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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


Lending Instrument DPL Borrower Socialist Republic of Vietnam

Original Total



Electricity Regulatory Authority of Vietnam (ERAV - MOIT)


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


Lending Instrument DPL Borrower Socialist Republic of Vietnam

Original Total



Electricity Regulatory Authority of Vietnam (ERAV - MOIT)

ii


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


Date(s)




Closing: 07/31/2013 07/31/2013



Date(s)




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


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


Implementation


QAG Assessments

(if any) Rating:

Potential Problem

Program at any time

(Yes/No):

No Quality at Entry

(QEA) None


time (Yes/No): No

Quality of


DO rating before



Implementation


QAG Assessments

(if any) Rating:

Potential Problem

Program at any time

(Yes/No):

No Quality at Entry

(QEA) None


time (Yes/No): No

Quality of


DO rating before


D. Sector and Theme Codes


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


Original Actual


General energy sector 100 100


Infrastructure services for private sector development 14 14



Original Actual


General energy sector 100 100


Infrastructure services for private sector development 14 14


E. Bank Staff


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 –



Vice President Victoria Kwakwa Pamela Cox


Practice

Manager/Manager Julia M. Fraser Jennifer J. Sara

Task Team Leader Pedro Antmann Beatriz Arizu de Jablonski



v



Vice President Victoria Kwakwa Axel van Trotsenburg


Practice

Manager/Manager Julia M. Fraser Jennifer J. Sara

Task Team Leader Pedro Antmann Pedro Antmann



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)


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


No. Date ISR

Archived DO IP

Actual

Disbursements

(US$, millions)

1 04/27/2010 Satisfactory Satisfactory 0.00


No. Date ISR

Archived DO

IP

Actual

Disbursements

(US$, millions)



No. Date ISR

Archived DO IP

Actual

Disbursements

(US$, millions)


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


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)


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


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.


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


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


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


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.


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


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


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


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


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


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


P124174 - Vietnam Power Sector Reform DPO2


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


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


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


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


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)





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)





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



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


BCT)

Date achieved 04/06/2010 – – 12/03/2010

Comments


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


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


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




Original Target

Values (from

approval documents)

Formally

Revised Target

Values

Actual Value

Achieved at


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,


BCT)

Date achieved 04/06/2010 – – 06/30/2011

Comments


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


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


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


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




Original Target

Values (from

approval

documents)

Formally

Revised

Target

Values

Actual Value Achieved at


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.


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.


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).


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)


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.


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.


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


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


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


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


Enhanced transparency in



for investors. Indicators:

1. Contracts in place for 90




form issued by MOIT.

2. VCGM spot market price

disclosed in SMO website to


Enhanced transparency in



for investors.

Indicators:

(i) Contracts in place for 90




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


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


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


access.

The SMO provides efficient and

non discriminatory services


and regulations.






access.

The SMO provides efficient and

nondiscriminatory services


and regulations.





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


categories.

Indicator (a) level of cross




percent.

Indicator (b) subsidies targeted


rural areas

Phase out of cross subsidy


categories

Indicator: (i) Level of cross




percent.

(ii) Subsidies targeted


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

Antman, Pedro. 2014. Reform of the Electricity Sector in Latin American Countries: Main

Characteristics and Emerging Lessons.

Asian Development Bank. 2015. Assessment of Power Sector Reforms in Viet Nam: Country

Report. Mandaluyong City, Philippines: Asian Development Bank.

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

Assessment.

Groom, Eric. 2014. Final Report: Assessment of the Framework for Tariff Regulation.

Information & Energy Services, Inc. (IES). 2012. Assessment of Readiness to Start Full VCGM.

———. 2014. Development of Detailed Design for Wholesale Electricity Market of Vietnam,

Task 1: Assessment Report.

———. 2015a. Appraisal of Draft Revised Master Plan on Power Development for Period

2011-2020 With Vision to 2030, Inception Report.

———. 2015b. Appraisal of Draft Revised Master Plan on Power Development for Period

2011-2020 With Vision to 2030, Task 1: Demand Forecasting.

———. 2015c. Appraisal of Draft Revised Master Plan on Power Development for Period

2011-2020 With Vision to 2030, Task 2: Generation Planning.

———. 2015d. Appraisal of Draft Revised Master Plan on Power Development for Period

2011-2020 With Vision to 2030, Task 3: Transmission Network Development.

———. 2015e. Development of Detailed Design for Wholesale Electricity Market of Vietnam,

Task 2 A: Detailed Design.

———. 2015f. Vietnam Wholesale Electricity Market Detailed Design Study: Discussion on

Capacity Mechanism. Dr. Stuart Thorncraft; Mr. Stephen Wallace; Power point presentation;

Hanoi, 20 March 2015.

ITAC. 2014a. Inception Report - Restructuring and Divestiture Strategy for GENCOs.

———. 2014b. Restructuring and Diversiture Strategy - First Field Mission Report and Next

Steps.

———. 2014c. Restructuring and Diversiture Strategy - Inception Findings and Next Steps.

———. 2015. Equitization and Divestiture Strategy – Interim Report.

90

Lahmeyer International. 2015. Vietnam Pumped Storage Power Development Strategy - Power

Sector Analysis and Pumped Storage Power Development Plan.

Lupano. 2012. Overall Review of Tariff Regulation Package.

Mercados.2014. Strategic Options for Enhanced Financial Performance of EVN Power

Companies, Ver. 7.

———. 2015a. Strategic Options for Enhanced Financial Performance of EVN, Report on

Overall Diagnosis of EVN.

———. 2015b. Strategic Options for Enhanced Financial Performance of EVN, Final Report on

Financial Evaluation and Projections of EVN (Task 2).

Mickle, Craig. 2015. Harmonizing Electricity Tariffs with Implementation of Demand Response

Programs: Final Assessment Report.

MOIT. 2015. Government ICR.

Pardina, Martin Rodriguez. 2015. Assessment of Tariff Structure and Tariff Framework.

PSR. 2014. Assessment of Alternative for Capacity Adequacy Mechanisms for the VWEM.

Schlift Rapti. 2012. Review of Retail Tariff Structure and subsidized Tariff Package.

World Bank. 2011. Country Partnership Strategy for the Socialist Republic of Vietnam for the

Period FY12 – FY16.

———. 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