
methodologies and standard
format published by regulator.
2. VCGM spot market price
disclosed in SMO website to
which the public has access.
Enhanced transparency in
generation contracting and
pricing, creating predictability
for investors. Indicators:
1. Contracts in place for 90
percent of demand, for non BOT
generation based on pricing
methodologies and standard
form issued by MOIT.
2. VCGM spot market price
disclosed in SMO website to
which the public has access.
Enhanced transparency in
generation contracting and
pricing, creating predictability
for investors.
Indicators:
(i) Contracts in place for 90
percent of demand, for non BOT
generation based on pricing
methodologies and standard
form issued by MOIT.
(ii) VCGM spot market price
disclosed to agents in SMO
website to which the public has
access.
3 The independence and diversity
of electricity generators
increases, creating conditions
that enable development of
effective competition and allow
the transition to wholesale
competition.
Concentration Indicator:
No single company owning
more than 40 percent of total
installed generation capacity.
The diversity of electricity
generators increases, creating
conditions that enable
development of effective
competition and allow the
transition to wholesale
competition.
Concentration Indicator:
No single company owning
more than 45percent of total
installed generation capacity.
The diversity of electricity
generators increases, creating
conditions that enable
development of effective
competition and allow the
transition to wholesale
competition.
Indicator: No single company
owns more 45 percent of total
installed generation capacity.
4 The SMO provides efficient and
non discriminatory services
following VCGM rules, codes
and regulations.
Indicator: SMO technical market
audit by independent consultant
firm completed and report on
compliance published in SMO
website to which the public has
access.
The SMO provides efficient and
non discriminatory services
following VCGM rules, codes
and regulations.
Indicator: SMO technical market
audit by independent consultant
firm completed and report on
compliance published in SMO
website to which the public has
access.
The SMO provides efficient and
nondiscriminatory services
following VCGM rules, codes
and regulations.
Indicator: SMO technical market
audit by independent consultant
firm completed and report on
compliance published in SMO
website.
5 Tariff annual updates approved
by MOIT up to 5 percent.
Indicator: annual tariff
adjustment is approved by
March each year.
Tariff annual updates,
approved by MOIT if up
to 5 percent.
Indicator: annual tariff
adjustment approved each year.
Tariff annual setting applying
market based mechanisms,
approved by MOIT. Periodic
adjustments (up to quarterly and
capped to 5 percent) to address
changes in uncontrollable cost
drivers (fuel prices, rate of
exchange VND vs. foreign
currencies).
Indicator: Annual tariff
determination and periodic
adjustment procedures
84
Results Matrix DPO1 Results Matrix DPO2 Results Matrix DPO3
Approved
6 Phase out of cross subsidy
between different tariff
categories.
Indicator (a) level of cross
subsidy from industrial and
commercial categories to
residential reduced at least 50
percent.
Indicator (b) subsidies targeted
to the poor, in both urban and
rural areas
Phase out of cross subsidy
between different tariff
categories.
Indicator (a) level of cross
subsidy from industrial and
commercial categories to
residential reduced at least 50
percent.
Indicator (b) subsidies targeted
to the poor, in both urban and
rural areas
Phase out of cross subsidy
between different tariff
categories
Indicator: (i) Level of cross
subsidy from industrial and
commercial categories to
residential reduced at least 50
percent.
(ii) Subsidies targeted
to the poor, in both urban and
rural areas
7 Enhanced energy
efficiency through legal
framework, and adequate
monitoring and enforcement
mechanisms
Indicator: Energy
efficiency target established by
law, and
MOIT and ERAV has the
capacity to enforce demand side
management (DSM) and energy
efficiency requirements on
power companies.
Enhanced energy efficiency
through legal framework, and
adequate monitoring and
enforcement mechanisms
Indicator: Energy efficiency
obligations established by law,
and MOIT and ERAV have the
capacity to enforce and PCs the
authority to implement demand
response programs.
Enhanced energy efficiency
through legal framework, and
adequate monitoring and
enforcement mechanisms
Target: Energy efficiency
Obligations established by
law, and MOIT and ERAV have
the capacity to enforce and PCs
the authority to implement
demand response programs.
85
Annex 7. Overview of the Conceptual Design of the VCGM
The following summary of the VCGM is an excerpt directly reproduced from an ERAV
document: “Vietnam Competitive Generation Market (VCGM) Market Background Note –
Attachment to the TOR for Consultancies Assisting ERAV in VCGM Implementation”.
1. The design of the market has been tailored trying to address potential power market
abuse and conflicts of interest due to cross ownership.
2. The design of the competitive generation market for Vietnam (VCGM) was approved
by MOIT in December 2009, while the Market Rules were issued by MOIT in May 2010.
3. In the VCGM cost-based power pool (CBP), direct participation by generators is
mandatory except for (i) generation with installed capacity equal or lower than 30 MW; and (ii)
for existing foreign-invested BOTs, including those under negotiation or being tendered, which
hold long-term PPAs for their full capacity.
Figure 7.1. VCGM Participants
Note: SMO: System Market OperatorTNO: Transmission Network Owner, MDMSP: Metering Data
Management Service ProviderPCs: Power CorporationsSMHPs: Strategic Multipurpose Hydro Power Plants;
HPPs: Hydro Power Plants; FSR: Fast Start Reserve;service providers SPPs: Small Power Plants (<30 MW);
CSR: Cold Start Reserve; service providers TPPs: Thermal Power Plant; RMR: Reliability Must-Run service
providers
86
Figure 7.2. VCGM Overall Structure
Generation Bids and Market energy pricing:
4. All generation must submit bids to compete for dispatch and to sell to the pool, except
for:
Large strategic multi-purpose hydro plants (SMHPs). The SMHPs, which generally
have market power, will be scheduled by the SMO based on the calculated water
value for each reservoir using a water value model. Water values are based on the
principle of maximising the opportunity cost of stored water within other water uses
and ecological constraints, expected load and available generation balance, expected
transmission constraints and thermal variable costs.
Run-of-river hydro and small renewables that participate in the VGCM will be
considered as ‘must-take’ generators in the scheduling process and as bid price zero.
5. Price-quantity bids will be submitted on the day-ahead and used for next day generation
scheduling and dispatch. The EPTC, as Single Buyer (SB) and the purchaser of BOTs long term
PPAs, will submit bids for BOTs.
6. Each trading period (hourly), the spot market has a single price that will apply to all
energy sold to the spot market independent on generation location. (It is considered that the
central planning of new generation investment removes the need to incorporate locational
signals into market prices for generation investors to decide type of project and location to
connect to the grid). All energy generated will be sold to the only buyer in the Pool – the EPTC
as SB - priced for each trading period (hourly) at the spot market System Marginal Price (SMP)
except for constrained-on generation where separate pricing arrangements. The SMP is
calculated ex post based on the highest bid accepted in an unconstrained schedule to supply the
actual demand.
87
7. A number of mechanisms have been designed to avoid the spot market delivering
excessively high or volatile prices, particularly during the initial years when reserve margins
may be low:
Each generation must submit bids not higher than a cap calculated by the
System and Market Operator (SMO, a role assigned to NLDC) and approved
by ERAV;
For thermal generation, the bid cap will be based on fuel costs and assumed
efficiency of reference generation type;
To promote efficient use of available hydro resources, bids by hydro power
plant will be restricted to a range of 80% up to 110 of the water value as
calculated by the SMO water value model for each one;
An overall price cap will apply to the spot market designed to deliver an
acceptable maximum price;
Role of the Single Buyer:
8. In the VCGM, EPTC will be the only purchaser as well as act in representation of BOTs.
As a wholesaler, EPTC will sell to PCs at a bulk supply tariff (BST) which includes generation
(power purchase costs of EPTC), transmission charges of PCs and system and market operation
charges (including ancillary services costs, and other administration and regulatory costs and
fees.
Capacity payment:
9. To enable recovery of efficient fixed costs even if bid prices and SMP are capped based
exclusively on generation variable costs, a capacity hourly payment in the form of a Capacity
Add-On (CAN) will be paid, except in hour of low demand, to reflect hour when capacity is
required to ensure supply security. A generation hourly schedule will be prepared ex post
exclusively for the allocation of CAN hourly payment. The CAN schedule will show the
generation dispatched in the unconstrained schedule to supply the actual demand plus a margin
set to cover operating reserve requirements and an additional ‘incentive’ margin to encourage
generators to be available.
10. The CAN total annual payment and the CAN hourly price will be set before the
beginning of each year. The total annual CAN amount will be calculated as the difference
between the costs of a Best New Entrant (BNE) generation and the revenues that this generator
is estimated to earn from energy sales at SMP prices in a simulation of the coming year. This
difference - the total CAN ‘pot’ - will then be allocated across months and hours in the year in
proportion to the forecasted demand level and therefore need for available and reserve capacity
in those hours.
Generator Contracts:
11. Non-BOT generators and the SB will be hedged against spot/pool market price risks
through the use of standard VCGM contracts structured as contracts for differences. Each
generator participating in the market will hold a standard contract with the SB, with the annual
energy quantity defined before the beginning of year as up to 95% of its expected output in the
next year. For new generation, there will be a single strike price (energy only, the same price
for all hours in the year). This contract price will be based on average cost methodology (sum
of variable plus annual fixed costs divided by annual energy). The costs will be agreed in
negotiation with the SB within a range defined through benchmark generation pricing
methodology and model.
Ancillary Services:
88
12. Scheduling of ancillary services may in future be co-optimized with energy scheduling
but is initially expected to be separate. Thermal generation will be paid the opportunity cost
when providing spinning reserves. Standard Ancillary Services Agreements (SASAs) will be
offered for some services. These include persistently constrained-on (reliability-must-run,
RMR) generation, that will be paid their variable and fixed costs, fast-start reserve (FSR)
generation such as open-cycle turbines who will be paid their fixed costs to ensure they remain
available even when not dispatched and therefore unable to recover their costs from sales in the
market and cold-start reserve (CSR) generators, who are infrequently dispatched but are
required for system security (e.g., in dry years).
Settlement:
13. Settlement calculation and documents of the spot market will be prepared by the SMO.
The SB will directly pay generators the net result of spot sales and Contract for Difference
(CfD)s, except for BOTs where the SB will pay following the pricing and payment
arrangements established in the PPA.
Role of the SMO:
14. For the purpose of establishing hourly generation to maintain system balance and
reliability, actual generation schedules will be prepared by the System and Market Operator
(SMO) using the submitted bids on a security constrained basis that minimizes daily costs.
15. Generators will not be permitted to self-schedule. Generation operational constraints
(start-up times, ramp-up / ramp-down rates) will be taken into account in the scheduling by the
SMO.
16. During daily real time operation, the SMO is responsible for issuing dispatch
instructions, procurement, and scheduling of ancillary services, including reserves. In
emergencies or unexpected situations that can endanger the integrity of the system or security
of supply, the SMO can instruct changes in generation schedule without following the merit
order, but must return to an economic dispatch of bids as soon as practical and possible.
17. Bids and generation scheduling processes are established in the Market Rules.
Generation Rules for real time operation and dispatch are covered in the Grid Code.
89
Annex 8. List of Supporting Documents
References
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Asian Development Bank. 2015. Assessment of Power Sector Reforms in Viet Nam: Country
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ERAV (Electricite du Viet Nam). 2014. Electricity Transmission Pricing Review - recommended
improvements to the current methodology.
———. 2015. Proposed Tariff Restructuring Plan.
Energy Sector Management Assistance Program (ESMAP). 2014. Vietnam Low Carbon Options
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Groom, Eric. 2014. Final Report: Assessment of the Framework for Tariff Regulation.
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———. 2014. Development of Detailed Design for Wholesale Electricity Market of Vietnam,
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———. 2015a. Appraisal of Draft Revised Master Plan on Power Development for Period
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———. 2015b. Appraisal of Draft Revised Master Plan on Power Development for Period
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———. 2015c. Appraisal of Draft Revised Master Plan on Power Development for Period
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———. 2015d. Appraisal of Draft Revised Master Plan on Power Development for Period
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———. 2015f. Vietnam Wholesale Electricity Market Detailed Design Study: Discussion on
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———. 2014b. Restructuring and Diversiture Strategy - First Field Mission Report and Next
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———. 2015a. Strategic Options for Enhanced Financial Performance of EVN, Report on
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———. 2015b. Strategic Options for Enhanced Financial Performance of EVN, Final Report on
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Mickle, Craig. 2015. Harmonizing Electricity Tariffs with Implementation of Demand Response
Programs: Final Assessment Report.
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Pardina, Martin Rodriguez. 2015. Assessment of Tariff Structure and Tariff Framework.
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———. 2014a. Mission AM, Distribution Efficiency Project.
———. 2014b. PAD Transmission Efficiency Project (TEP).
———. 2015. Performance and Learning Review of the Country Partnership Strategy for the
Socialist Republic of Vietnam for the Period FY12 – FY16.
———. 2016. Vietnam 2035: Toward Prosperity, Creativity, Equity, and Democracy, Overview.
Legal Documents of the Government of Vietnam
MOIT Decision 6713/QD-BCT of December 31, 2009
MOIT Circular 27/2009/TT-BCT of September 25, 2009
MOIT Circular 05/2009/TT-BCT, February 26, 2009
MOIT Circular 18/2010/TT-BCT of May 10, 2010
MOIT Circular 41/2010/TT-BCT of December 14, 2010
MOIT Circular 46/2011/TT-BCT of December 30, 2011
MOIT Letter 350/TTr-BCT of November 15, 2011
MOIT Circular 31/2011/TT-BCT of August 19, 2011
91
MOIT Circular 14/2010/TT-BCT of April 15, 2010
MOIT Circular 03/2012/TT-BCT of January 19, 2012
MOIT Circular 33/2011/TT-BCT of September 6, 2011
MOIT Decisions 3203, 3204, 3205/2012/QD-BCT.
MOIT Circular 12/2014/TT-BCT dated March 31, 2014
MOIT Decision 2600/QD-BCT of March 27, 2014
MOIT Decision 4887/QD-BCT, May 2014
MOIT Decision 2256/QĐ-BCT, March 2015
MOIT (March 2014) - Circular 12 on Calculation of Average Retail Price of Electricity
MOIT (May 2010)- Circular 18, VCGM Market Rules
MOST Decision 2740/QD-BKHCN, December 9, 2008
OoG Notice 232/TB-VPCP of July 31, 2009
OoG Notice 77/TB-VPCP of April 5, 2011
PM Decision 26/2006/QD-TTg of January 26, 2006
PM Decision 21/2009/QD-TTg of February 12, 2009
PM Decision 632/QDBKHCN, April 20, 2009
PM Decision 268/2011, February 2011
PM Decision 28/2014/QĐ-TTg, April 2014
PM Letter 138 /TTgĐMDN of February 3, 2012
PM Decision 24/2011/QD-TTg, April 15, 2011
PM Decision 63/2013/QD-TTg dated November 8, 2013