The World Bank/ PPIAF/ MOIT · • 2005 through 2008: A pilot internal market within EVN • 2009....

The World Bank/ PPIAF/ MOIT Vietnam: Framework for Thermal BOT Tenders & Strategy for Gas Coordination and Harmonization with Market Roadmap

Final Report

Volume I: - Executive Summaries - Coordination between New Gas-fired

Generation and Development of Natural Gas Resources

20 June 2009

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69891 v1

The World Bank/ PPIAF/ MOIT 20/6/09

The World Bank/ PPIAF/ MOIT Vietnam: Framework for Thermal BOT Tenders & Strategy for Gas Coordination and Harmonization with Market Roadmap

Final Report

Volume I: - Executive Summary - Coordination Between New Gas-fired

Generation and Development of Natural Gas Resources

20 June 2009

PA Consulting Group Level 4

369 Queen Street Auckland 1010

Tel: +64 9 306 8895 Fax: +64 9 306 8896

www.paconsulting.com

Prepared for: Prepared by:

The World Bank/ PPIAF/ MOIT PA Consulting Group

Version: 1.0

iii


FOREWORD

This Final Report represents the third and final under The World Bank PPIAF-financed Vietnam Framework for Thermal BOT Tenders & Strategy for Gas Coordination and Harmonization with Market Roadmap. It consists of two volumes: Volume 1 presents the executive summaries of assignment activities, and a detailed report on coordination of gas and power development planning. Volume 2 presents the detailed report on mechanisms for market integration and competitive tendering. The terms of reference for the assignment are presented as Appendix A to this report, and the final workshop presentation is provided as Appendix B.

The report was prepared by Mike Crosetti and John George of PA Consulting Group, Richard MacGeorge of Ridgway Capital Projects Ltd, and Bruce Cole, with additional comments and inputs from Nguyen Quang Hung of Vilaf-Hong Duc Law Firm, Luu Hoang Ha of LDV Lawyers, and Jim Bradley of Hunton & Williams. This report compiles the principal results of all project activities, which commenced in September 2007 and entailed several visits to Vietnam by the team over the course of the work.

The consultants gratefully acknowledge the assistance of the counterpart team from the Ministry of Industry and Trade (MOIT), in particular Messrs. Pham Hung, Pham Manh Thang, Ho Dinh Tham and Mai Dinh Trung, as well as Mr. William Derbyshire, Resident Advisor to ERAV, and Ms. Beatriz Arizu and Mr. Richard Spencer of The World Bank.

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ABBREVIATIONS

2P Proven + probable petroleum reserves ACAP Available Capacity, used in the context of a capacity assurance scheme ADB Asian Development Bank ASB Authorized State Body bcm Billion cubic meters BNE Best New Entrant BOT Build-Operate-Transfer. Unless indicated otherwise, this report uses BOT to

refer to thermal power generators in Vietnam operating under a BOT Contract.

BT Build-Transfer BTO Build-Transfer-Operate BTU British thermal unit CAN Capacity add-on payment CCGT Combined Cycle Gas Turbine CDE Compania de Electricidad of the Dominican Republic CESPM Compania de Electricidad de San Pedro de Macoris of the Dominican

Republic CfD Contract for Differences CGM Competitive Generation Market CO2 Carbon dioxide DOE Department of Energy DOI Department of Immigration DOLISA Department of Labor, War Invalids and Social Affairs ECA Energy Conversion Agreement EDF Electricite de France EGAT Electricity Generating Authority of Thailand EIA Environmental impact assessment EL Electricity Law EMA Energy Market Authority of Singapore EMS Energy Management System EPC Engineering, Procurement and Construction ERAV Electricity Regulatory Authority of Vietnam EVN Electricity of Vietnam FDP Field development plan FIDIC Fédération Internationale Des Ingénieurs-Conseils, International Federation

of Consulting Engineers FRC Full retail competition FSA Fuel supply agreement FX Foreign Exchange GOV Government of Vietnam GMP Gas master plan GPA Government Procurement Agreement GSA Gas sales agreement

Abbreviations…

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GSPA Gas sales and purchase agreement GT Gas turbine GW Gigawatt IBWG Inter-Branch Working Group ICAP Installed Capacity, used in reference to capacity assurance schemes ICB International Competitive Bidding IFC International Finance Corporation IoE Institute of Energy IP Institute of Petroleum IPP Independent Power Producer. Unless otherwise indicated, this report uses

IPP to mean grid-connected generation that is not owned by EVN and is not a BOT.

IPPA Independent Power Producer Administrator in the Philippines JBIC Japan Bank for International Cooperation JOA Joint operating agreement JOC Joint operating company km Kilometer kV Kilovolt kW Kilowatt kWh Kilowatt-hour LDC Load duration curve LFI Law on Foreign Investment LNG Liquefied natural gas LPG Liquefied petroleum gas LRMC Long Run Marginal Cost LTMC Long-term maintenance contract MCP Market clearing price MFO Medium fuel oil MIGA Multilateral Investment Guarantee Agency MO Market Operator MOC Ministry of Construction MONRE Ministry of Natural Resources and Environment MOIT Ministry of Industry and Trade MPI Ministry of Planning and Investment MW Megawatts MWh Megawatt-hour NEMS National Electricity Market of Singapore NPC National Power Corporation of Philippines NPV Net Present Value O&M Operations and Maintenance PC Power Company, an EVN unit that conducts distribution and retail PDC Price duration curve PJM Pennsylvania-Jersey-Maryland power system PMP Power master plan PMP6 Sixth Power Master Plan

Abbreviations…

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PLN Perusahaan Listrik Negara, the State Electricity Company of Indonesia PPA Power Purchase Agreement PPC Provincial People’s Committee PRG Partial Risk Guarantee PSALM Power Sector Assets and Liabilities Management Company of the Philippines PSC Production sharing contract PV Gas PetroVietnam Gas, a subsidiary of PVN PVN PetroVietnam RAP Resettlement Action Plan RFP Request for Proposal S&P Standard and Poor’s SB Single buyer SBV State Bank of Vietnam SGD Singapore dollar SGMP Southern Gas Master Plan SO System Operator SOE State-owned Enterprise SRMC Short run marginal cost TAGP Trans-Asia Gas Pipeline TECO Tri Energy Company TEPCO Tokyo Electric Power Company TO Transmission operator TNO Transmission network owners UDEC Urban Development Construction Company UNCITRAL United Nations Commission on International Trade and Law USD United States dollar VC Vesting contract VfM Value for Money VND Vietnam dong VoLL Value of lost load WACC Weighted Average Cost of Capital WCM Wholesale Competitive Market WESM Wholesale Electricity Spot Market of the Philippines WHP Wellhead platform WTO World Trade Organisation

Other words or phrases:

BOT Contract: The contract between a BOT and GOV describing their mutual rights and obligations. The BOT Contract exists in addition to a PPA. In other countries, BOT Contracts may be referred to as “concession agreements” or “implementation agreements”.

Master plan: The power sector plan stipulated under the Electricity Law, which as currently formulated identifies, among other things, defines the generation expansion plan, the ownership modality of new plants, and in the case of BOTs, whether they are competitively procured or unsolicited.

Abbreviations…

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Offtaker: the purchaser of bulk power under a PPA

Project Contract: Another name for the BOT Contract.

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EXECUTIVE SUMMARY ON COORDINATION OF GAS & POWER PL ANNING

Introduction

Over the past decade, Vietnam has experienced some of the fastest power demand growth in the world. To ensure future generation capacity needs are fulfilled, the Government of Vietnam (GOV) envisions an increasing role for independent power producers (IPPs) and build-operate-transfer (BOT) generation projects. During the period 2011 – 2015, between 8,225 and 14,675 MW of new BOT capacity is expected to be commissioned. A large proportion of the new BOT and IPP plants are to be gas fuelled.

The GOV is simultaneously introducing a power market in phases. The principal stages of the market are:

• 2005 through 2008: A pilot internal market within EVN

• 20091 through 2014: A complete Competitive Generation Market (CGM)

• 2015 through 2016: A pilot Wholesale Competitive Market (WCM)

• 2016 through 2022: The complete WCM

• 2023 through 2024: A pilot market for Full Retail Competition (FRC)

• 2024 and beyond: A complete FRC

This assignment is concerned with BOTs, specifically:

• How they can be most effectively integrated into the evolving power market

• How they should be competitively tendered, and

• More generally, how development of thermal power generation can be coordinated with gas development.

This Executive Summary covers all these items, and the remaining portion of this Volume 1 report presents the findings on the last item. Findings on the first two items are presented in Volume 2.

Most Vietnamese gas production is used for power generation, and gas-fired generation represents a sizable portion of total generation. Consequently, optimal development of one sector depends strongly on the other, particularly since both sectors are subject to Government master planning. However, changes in the master planning process have not kept up with the liberalization occurring in the electricity sector, nor is the gas sector changing in fundamental ways that the electricity sector is, impeding planning coordination between these two sectors.

1 The Electricity Regulatory Authority of Vietnam (ERAV) now expects that the CGM will commence in 2010, one year later than originally envisioned.

Executive Summary on Coordination of Gas & Power Planning…

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The purpose of this Volume 1 report is to explore how development of the gas and electricity sectors can be better coordinated within this dynamic environment. In particular, this report aims to:

• Briefly outline the gas resources and developments in Vietnam, and describe the current institutional arrangements for the gas sector and how they relate to overall gas and electricity planning

• Identify key gas sector issues as they relate to gas and electricity sector planning in general and BOT electricity generation project development in particular.

• Identify the development and operating risks for a BOT electricity generation project developer and suggest mitigation measures for these risks.

• Suggest mechanisms to improve gas and electricity planning coordination

• Present a case study that illustrates some of the gas and electricity planning issues and how these would be addressed if the suggested planning changes were implemented

This assignment has been undertaken during a period of unprecedented change. In Vietnam, the electricity sector is part way through the complex process of introducing a market. In global world energy markets, oil prices have risen to USD140/bbl and then dropped to below USD50/bbl in less than a year. In global financial markets, the world is facing the deepest recession in decades, the banking sector is in turmoil, and the availability of credit has shrunk dramatically. It is difficult for any planning process to cope with these massive worldwide shifts and fully capture the expected economic impact on a rapidly growing economy such as Vietnam. As a result of these events, some data such as electricity load forecasts and the least-cost ranking of generating plant would likely differ if they were updated. Nonetheless, the fundamental observations and recommendations of this report remain relevant despite (or perhaps because of) the volatility of international markets. And while recent economic volatility complicates planning, it makes it all the more necessary.

Gas Resources and Development

All the major oil and gas fields in Vietnam are offshore in the south of the country. Each gas field development has a dedicated pipeline to shore and has been developed to feed major power generation and fertilizer plant end users, and also supply some smaller industrial customers. There is no gas pipeline interconnection between these developments, but there are plans in PVN’s draft Master Plan for Gas Development in Southern Vietnam (referred to henceforth as the Southern Gas Master Plan, SGMP) for such a pipeline to tie the principal gas supplies together in the future.

The Cuu Long and Nam Con Son Basins

A joint venture was established with Vietsovopetro in 1981 to develop the Bach Ho field and explore surrounding blocks in the Cuu Long basin. Initial oil production from the Bach Ho field commenced in 1986, with the associated gas being flared until the Bach Ho - Dinh Co pipeline and associated onshore treatment facilities were installed. This system also collects gas from the Rang Dong fields, which is piped to the Bach Ho compressor platform for transport to shore. The onshore facilities at Dinh Co include LPG separation, condensate separation, and gas drying.


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The Nam Con Son basin is located South East of the Cuu Long basin. The Dai Hung oil field commenced production in 1994 and gas from the Lan Tay field has been utilised since 2003. Further gas discoveries have been made on neighboring blocks and development plans for these have been approved to ensure a continuing gas supply as the Lan Tay field declines. Gas from the Nam Con Son basin is transported to the gas processing facilities at Dinh Co and the treated gas is mixed with the Bach Ho gas and piped to the Ba Ria power plant, to Phu My for power generation and fertilizer production, and to some major industrial users.

Development of the gas fields in the Bach Ho and Nam Con Son basins required major end-use customer contracts to justify the development costs of the pipelines and other infrastructure. The Bach Ho gas development was easier because much of the offshore infrastructure was in place for oil production with the gas being flared. The initial gas customers for this development were existing power stations that were converted to gas fuel, and an LPG extraction plant. The Phu My power and fertilizer complex was developed as the end use customer for the Nam Con Son fields. This includes the Phu My 2-2 and Phu My 3 BOT generating plants, together with some EVN plant and the PVN fertilizer plant. The negotiations for the BOT plants were protracted, but the outcome was two large BOT generating plants fuelled by gas that has a falling cost in real terms for the life of the contract. However as new fields are developed to replace the declining fields the Phu My complex will likely face higher gas prices.

The Malay-Tho Chu Basin

The Malay-Tho Chu Basin has a common boundary with Cambodia, Malaysia and Thailand. A production sharing agreement was signed with Talisman Malaysia in 1993 to develop the PM3-CAA block. Oil production commenced in 1997 and gas production in 2003. Vietnam is entitled to 50% of the gas produced from these fields. The gas sale and purchase agreement allowed Petronas to receive Vietnam’s share of the gas produced on a refundable basis until the pipeline and the Ca Mau generating plants were completed.

The pipeline and the PVN-owned Ca Mau 1 and 2 IPP power stations have now been completed and a fertilizer plant is under construction. The gas price is set at 0.46 x the USD price of Medium Fuel Oil (MFO) on a calorific basis, which means that the gas price rises directly as oil prices rise. With the very rapid rise in oil prices in the first half of 2008 (to around USD140/bbl), the price of this gas rose rapidly, resulting in reduced plant dispatch. The CGM design incorporates technology-specific bid caps based on domestic fuel use. At the time this report was prepared it was not clear whether or how the CGM bid caps would be relaxed or adjusted for plants like Ca Mau that are exposed to volatile international fuel prices.

Blocks B, 48/95 and 52/97

Block B and associated fields are similar to other Gulf of Thailand fields, with small pockets of dry gas containing relatively high inerts. Production sharing agreements were signed with Unocal (now Chevron) for Blocks B and 48/95 in 1996 and Block 52/97 in 1999. During exploration, a number of gas fields were discovered and the reserves estimates have been approved by the Government. The field development plan is to bring the gas ashore for a power generation complex to be built at O Mon (2670 MW), the Tra Noc power plant (183 MW) and industrial customers. The development plan calls for up to 31 wellhead platforms and approximately 450–500 wells, with consequently high field development costs. Chevron and PVN have been negotiating a gas sale and purchase agreement for some years, and until this is completed the contracts for the pipeline and the larger power stations cannot be awarded.


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Current Institutional Arrangements in Vietnam’s Gas Sector

Legislation & Contracting

The Vietnamese gas market is still in its infancy. Legislative efforts and resources have been focused on oil-related matters. Various provisions of the Petroleum Law (as revised in 2000 and 2008) and Decree 48/2000 are relevant to gas, but there is no comprehensive legislative or regulatory framework. A number of decrees to clarify gas legislation are under preparation.

Oil and gas development in Vietnam has been undertaken under production sharing contracts (PSC) between PetroVietnam (PVN) and an international partner who is the operator for the block and fully funds the exploration work. In the event of a discovery PVN has the right to participate in the development phase up to a prescribed percentage, and the right to purchase all of the gas produced that is landed in Vietnam. The form of the PSC has been amended in recent years to more closely resemble the joint operating arrangements used in other countries.

The Ministry of Industry and Trade

The Ministry of Industry and Trade (MOIT) manages the state’s interests in the industrial sector, including energy. The two departments affecting gas and electricity are the Energy and Petroleum Department and the Electricity Regulatory Authority of Vietnam (ERAV). The Ministry has overall control of the gas and electricity planning processes, develops strategy for the sector for Government approval, helps develop draft legislation to implement that strategy and manages tariff setting. The Electricity Law and the Petroleum Law provide for preparation of national electricity and gas development plans, which are referred to here as Power Master Plans (PMPs) and Gas Master Plans (GMPs).

The inter-relationships between MOIT and the other participants in the electricity and gas industries are shown in Exhibits 1 and 2 below.

Exhibit 1: Electricity Industry Institutional Rela tionships

MOIT Energy and Petroleum Department

Generators DistributionCompanies

EndUsers

EVNTransmission

ERAV

Electricity flow

EVN Single Buyer

Sellelectricity

Sellselectricity

Managesthrough

PMPprocess

Regulation

Develops retail tariffs for approval by Minister, MOIT

ManagesMarketDevelopment

These include- EVN- IPPs (including PVN)- BOTs

Prime Minister

Approves PMP


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Exhibit 2: Gas Industry Institutional Relationship s


PVNChevronTalismanBP etc

PVNWholesale

Pipeline CompaniesPSCs, PVN

Non-GenerationEnd Users

All gassales

Gas flow

PVNLPG PlantElectricity

LPG

Manages through blockoffers, reserves, FDP,GSPAGSA approval

Regulates gasretail prices

These include- EVN- BOTs- IPPs- Industrial Cogen

PSCPartners

ElectricityGenerators

PSCPartners

Prime Minister

Approves reserves, FDPs, GMP

The Electricity Industry

Electricity of Vietnam (EVN) is the state owned corporation that operates in the areas of generation, transmission, distribution and retailing of electricity. In 2006 (the latest statistics that were available) EVN had 9,418 MW of generation assets including hydro, coal fuelled thermal, and oil and gas fuelled thermal power stations. In addition to the EVN owned generating plant, there were 2,939 MW of IPP, BOT and cogeneration stations. EVN also owns the national transmission system, most of the country’s distribution networks, and retails electricity to end use customers. Total system electricity sales in 2006 were 51,530 GWh. The load growth over the period 2000 – 2006 has been in the range 13 – 17% per year, and due to delays in developing new generating plant there are frequent power cuts during peak demand periods.

The Gas Industry

The Vietnam Oil and Gas Corporation (PetroVietnam or PVN), was established to undertake oil and gas exploration, development and production. PVN is an integrated oil and gas company with interests in exploration, oil and gas field development, oil industry services, consulting, gas transport and supply, electricity generation, fertilizer production, petrochemicals, property, finance and insurance. PVN purchases all gas produced and on-sells this to their own subsidiaries or other end users. The gas industry has not yet started to develop a competitive market and there is no formal regulation of the industry. However legislation is being developed that might specifically allow the other production sharing partners in a development to sell domestically a proportion of the gas produced from their fields, though it would be several years at the earliest before such legislation would be enacted.


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The Electricity Master Plan

The electricity planning process is well established in Vietnam. The Sixth Power Master Plan (PMP6) covering the period 2006-2015 has been approved by the Government and the seventh master plan is under preparation. The current process for producing the PMP by MOIT is shown in the flow diagram in Exhibit 3, but this may change as part of the introduction of the Competitive Generation Market (CGM). MOIT appoints an EVN subsidiary, the Institute of Energy (IoE), to prepare the plan.

Exhibit 3: Flow Diagram of the Current PMP Process

MOITAppoints IoE

IoE PreparesCost Data

Bases

PMApproves

PMP

MOITDesignates

DevelopmentModality

Least CostGeneration

Plan

Fuel AvailabilityAnd Prices

IoE PreparesDraft PMP

Hydro Plans

IoE PreparesDemandForecast

RegionalElectricity

Plans

IoE PreparesFinal PMP

Information fromthe GMP

Information fromCoal MP

MOIT ReviewsFinal PMP

Having established a national demand forecast, a fuel availability and cost data base, a plant cost data base and an operating and maintenance cost data base, IoE determines the optimum generation expansion plan using a least-cost generation expansion planning program. IoE then submits the analysis and resulting list of new generating plant required for system growth to MOIT, which then determines the development modality for each plant, i.e. whether it will be developed as a BOT, IPP or under EVN. The IoE finalizes the draft plan accordingly, and submits it to MOIT, which ensures that it meets the government’s energy strategy and forwards it to the Prime Minister for approval.

As noted previously, PMP6 plans for commissioning of between 8,225 and 14,675 MW of new BOT capacity over the period from 2011 to 2015. There is a range of future BOT capacity as some plants have been identified in the plan as IPP or BOT developments.

The Gas Master Plan

Gas planning in Vietnam commenced relatively recently with the preparation of a draft Southern Gas Master Plan (SGMP) by PVN in 2005. This will form the basis for the national Gas Master Plan (GMP) that is under preparation. The process for the preparation of the GMP is shown in the flow chart in Exhibit 4 below. Just as MOIT appoints IoE to prepare the PMP, MOIT appoints the Institute of Petroleum (IP), a PVN subsidiary, to prepare the GMP.


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Exhibit 4: Flow Diagram of GMP Processes

MOITAppoints IP

IP PreparesGas Supply

Forecast

PMApproves

GMP

MOITReviews Draft

GMP

IP PreparesDraft GMP

IP PreparesGas Demand

Forecast

MOIT ReviewsFinal GMP

PSC ReservesReports

PSC FieldDevelopment

Plans

Information fromthe draft or approved PMP

IP PreparesFinal GMP

Information to draft PMP

The draft SGMP assesses the demand for gas in the southern part of the country, assesses the gas reserves that are available and matches supply and demand. It also briefly looks at a possible pipeline linking neighboring countries and the importation of liquefied natural gas (LNG). A similar process but on a national basis will be used when the Institute of Petroleum (IP) prepares the draft GMP. On completion of the draft GMP it will be submitted to MOIT to ensure that it meets the government’s energy strategy, revised as necessary, and MOIT will submit the final plan to the Prime Minister for approval. Since the SGMP is at a draft stage, details are not cited in this report.

In the draft SGMP, a sector-by-sector gas demand forecast shows that in 2009 the total demand will be 16.55 bcm/year, of which 20% will be used for fertilizer production, industrial customers and small end users, and the remaining 80% used for electricity generation. On the supply side, existing developed fields, those under development and those discovered but not yet at the development stage are used to formulate scenarios for firm gas supply, probable gas supply and possible gas supply, and these are matched to the demand forecasts. To meet the forecast demand for gas for electricity generation will require the reserves of all the recent discoveries in the South East area and a rapid program of field development. For the South West area the supply/demand position is better, with the forecast demand being met by supply from Malay-Cho Thu and Block B and 52/97 developments. As alternatives, the Trans Asia Gas Pipeline to link the gas producing and gas consuming countries in the area and LNG importing were assessed but not considered viable at this time. An onshore pipeline linking the three gas producing areas and pipelines to further industrial customers are also planned.

Gas and Electricity Master Planning Co-ordination

The PMP process is well established but the GMP process is only in the early stages of development and application. For the GMP and PMP processes to be successful they must be undertaken together with interaction between IoE and IP, and with the new


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electricity market planning processes being developed by ERAV. When PMP6 was prepared the GMP processes had not commenced and the information provided for fuel pricing by PVN reflected historical pricing from fields like Nam Con Son rather than pricing from future developments like Block B, which is likely to be significantly higher. Some of the projects identified by the least-cost generation planning model have not advanced principally due to continuing fuel price negotiations. This highlights the need for more coordination between the gas and electricity master planning processes and the need for the PMP and GMP to be updated on a regular basis.

Key Gas Sector Issues

A number of key gas sector issues that affect gas and electricity planning coordination and thereby BOT project implementation have been identified as follows.

National Energy Strategy

By Decision No 1855/QD-TTg dated 27 December 2007, the Prime Minister approved the National Strategy of Energy Development up to 2020, Vision to 2050 that outlines in broad terms the government’s strategy and vision for energy development. This is a high-level document that does not quantify specific targets for the energy sector. A “Quantified Energy Strategy Report” should be prepared that would cover issues such as:

• Demand for energy across all sectors of the economy

• Indigenous and imported energy resources to meet these demands

• Prioritization of energy technologies

• Energy conservation and efficiency

• Energy security

• Environmental considerations, sustainability, and carbon impacts

• Accessibility and social impacts

• Government funding and support across fuels and sectors

• Energy pricing and policy across fuels and sectors

This would require close coordination with the PMP and GMP processes and would provide a robust economic model of the country’s energy industry and of the effect of international energy prices on the local economy.

Stakeholder Participation in the Planning Process

During country visits for this report it was apparent that whilst those who are responsible for the preparation of the GMP and PMP have tried to seek the views of all stakeholders in the development process, further consultation and discussion with the private sector would be highly valuable. Particularly where foreign capital is required for the new investments, such as typically occurs with BOT generation projects and gas field development, it is essential that the developers and their financiers have confidence in the whole of the energy industry, and that planning efforts take into account foreign investor perspectives and suggestions from the outset.


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Gas Pricing

Gas pricing in Vietnam has tended to be cost driven rather than market driven and the prices have been low by world standards. The Blocks B, 48/95 and 52/97 development is a high cost development relative to earlier developments such as Nam Con Son. The field developers and PVN as gas wholesaler have been in negotiations for some years to reach agreement on a gas price that will allow the field development and associated power stations to proceed. Such upstream delays retard development along the entire gas-to-power value chain.

In the absence of a gas market, the price for gas for electricity generation can be set in a number of ways:

• Cost of production

• Value for alternative uses

• Cost of generation from alternative fuels (netback)

• Negotiation

A cost of production regime is a regulated regime where the developers submit the costs for the development and are entitled to earn a regulated rate of return on those costs. To establish gas pricing from the value for alternative uses a model could be developed to value the gas for uses such as fertilizer, methanol or LNG production. In the netback approach, a least-cost generation model sets the upper value of gas for electricity generation by modeling coal fuelled generating plant. This gas price can be determined from the costs for a CCGT plant that produces electricity at the same cost as the coal plant. Negotiation is the process currently used to set gas prices in Vietnam, and all parties to this negotiation will have undertaken their own analysis using one or more of the above methodologies and will have a view on what the gas price should be.

In an open and competitive market the gas price will rise to the value of the gas for alternative uses or to the price where it is cheaper to use an alternative fuel (usually coal) for thermal generating plant.

Pipeline Gas Specifications

The gas from the four fields that have been developed or are in development is of differing quality and composition, and there is no national gas quality standard. If there is to be interconnection of the major gas sources then a national gas standard must be established, gas treatment plants built, and all end-users that are currently not being supplied with national pipeline standard gas (other than some large end-users who may wish to stay on untreated gas direct supplied by one field) will have to convert their equipment to the new gas standard.

Updating the Master Plans

The GMP and the PMP are prepared under a five year planning cycle. If the GMP and PMP are to maintain their relevance as the key planning documents for the industry, then following government approval of the plans there should be a coordinated annual review program that produces updated plans or addendum documents that details the changes to the plans.


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Gas Industry Restructuring

The electricity industry is undergoing a series of major structural changes to introduce a competitive electricity market, but there is no such program for the gas industry. To fully implement a competitive electricity market, structural reform of the gas industry is required to separate the monopoly sectors of the industry, such as transmission and distribution, from the potentially competitive sectors, such as generation and retailing. Gas system open access and the ability for gas producers and gas-fired generators to negotiate fuel supply directly can contribute to optimal investment and resource utilization in both the electricity and gas sectors, as well as timely project implementation. Regulations regarding cross ownership, for example of a generating plant by a gas transmission company, should also be considered.

BOT Development Risks and Mitigation

The Gas to Electricity Value Chain

Gas-fired electricity projects in Vietnam to date have been field specific, which is quite different to developing a gas field or a power station in an environment where there is a deep gas market with access to a network of gas pipelines and a range of gas purchasers. In a deep gas market, a BOT generation project developer is able to develop the generation project without exposure to the upstream gas field development or gas transmission development risks. In the field-specific development environment in Vietnam a complex web of interlinked contracts must be finalized. If any one of the contracts along the gas to electricity value chain fails, then the BOT developer is exposed to risks. The gas-to-electricity value chain and its associated contracts for a BOT development are shown in Exhibit 5.

Exhibit 5: Gas and Electricity Value Chain Contrac ts

Gas FieldDevelopment

GasTransmission

PowerStation

ElectricityTransmission

ElectricityPurchaser(s)

Energy Flow

GasWholesaler

GTA

PPA

TCA

GSAGSPA

Field DevelopmentContracts

Pipe Supply &Laying Contract

Power StationConstructionContract

TransmissionConstructionContract

FinancingAgreements

GSPA – Gas Sale and Purchase AgreementGSA – Gas Sales AgreementGTA – Gas Transport AgreementPPA – Power Purchase AgreementTCA – Transmission Connection Agreement

BOTAgreement


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Risks and Risk Mitigation for the BOT Developer

The flow chart in Exhibit 6 identifies where key development risks occur throughout the development process. All of these must be addressed for a successful project.

This report assesses the impacts of each of these risks on a BOT project, and suggests mitigation measures. Some of these risks will be mitigated by the work that ERAV is undertaking, but until the detail of the new regime is promulgated the institutional uncertainty increases the risk for the BOT developers.

Exhibit 6: BOT Development Risks

MOITProcures

BOT

NegotiateTransmissionConnection Agreement

NegotiateBOT

Agreement

NegotiateGas SupplyAgreement

NegotiatePPA

PowerPlant

Developed

NegotiateGas Transport

Agreement

EPCContract

TransmissionConnectionDeveloped

GasFieldDeveloped

GasTransmissionDeveloped

BOTCommercialOperation

1

Risks

2

3

4

5

6 10

9

7

8

Risks 5, 6, 9 and 10 are gas-specific risks for BOTs, while risks 1, 2, 3, 4, 7 and 8 are fuel-independent BOT development risks.

Institutional Measures to Reduce BOT Development Ri sk

There are a number of ways that the government (through MOIT) can reduce the risks in the BOT development process. The first recommendation is to build confidence in the energy planning processes.

Recommendation 1

Develop a robust process of gas and electricity planning to ensure that the projects that proceed through to BOT development are viable in the electricity and gas markets or industry structures that prevail at that time.

The second recommendation relates to the BOT tender documents for a BOT project.


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Recommendation 2

Spend the necessary time and effort before the BOT tender documents are issued to prepare a comprehensive set of draft contract documents covering the BOT contract, GSA, PPA, GTA and TCA.

Mechanisms to Improve Gas and Electricity Planning Coordination

Gas and Electricity Planning in an Idealized Market

The report notes the conditions that would exist in an ideal energy market. These conditions do not exist in Vietnam, where a number of constraints have been identified, particularly related to the vertically-integrated gas industry. In order for gas and electricity planning coordination to improve, progress needs to be made on removing some of the constraints identified. The following recommendations are made to help improve gas and electricity planning coordination.

Updating the GMP

To be an effective tool for managing development, the GMP must be prepared and approved quickly, and a process of annual review and update established. This annual update should address such things as changes in reserves, project timing, gas pricing and forecast demand as a result of further information that has become available in the preceding 12 months, and should update the key tables, charts and development programs. The results of the annual review should be published as an addendum to the GMP.

Recommendation 3

That the GMP should be completed promptly, a process of annual review and update established, and that the results of the annual review should be published as an addendum to the GMP.

Gas Price Formation

The quality of the information passed from the gas planning process to the electricity planning process is critical for success of the electricity least-cost generation expansion planning process. The practice of forecasting prices on the basis of earlier developments has resulted in an underestimation of the gas cost, causing delays to projects and potentially exacerbating shortages of generation in the electricity market. Gas price formation for the purposes of electricity planning should be a two stage process, with an initial gas price based on an expected rate of return on field development costs being prepared off the outline field development plan, and an updated price estimated when the final field development plan is prepared. These initial prices will later be replaced with the actual negotiated contract gas price.

Recommendation 4

That for new field developments a two-stage gas price formation process driven off the outline field development plan and the final field development plan be utilized to provide more accurate gas price information to the gas and electricity master planning process. This price data, and the associated planning, should be updated annually.


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Stakeholder Consultation

There are many stakeholders in the gas and electricity markets in Vietnam, and for the GMP and PMP processes to be effective all of these stakeholders must be consulted. This consultation could take the form of a series of workshops where the policy parameters and initial results of the planning are presented, and stakeholders given an opportunity to provide feedback and suggestions.

Recommendation 5

That there be greater stakeholder consultation in the preparation of the GMP and the PMP, and that a formal structure of stakeholder consultation through workshops be implemented.


If there is to be greater competition introduced to the electricity industry involving gas-fired generation, then changes will be required in the gas industry to allow greater competition and an open access transmission regime. To help formulate policy in the area of gas industry reform a road map is required, similar to the road map that was prepared for introducing competition to the electricity industry. This roadmap should also address the issues of a national pipeline gas standard, interconnecting the producing fields and the option of a gas pool price mechanism.

Recommendation 6

That a road map be prepared for the introduction of greater competition to the gas industry in Vietnam, with a view towards accelerating gas production and utilization and contributing to the successful operation of the electricity market.

Electricity Load Forecasting

Because these forecasts underpin the large capital expenditure program for electricity generating plant, gas field development and electricity transmission and distribution systems, it is essential that they be as accurate as possible. Because of the impact of the forecasts on the whole gas and electricity sectors, an independent expert review should be undertaken to benchmark the process going forward. This is particularly important since the institute that undertakes the forecasts, the Institute of Energy, is a subsidiary of the major player in the sector, EVN.

Recommendation 7

That an independent expert review of the electricity load forecasts be undertaken to establish a benchmark forecast for the ongoing annual PMP review process.

Updating the PMP

As for the GMP, the PMP should be updated annually.

Recommendation 8

That a process of annual review and update is established for the PMP, and that the results of the annual review should be published as an addendum to the PMP.


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Least Cost Generation Planning

At the core of the PMP is a least cost generation expansion plan. A critical input to this process is the fuel cost. The fuel input costs used in PMP6 were lower than the actual prices necessary to facilitate development of new fields. This may have skewed the results of the least-cost plan, may have contributed to unrealistic expectations that have complicated fuel price negotiations, and in any case has not provided policy makers and government planners with information needed for better decision-making. The two-stage gas price formation process outlined above with timely incorporation into the PMP updates should ensure that the list of projects to be developed reflects the prevailing market conditions. GMP and PMP processes should be updated in an iterative manner, with each plan update using the most recent data or outputs from the other.

Recommendation 9

That the output from the two-stage gas price formation process recommended for the GMP be used as the input gas price for the PMP development process (including updates) and CGM least-cost planning procedure until the negotiated gas contract prices are known.

Electricity Price Discovery

The PMP process produces a least cost development plan for generation expansion, but doesn’t consider the impact of the cost of generation from the selected stations on the wholesale price for electricity. The PMP should be extended to include a section on the wholesale price profile that will result from the least cost development plan.

Recommendation 10

That the PMP process be extended to cover the development of a forward price curve for wholesale electricity in conjunction with a market simulation model that should be developed and used by ERAV.

Case Study – The O Mon – Blocks B, 52/97 and 48/95 Development

This case study looks at the development process for the O Mon – Blocks B, 52/97 and 48/95 development and serves to illustrate how the present master planning processes are working and how they can be enhanced to move from a static planning process to a more dynamic process. The final part of the case study looks at international experience, particularly Thailand and Indonesia, as they have experienced many of the problems that Vietnam is now experiencing.

The Existing Planning Process

The electricity market in Vietnam is moving through a period of change from a fully centrally planned model towards a regulated competitive model. This process is continually evolving as the CGM is introduced, and the process will be further enhanced once the GMP processes are fully established. The existing planning processes can be characterized as a series of silos with limited coordination between the silos and a lack of regular updating. The process for the O Mon Development is illustrated in Exhibit 7 below, which resulted in a protracted GSPA negotiation with all the O Mon generating plants slipping behind schedule.


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Exhibit 7: Current Status of GMP and PMP Planning Process

The Proposed Planning Process

If the recommendations above are implemented the GMP and PMP planning processes change from static to dynamic, with annual updates of the plans. The two stage gas price discovery process will determine if there is insufficient value along the gas to power value chain for all participants. This dynamic planning process is illustrated in Exhibit 8 below.

Exhibit 8: The Enhanced GMP and PMP Planning Proce ss

GSPA, GSA, PPA, GTA, TCA, Negotiations

Discovery

PM Approval

Final ReservesEstimate

Final FieldDevelopment Plan

PM Approval

Outline FieldDevelopment Plan

Initial ReservesEstimate

MOIT Contracts IP

Draft GMP

Demand Forecast

MOIT Contracts IE

Least CostGeneration Model

Draft PMP

MOIT Review

PM Approval

Fuel, Capitaland O&M Databases

Demand Forecast

Gas Reserves Information

Gas Field Development GMP Process PMP Process

MOIT Approval

PM Approval

Supply Forecast

Electricity gas demand information

Gas Price Information


Discovery

PM Approval



PM Approval



MOIT Contracts IP

Draft SGMP Reviewed

Draft SGMP

MOIT Contracts IE


Draft PMP

MOIT Review

PM Approval


Demand Forecast

Gas Reserves Information Gas Price Information



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For a BOT development it is essential that issues around pricing are fully understood and that only projects with a high expectation of success proceed to BOT tender. If the more dynamic planning process had been followed the outcomes for the Block B – O Mon development might have been that:

• O Mon was dropped from (or deferred within) the least-cost development plan and replaced by another gas plant having cheaper gas or a coal plant, or

• The field developers might have sought an alternative higher value use for the gas, or

• O Mon may have retained its position in the least-cost generation development plan, but wholesale electricity prices would be adjusted upwards to accommodate higher cost new generating plants.

International Example - Thailand

Thailand has embarked on a wide ranging reform of the energy sector with the objective of making it more competitive and transparent. Like Vietnam, the energy sector is dominated by the national generation company (EGAT) and the national oil and gas company (PTT), but also relies on IPPs. Thailand is in the process of separating the policy making, regulatory and operational functions in the sector to prevent abuse of monopoly powers, protect the consumers’ interests, and regulate prices. Thailand has conducted two solicitations for bids for IPP projects in 1994 and 2007. The recent bid solicitation used an electronic process with standard form PPA documents and clear evaluation and award procedures.

The latest Power Development Plan (PDP 2007) covering the period 2007 – 2021 was endorsed by Cabinet in June 2007, and a revised plan called PDP 2007 Revision 1 was submitted to NEPC for approval in December 2007. The national load forecast is prepared by the Thailand Load Forecast Sub-Committee and demand is expected to grow at 5.7% per year, down from earlier levels of around 13% per year from 1986 to 1997.

The extensive gas infrastructure and the linking of many different gas fields has allowed PTT to establish a gas pool price, and the gas price for EGAT and the IPPs is the pool price plus 1.75% supply margin plus a fixed transmission tariff. Because PTT is vertically integrated, gas sector planning is internalized.

Lessons from the Thailand Experience

The following lessons are relevant for Vietnam:

• It requires great and sustained political determination to carry through regulatory reform in the energy industry.

• Separation of the functions of policy development, regulation and company operation is important.

• Even if a degree of competition is developed in the energy markets regulation is still required, particularly for the monopoly aspects of the industry. One regulatory authority covering gas and electricity is an effective way of reducing overheads and ensuring that similar regulatory regimes are established for both energy types.

• Open access regimes with regulated published tariffs are required for gas and electricity transmission.


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• The benefits of establishing a national gas quality standard, linking the various gas sources and establishing a gas pool price should be investigated.

• Master Plans should not be fixed, but should be revised as market conditions change.

• An open and participative process is required to develop the load forecast that underpins the PMP.

• With well-prepared standard contracts and fuel and electricity price information a BOT tender process can proceed to signing quickly.

International Example – Indonesia

The oil and gas industry in Indonesia up until 2004 was structured in a very similar way to that in Vietnam. For example, the Indonesian state oil and gas company, Pertamina, played a very similar role to PVN.

The Indonesian Oil and Gas Law No 22/20012 completely restructured the oil and gas industry. Pertamina is now treated the same way as any other oil and gas company under the PSC regime, and foreign oil and gas companies are no longer required to partner with Pertamina under a PSC.

A new government body, BP Migas, was established to be the counterparty under the production sharing contracts and to sign and supervise the PSCs. A new regulator for the downstream industry, BPH Migas, was established to set pipeline tariffs and retail tariffs for small customers. The Director General of Oil and Gas now develops policy, standards and processes for the oil and gas sector, and offers new exploration blocks and manages the upstream data.

Domestic gas sales are now contracted on a direct basis between the gas producer and the end-use customer. A Domestic Market Obligation has been introduced to ensure that gas is available for the domestic market rather than all of it being exported as LNG or via pipeline.

These gas industry reforms have resulted in rising gas prices, but consumption has grown greatly as the reforms have eliminated or reduced bottlenecks to availability.

Lessons from the Indonesia Experience

Indonesia has made considerable progress with the reform of their gas industry. The following lessons are relevant for Vietnam:

• It is possible to reform a county’s gas industry even when it is controlled by a powerful monopoly. Such reform can result in greater benefits for the entire economy.

• Gas consumption can increase greatly even if gas prices rise, since higher prices may be necessary to increase availability.

2 Though the law was enacted in 2001, implementing regulations and fundamental changes in the industry did not occur immediately. It is probably more accurate to view 2004 as the year in which these reforms were effective.


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• Large end-use customers and gas producers both benefit from direct negotiations for gas supply in terms of availability, timeliness and price.

Executive Summary on BOT Tendering & Market Integration…

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EXECUTIVE SUMMARY ON BOT TENDERING & MARKET INTEGRA TION

ES.1 Introduction

As described in the Executive Summary on Coordination of Gas & Power Planning, Vietnam is introducing a power market while simultaneously seeking a greater role for BOT generation projects to meet growing demand. This assignment is concerned with BOTs, specifically:

• How they can be most effectively integrated into the evolving power market

• How they should be competitively tendered, and

• More generally, how development of thermal power generation can be coordinated with gas development.

This Executive Summary addresses the first two topics, which are covered in full in Volume 2 of this report. In particular, the work on tendering and market integration aims to:

• Develop and evaluate options for contracting BOTs and subsequently integrating them into the market. The proposed mechanisms must accommodate BOTs in both the CGM and WCM, since the lifetime of these plants may span both of these markets. Any mechanism developed for the WCM will also apply for the FRC. For the purposes of BOT integration, the FRC is no different from the WCM.

• Describe and demonstrate the functionality of a model to assess the impact of these BOT contracting options, particularly with respect to stranded costs.

• Prepare a conceptual framework for competitive tendering of BOTs, consistent with the selected market integration mechanisms (though not dependent on it).

• Draft an Instruction for issuance by the Ministry of Industry and Trade (MOIT) that stipulates the guidelines, standards and general procedures to be applied for the implementation of the conceptual framework for thermal generation BOTs, in accordance with the broader BOT Decree and subject to the Ministry of Planning & Investment (MPI) circular on BOT implementation currently under preparation.

ES.2 The Need for a Market Integration Mechanism

Vietnam has two existing thermal generation BOT projects, Phu My 2.2 and Phu My 3. Like most other BOT or independent power producer (IPP) projects elsewhere in the world that sell power to a vertically-integrated utility operating as a monopoly, these projects sell power to EVN under a traditional two-part power purchase agreement (PPA). Other BOT project currently under development in Vietnam (Vinh Tan 1, Mong Duong 2, and Nghi Son 2) will also rely on a traditional two-part PPA.

These are “two-part” PPAs because they pay the BOT a fixed component plus a variable component. The fixed component is a fee paid per MW of capacity based on plant availability that covers all plant fixed costs, including debt service, fixed operations and maintenance (O&M), and equity returns. The variable component pays for the cost of fuel and variable O&M costs. Fuel costs are passed-through to the offtaker assuming a plant heat rate defined in the PPA.


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Traditional two-part PPAs were developed to facilitate financing of these projects. When selling power to a monopoly, vertically-integrated utility, the BOT has no control over dispatch. The offtaker determines dispatch, and in the longer term determines capacity additions and generation mix. Therefore, investors sought equity returns and debt service independent of whether the plant was actually dispatched, since that was entirely out of their control. The structure of the two-part PPA leaves them largely indifferent as to whether they are dispatched or not. It insulates them from market or regulatory risks that could affect plant dispatch. In effect, it is a contract to provide available capacity that can be dispatched upon request.

Given the changing nature of Vietnam’s power industry, traditional PPAs might not be the best mechanism for contracting future BOT projects. Vietnam is introducing a power market in stages to attract new investment at competitive prices and promote greater efficiencies. The fundamental assumption is that competition in generation and later in retailing will drive prices lower than would be achieved by retaining a vertically-integrated, monopoly industry structure.

Traditional PPAs were not developed for use in a market environment. They cannot be directly integrated into power markets, but can only be superimposed on them. This results in the following issues:

• A BOT contracted under a traditional PPA requires an “agent” (e.g. a BOT Wholesaler) to bid the plant into a market in order to be dispatched. This BOT Wholesaler would be responsible for paying the BOT per the terms of its PPA, and would earn revenue by selling BOT plant output in the market.

• If the power market proceeds as planned, the price of power generated under traditional PPA could be more expensive than the price of electricity in the market, in which case the BOT Wholesaler would lose money. If the revenue that a plant actually receives under a traditional PPA is higher than the amount it would receive if were participating in the market, the difference is referred to as “stranded cost”.

• A traditional PPA puts all risks on the buyer, other than the risks of payment default and plant unavailability.

• Under a traditional PPA, the capacity fee is paid upon availability – even if the plant does not run. Once awarded, the plant does not need to compete with other generation to provide equity returns, so there is little competitive pressure to reduce costs or improve efficiency.

• Any plant efficiencies that the generator achieves while operating under a traditional PPA do not benefit the buyer or consumers. Benefits are retained exclusively by the generator.

The GOV seeks to minimize potential stranded costs that could arise from the BOT program going forward. It also wants to ensure that consumers get the lowest possible electricity prices3. And it wants the transition to a power market to proceed smoothly.

3 A mechanism that minimizes stranded costs does not necessarily minimize electricity prices to consumers. If, for example, a BOT did not hold a PPA but instead participated fully in the market, by definition there would not be any stranded cost. However, if the BOT chose market exposure


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Investors, on the other hand, seek returns commensurate with the risks they take. Investors do not necessarily reject risk, but they must understand, manage and be compensated for it. Uncertainty about how these markets will operate and the revenues they will earn if they participate creates risk for them. Moreover, regardless of how these market risks are addressed, investors will seek a single, creditworthy counterparty to their contract. Counterparty creditworthiness is a particularly acute issue given that Vietnam’s credit rating is below investment grade.

Any mechanism to integrate BOTs into the power market must address these GOV and investor concerns. A market integration mechanism should therefore:

• Minimize stranded cost

• Minimize electricity prices for consumers

• Allow investors returns commensurate with the risks they take

• Provide a creditworthy counterparty for the life of the BOT

• Transition smoothly from one stage of the market to the next

ES.3 Contracting Options

The market integration mechanism will be implemented through the contract that governs the BOT’s sale of power.

The potential for stranded costs would be avoided entirely if BOT projects relied on trading in the market for their revenue streams without any support from the GOV, i.e. they would enter the markets as they are introduced without any pre-existing contract. However, from an investor’s perspective, BOT project enterprises need to contract with an identified and creditworthy power purchaser throughout the life of the BOT. This is because:

• The competitive generation market in Vietnam is in a transitional phase and has not developed to a point where lenders will allow a project enterprise to take market risk. Even if the BOT trades into the market, it will at a minimum require a hedge to secure adequate prices for its output regardless of the direction of the market;

• Lenders will insist that the project enterprise has a counterparty that they can look to for payment performance, regardless of the specific contracting instrument. This should be a single entity for the life of the BOT because of the effort and potential disruption involved in assigning contracts to successors. Investors will give considerable weight to the certainty of a clear GOV vision regarding the identity of the BOT Counterparty;

• In the near- to medium-term, no entity in Vietnam’s electricity sector will be seen by international commercial lenders as strong enough to meet its obligations without a performance guarantee from the GOV;

• Moreover, Vietnam is not yet sufficiently strong in the eyes of most international commercial lenders for them to accept a sovereign guarantee without some form

because of the windfall revenue generated by high market prices, consumers would be worse off than if the BOT had been “locked in” under a traditional PPA.


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of credit enhancement. These include political risk guarantees attached to export credits that finance equipment supply or risk mitigation instruments such as partial risk guarantees offered by multilateral agencies like the World Bank.

Therefore, the market integration mechanism will be implemented through a contract between the BOT and the offtaker, herein called the BOT Counterparty, which will be the beneficiary of a GOV support package.

Two types of contracting instruments are considered:

• A traditional PPA, as discussed above.

• A Contract for Differences (CfD), A CfD is a contract commonly used in markets to manage risk. Under a CfD, the buyer and seller agree a “strike price”. The buyer and seller still participate in the market, but if the market price is greater than the strike price for a designated period, the seller pays the buyer the difference between the two prices for the entire volume contracted during that period. Alternatively, if the market price is less than the strike price, the buyer pays the seller the difference. In this way, uncertainty and hence risk is reduced for both buyers and sellers. Buyers know in advance the costs they will pay, and sellers the revenues they will earn, for the contracted volumes.

This study considers following integration options:

• Option 1: Maintain traditional PPAs: Under this option the BOT is contracted from the outset under a traditional PPA, which is retained for the life of the BOT. When the CGM and WCM markets are introduced the BOT’s capacity is offered into the market by the BOT Counterparty functioning as a BOT Wholesaler. The BOT Counterparty pays the BOT per the terms of the PPA, but earns revenue based on the market price received when it successfully bids the BOT into the market, i.e. when the BOT is dispatched, and through its contracts with buyers in the market. This option insulates the BOT from the market. This option will result in the issues associated with superimposing a traditional PPA on a market, as discussed above.

• Option 2: 1-Step Dynamic Contracting: Under this option, a traditional PPA is used until the WCM is introduced. When the WCM starts, the contract converts to a CfD. This means that the BOT is insulated from the CGM market, but will participate in the WCM market under the contract cover of the CfD.

• Option 3: 2-Step Dynamic Contracting: The BOT is initially contracted under a traditional PPA which converts to a CfD when the CGM is introduced. This contract may continue through the WCM, or may be re-defined once the WCM is introduced. Under this option, the BOT participates in both the CGM and WCM under the cover of CfDs.

Exhibit ES-1 shows implementation of these options over the evolution of the market.


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Exhibit ES-1: Implementation of Contracting Options

The “pre-market” stage is the period prior to the introduction of the CGM. It is necessary to define as part of each option the contracting mechanism that will apply in the absence of a market for two reasons:

• Although the Government’s power market road map stipulates specific dates for each stage of the market, there is likely to be slippage in this schedule. The start of a market is subject to various pre-conditions. For example ERAV now plans for the CGM to start in 2010 since the design is only now being formally adopted, the rules not yet finalized, and the procurement of market infrastructure has not yet begun. Though there is also likely to be slippage in the development and commissioning of BOTs relative to the Government’s power sector master plan, the integration mechanism must anticipate the possibility, however small, that procurement of future BOTs using the integration mechanism might commence prior to introduction of the CGM.

• The Electricity Law stipulates that the Government must regulate the electricity market to ensure safety, stability, and efficiency. Conditions might arise where market operations are suspended. This occurred with EVN’s internal market in 2008 due to dry hydrology, and has also occurred internationally (e.g. California). A “fall-back” contract mechanism is required to provide investors comfort that they will still have contract cover if the market is suspended for any reason.

The mechanism developed here would only apply to BOT projects procured after the mechanism has been formally adopted by the Government. It would not apply to existing BOTs or those currently under development. Given the lead times involved, this framework would apply to BOTs to be commissioned 2014 at the soonest.

ES.4 Assessment of Options

These three options were evaluated against the five criteria described above. To facilitate this evaluation, a model was developed to assess the performance of each option with respect to minimizing stranded costs and electricity prices. It calculates the revenues accruing separately to the BOT and the BOT Counterparty by virtue of the prevailing contract between them, plus the sale of power into the market by either the BOT (under the CfD options) or the BOT Counterparty (under the traditional PPA option). These

Option 1:

Maintain traditional PPAs

Option 2:

Establish 1-step dynamic contracting

Pre-market WCM

Option 3:

Establish 2-step dynamic contracting

CGM

Traditional PPA

WCM CfD

WCM CfDCGM CfD

Traditional PPA

Traditional PPA


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calculations are done for each option at each stage of the market, i.e. pre-market, CGM and WCM.

The model does not forecast stranded costs (since the market rules have not yet been finalized) but rather allows comparison of revenues accruing to each party under various scenarios. These scenarios included whether the market is tight or slack, and whether the BOT is efficient relative to other generators. Losses (negative net revenues) for the BOT Counterparty represent stranded costs, whereas gains (positive net revenues) represent reduced electricity prices compared to what the BOT Counterparty would pay if it were buying electricity unhedged from the market. The option that yields the best results over the broadest set of conditions is preferred.

Based on the analysis performed, 1-step dynamic contracting is preferred, i.e. a traditional PPA applies through the pre-market and CGM stages, but then converts to a CfD upon the WCM trigger event. The principal reasons for this are as follows:

• Because the CGM places tight constraints on bidding and entails a high degree of contracting, use of a traditional PPA during this stage is highly unlikely to result in stranded costs of any significance. Institutionally, the SB can easily take on the role of the BOT Wholesaler.

• However, in the WCM, a CfD can be structured to provide better protection against stranded costs than a traditional PPA by allowing the BOT to take on risk of low market prices in exchange for the opportunity to earn more than it would have earned under a PPA when market prices are high.

Allowing BOT developers to define the amount of risk they are willing to accept is the key to formulating a successful market integration mechanism. Any mechanism that simply ensures that the BOT is made whole as though it were holding a traditional PPA will never result in lower stranded costs than those generated under the traditional PPA. The risk of stranded costs is mitigated by the degree to which the BOT developer accepts the risk of less than full cost recovery. The risk of excessive consumer electricity prices is mitigated by the degree to which the BOT accepts limits on the returns it can achieve. The mechanism must therefore allow the BOT to balance the risk of loss with the potential for gain relative to what it would face under a traditional PPA. A CfD can be structured to achieve this using a “collar” structure.

Implementation of the recommended market integration mechanism requires competitive tendering. Bidders will have to propose not only the cost and performance of the plant, but the amount of fixed cost recovery they would be willing to put at risk during the WCM in exchange for greater upside revenue potential. The tendering process therefore provides the opportunity to let the market speak about acceptable risk/reward trade-offs. Arguably, a BOT selected and developed through such a process cannot result in stranded costs, since the resulting project accepts a degree of market exposure established through a competitive process, albeit one conducted in the face of considerable uncertainty about the behavior of the future markets.

ES.5 Institutional Framework

The GOV acts in a range of different capacities with regard to thermal generation BOT projects. These are:

� Planning;

� Procuring;


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� Contracting (BOT Contract);

� Monitoring; and,

� Offtake (Power Purchase Agreement).

Each of these roles entails a discrete activity that should be managed by clearly designated GOV agencies, acting independently. In this Framework, these entities are referred to as the Planning Authority, the Procuring Authority, the Contracting Authority, the Monitoring Authority and the Offtake Authority. The Offtake Authority is the BOT Counterparty.

The obvious choice of Planning Authority is MOIT because it is currently responsible for the planning function. That said, measures should be taken to minimize conflicts of interest that could arise by having EVN units such as the Institute of Energy (IoE) prepare the master plan for MOIT. It would also be worthwhile to establish greater transparency in the planning process, particularly in terms of how projects are designated as BOTs and how those projects are procured. The least-cost generation planning procedures currently under preparation by the Electricity Regulatory Authority of Vietnam (ERAV) can help address this.

With respect to the Procuring Authority, this could also be MOIT’s role. However, the BOT Decree provides for Inter-Branch Working Groups (IBWGs). It would be appropriate for the thermal generation BOT IBWG to perform the role of Procuring Authority.

The IBWG cannot contract with a project enterprise because it is not, in itself, a legal entity. However, it is appropriate as has been past practice for MOIT to perform the role of Contracting Authority for the BOT Contract on behalf of GOV.

While the major activities relating to procurement would be the responsibility of the Procuring Authority and the Contracting Authority, it is necessary to ensure that each procurement complies with legislative and regulatory requirements. To this end, an independent entity should monitor the development of those requirements and key stages of each procurement. That entity is referred to as the Monitoring Authority. The most appropriate body to perform that role would be ERAV, as the national electricity regulator.

The Offtake Authority is the counterparty to each PPA, referred to elsewhere in this report as the BOT Counterparty. Current arrangements rely on EVN to fulfil this role. While this is sufficient for the pre-market phase, the Offtake Authority should also have the following five characteristics to anticipate the transition to the CGM and WCM:

• Ownership . In principle, the Offtake Authority could be public or privately owned. In practice, however, even if it were privately held it would still need GOV support. (It is highly unlikely a Vietnamese private company could achieve an investment grade rating in the medium term). It is unlikely that the GOV would extend support to a private entity for transactions with another private entity. Moreover, the GOV controls most aspects of the market and can change legislation in a manner that could adversely affect a private Offtake Authority. Investors likely prefer a Government-owned counterparty so that the Government can better appreciate the impacts of any decision on that counterparty. A GOV owned or controlled entity is a logical conclusion;

• Lifetime . As noted above, investors will be considerably more comfortable with a single BOT Counterparty over the lifetime of the BOT, as the beneficiary of a well-defined GOV support package and other credit enhancements as necessary.


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• Credit-worthiness . The Offtake Authority must be able to demonstrate to BOT investors that it will be able to meet its obligations, especially those of a financial nature. It is likely in the medium term that the Offtake Authority could achieve a Standard & Poors’ BB rating if well structured and supported by the GOV. Lenders, however, will expect a BBB rating. To the extent that the Offtake Authority falls short of BBB (as judged by lenders) then GOV support or credit enhancement (as discussed above) would be needed to bolster the Offtake Authority’s payment obligations.

Moreover, while the functions of the Offtake Authority may change as the market evolves, it will need to have a role at each stage that is judged by lenders to be commercially sound, i.e. the Offtake Authority should be a business with good prospects for solvency throughout the evolution of the market, notwithstanding the existence of Government support and other credit enhancements. Government support and credit enhancements only serve as a “last resort” for ensuring payment to the BOT.

During the CGM, the single buyer (SB) is the obvious candidate for the Offtake Authority. However, this will require the SB to transform into solely a BOT Wholesaler in the WCM to preserve the goal of a single counterparty for the life of the BOT. The solvency of the BOT Counterparty at that point will depend on its commercial success as a wholesaler. Further regulatory commitments may be necessary to address investor concerns about counterparty solvency during this stage of the market. One such mechanism could be the application of a universal wires charge to recover BOT Counterparty losses should they occur. Such a mechanism has been used in the Philippines to deal with stranded costs, though the proposed dynamic contracting mechanism stimulates BOTs to take greater risk, thereby minimizing the potential for stranded costs to arise in the first place.

Finally, under the dynamic contracting option, the BOT will depend on both spot market and CfD settlements for revenue during later stages of the market. While the GOV support package and credit enhancements can help ensure that CfD payment obligations by the BOT Counterparty are met, it may be also necessary for the GOV to provide a broader guarantee for market settlement as well. This could perhaps be structured as the BOT Counterparty assuming the obligation for market settlement in the event such payments are not forthcoming.

• Structural relationship to other power sector entit ies . To avoid conflicts of interest, the Offtake Authority should be separate from the following entities:

o The Monitoring Authority, which is charged with designing and supervising the operation of the market. The Offtake Authority will be a participant in the market.

o The Contracting Authority, which is the counterparty to the Project Contract, and therefore an agency of the GOV. In the interests of further commercialization of the sector, the Offtake Authority should be a company, not a Government agency.

o The Planning Authority, since it will determine which projects will be developed as BOTs and hence which will receive Government support, a role best served by a GOV agency rather than a state-owned enterprise (SOE).


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o The system operator (SO) and market operator (MO), since these will determine and instruct dispatch. If the Offtake Authority were affiliated with these entities, there could be potential for biased dispatch for the Offtake Authority’s benefit.

• Prevailing legislation. The Roadmap Decision stipulates that the single buyer will be developed under EVN. By the time the full WCM has been established, it will become an independent company functioning as a normal wholesaler.

There is no existing entity in Vietnam that meets all of these criteria. Consequently, the creation of a new entity is suggested. EVN has taken a step in this direction, having established a power purchasing subsidiary. This also gives the opportunity to set up the entity’s constitution such that its purpose is clear and without conflict with other agencies in the energy sector. Establishing this new Offtake Authority will require assignment of the Phu My PPAs to the new entity, and ring-fencing from other EVN operations to achieve the conditions enumerated above. If the Offtake Authority were to be a new subsidiary of EVN, ring-fencing could be achieved by the Offtake Authority being a limited purpose entity, its assets not being permitted for offering as parent security and restrictions on asset transfers and inter-company advances. These measures are aimed to address concerns that: (a) a healthy subsidiary’s assets may be consolidated with those of its insolvent parent; and (b) the parent will have the ability to cause the subsidiary to file itself into bankruptcy, despite the fact that the subsidiary is not itself experiencing financial difficulty. Taken all together, a new, ring-fenced subsidiary of EVN is the most promising option for serving as the Offtake Authority. This subsidiary would serve as the single buyer in the CGM and evolve into a BOT Wholesaler in the WCM.

ES.6 Tendering Process

This report presents a draft Ministerial Instruction that describes the tendering process for thermal generation BOT projects. The Instruction distinguishes between the authorities described above when considering the various activities that make up the procurement process. This Instruction is intended to be issued by MOIT to guide implementation of the BOT Decree and the broader MPI BOT implementation circular currently under development, specifically for thermal generation BOT projects.

Competitive bidding will help drive BOTs to take on the most risk for the lowest cost. Certainly this is true for procurement of BOTs under a traditional PPA, but benchmarking can be used to help drive down prices offered by a BOT developer under a negotiated procurement. However, given the difficulty of applying benchmarking to the proposed market integration framework (e.g. how much fixed cost should BOTs be expected to put at risk upon introduction of the WCM?), competitive tendering is essential. Though the competitive tendering framework is therefore essential for effective implementation of the market integration framework, the competitive tendering framework can and should be implemented regardless of whether the market integration framework is adopted.

The tendering approach proposed here has been developed based on standardized, internationally accepted approaches including:

• UNIDO Guidelines for Infrastructure Development through Build Operate Transfer (BOT) Projects, 1996;

• OECD Basic Elements of a Law on Project Agreements, 1999-2000;


xxxv


• UNCITRAL Model Legislative Provisions on Privately Financed Infrastructure Projects, 2003 (the “Model Legislative Provisions”).This has been used as a base document for developing the Instruction;

• UNCITRAL Legislative Guide on Privately Financed Infrastructure Projects, 2000 (the “Legislative Guide”), which provide a basis for the Model Legislative Provisions.

• UNCITRAL Model Law on Procurement of Goods, Works and Services, 1994 (the “Model Procurement Law”).

Exhibit ES-2 summarizes the elements of the proposed tendering approach. Details are provided in Chapter 5 of this report, and the draft Ministerial Instruction is presented in Appendix G.

Exhibit ES-2: Elements of the Proposed Procurement Process

Monitoring of Thermal Generation Procurement

Key characteristics of the proposed tendering process that may differ from current practice in Vietnam include the following:

• The tender process begins with the identification of projects and designation of those projects as BOT projects. Investors will be more confident to pursue a project if they know that it is a needed project, and understand why it has been designated for BOT development. While the power sector master planning process relies on least-cost planning


xxxvi


analysis, the designation of projects as BOTs is less clear. The Framework proposes a more transparent method of designating projects for BOT development by comparing the financing capacity of domestic players with expected financing needs, and if needs are greater than resources, designating projects as BOTs if there is no natural fit with domestic players in the industry.

• Once a project has been designated for BOT development, MOIT may wish to conduct a market sounding in which it can get input from potential developers and lenders that can help it design the project. Market soundings may be conducted at various stages during project preparation, for example before the feasibility study is conducted, and again later before bid documents are finalized.

• The thermal generation IBWG should continue to serve as the Procuring Authority, but should be augmented with a permanent secretariat. Moreover, steps should be taken to mitigate potential conflicts of interests for certain members, e.g. various state-enterprises who will participate in the market are also members of the thermal generation IBWG.

• The Framework recommends the use of prequalification, consistent with international guidelines. The disadvantages of prequalification (e.g. the ability to manipulate the process to appoint winners at the outset, the potential to extend procurement time) are outweighed by advantages such as ensuring a reasonable work load for members of the Procurement Authority, encouraging higher quality bids by assuring bidders that they are part of a small pool of candidates, determining at an early stage interest in opportunity, eliminating frivolous interest or unqualified firms at an early stage, etc.

• The Request for Proposals (RFP) should include, in addition to instructions and forms such as a financial proposal template:

� Draft project agreements, including the Project Contract, PPA/CfD, Fuel Supply Agreement, etc.

� Minimum technical requirements of the Thermal Generation BOT Facility;

� The grid code and metering code; and,

� Other project information including draft generation license, feasibility studies, interconnection studies, environmental and social impact studies and so forth.

• A two-envelope approach, in which financial and technical proposals are submitted separately, is recommended. Bidders are first evaluated on whether they pass a technical threshold. Financial proposals are only opened for those that pass. The separate of technical and financial proposals reduces bias in the technical evaluation and reduces the potential for leakage of commercially sensitive information.

• Along these lines, the Framework suggests that the evaluation proceeds as follows:


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� First Stage – Responsiveness. Each proposal is reviewed for completeness and substantial responsiveness according to a test to be specified in the RFP;

� Second Stage – Technical Evaluation. For those proposals that pass the First Stage, Technical Proposals shall be evaluated to establish whether they meet the requirements of the RFP, particularly regarding compliance with the minimum technical specification.

� Third Stage – Financial Evaluation. The Financial Proposals for those bids that pass the Second Stage shall be opened publicly and evaluated. A score shall be calculated based on:

• Price

• Deviations to project agreements, and

• The quality of the financing plan.

� The Bidder that has the lowest evaluated price shall be invited to finalize the Project Contract.

ES.7 Incorporating the Market Integration Mechanis m into the Tendering Framework

The tendering framework incorporates the market integration mechanism through the nature of the PPA and through the tendering and tender evaluation processes as follows:

• The PPA will be formulated as a traditional PPA that converts to a collar CfD upon introduction of the WCM (or an associated event-based trigger, such as one year after introduction of the WCM).

• The PPA could be structured so that either the conversion occurs purely upon achievement of the trigger event, or that once the trigger event occurs conversion is at the discretion of the BOT Counterparty. This might be advantageous to the BOT Counterparty if the market is particularly tight when the trigger occurs and the BOT has stipulated little or no fixed cost at risk.

• The CfD volume will be specified by MOIT at the time of bidding based on its own analysis of the expected dispatch of the BOT. It may be advantageous to establish a volume somewhat below expected dispatch, since analysis performed as part of this study suggests that lower-than-expected dispatch provides better protection across both slack and tight capacity markets.

• Bids will be evaluated at least in large part on the basis of a levelized price to be calculated using assumptions and formulas explicitly stated in the bid documents.

• Key assumptions to be specified for evaluation purposes only include:

� The discount rate for calculating the levelized price


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� The commercial operation date and the date at which the collar CfD comes into effect.

� Plant capacity factor prior to conversion to the CfD

• Other parameters that would be binding upon bidders include:

� The CfD volume, which will be allocated to the highest demand periods and re-allocated in every subsequent year based on the preceding year.

� The indexing formulae for the CfD floor price, and the cap price multiplier that expresses the cap as a function of the floor.

� The formulae by which floor and cap prices are initially set based on the PPA fixed and variable payments plus the bidder’s specification of the portion of fixed costs it is willing to put at risk for calculation of the floor price.

• The bidder will specify the percentage of PPA fixed costs that should be used to calculate the floor price. (If the bidder wants 100% of fixed costs to be covered by the CfD, the contract becomes a two-way CfD with the cap equal to the floor price).

• The evaluated price, P , is a levelized price calculated as follows:

∑

∑ ∑

=

= +=

+

•+

+++= N

iii

T

i

N

Tiiiiii

Ed

FPVd

VCFCd

P

1

1 1

)1(

1

)()1(

1)(

)1(1

Where T = the last year of the traditional PPA d = the discount rate FCi = fixed costs in year i

VCi = variable costs in year i, a function of heat rate, variable O&M, assumed fuel costs, etc. N = the BOT lifetime V = the CfD volume FPi = the collar floor price in year i, which is a

function of the portion of FCi the bidder seeks to protect and VCi

Ei = the energy produced in year i at the busbar

Calculating the evaluated price in this manner rewards bidders who elect to minimize fixed cost recovery in the collar floor price. Arguably, a tender conducted in this manner can never result in stranded costs, since the arrangements are themselves the outcome of a competitive process that allows bidders to elect merchant operation.

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SUMMARY OF KEY RECOMMENDATIONS

BOT Market Integration

1. Contract future BOTs using a hybrid PPA that converts from a traditional two-part PPA to a collar CfD upon introduction of the WCM

2. Procure BOTs competitively in such a way as to establish the amount of downside risk BOTs are willing to accept in exchange for upside potential

BOT Tendering Framework Gas and Power Coordination

1. Establish a competitive tendering framework for new BOTs consistent with international practice

2. Strengthen the IBWG and eliminate or mitigate potential conflicts of interest among members

3. Clarify to stakeholders how development modalities are assigned

4. Use prequalification

5. Put the time & effort into preparing thorough RFPs & documentation

6. Use a two envelope approach

7. Set & maintain realistic time frames

8. Establish a creditworthy BOT counterparty that will remain intact through evolution of the market

1. Prepare a Quantified National Energy Plan

2. Expand stakeholder consultation in the energy planning processes

3. Use a two stage process for indicative gas price formation driven off the field development plans

4. Investigate costs and benefits of a national pipeline gas specification and producing field interconnection

5. Update the draft GMP and complete together with PMP7. Going forward update the PMP and GMP iteratively on an annual basis

6. Undertake an independent expert review of the PMP demand forecast

7. Prepare a roadmap for the reform of the gas industry

8. Formulate and apply regulations that implement the above strategies and policies, particularly with respect to consistent pricing across the gas-to-power value chain.

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TABLE OF CONTENTS

Foreword iii

Abbreviations iv

Executive Summary on Coordination of Gas & Power Pl anning viii

Executive Summary on BOT Tendering & Market Integra tion xxvi

Summary of Key Recommendations xxxix

1. Current Institutional Arrangements in Vietnam’s Gas Sector 1-42 1.1 Gas Resources and Utilization in Vietnam 1-42 1.2 Governing Legislation 1-45 1.3 Pending Legislation 1-46 1.4 The Institutional Setting 1-47 1.5 The Development Environment 1-53 1.6 Past and Current Gas Developments 1-56

2. Key Gas Sector Issues 2-1 2.1 National Energy Strategy 2-1 2.2 Stakeholder Participation in the Planning Process 2-2 2.3 Gas Pricing 2-2 2.4 Pipeline Gas Specifications 2-4 2.5 Updating the Master Plans 2-5 2.6 Gas Industry Restructuring 2-5

3. BOT Development Risks and Mitigation 3-1 3.1 The Gas-to-Power Value Chain 3-1 3.2 Risks and Risk Mitigation for the BOT Developer in the

Gas-to-Power Value Chain 3-2 3.3 Institutional Measures to Reduce BOT Development Risk 3-5

4. Mechanisms to Improve Coordination of Gas and Elect ricty Planning 4-1 4.1 Gas and Electricty Planning in an Idealised Market 4-1 4.2 Gas Planning 4-2 4.3 Electricity Planning 4-5

5. Case Study – the O Mon – Blocks B, 52/97 and 48/95 Development 5-1 5.1 Outline of the Case Study 5-1 5.2 The Existing Planning Process 5-1 5.3 The Proposed Planning Process 5-2 5.4 International Example - Thailand 5-4 5.5 International Example - Indonesia 5-6

1. Current Institutional Arrangements in Vietnam’s Gas Sector. …

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Appendices

APPENDIX A: Assignment Terms of Reference A-1

APPENDIX B: Final Workshop Presentation B-1

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1. CURRENT INSTITUTIONAL ARRANGEMENTS IN VIETNAM’S GAS SECTOR

1.1 GAS RESOURCES AND UTILIZATION IN VIETNAM

1.1.1 National Distribution of Gas Resources

Apart from a limited reticulated gas system in the north, all gas development in Vietnam is in the south of the country, as this is where gas has been found and produced. These gas developments are tied to large gas users (power generation and fertilizer production) with limited reticulation to other end-use customers. The Bach Ho and Nam Con Son developments have been operating for some years feeding the Phu My complex and some reticulation, the Malay-Tho Chu basin is now feeding the Ca Mau complex, and the Block B and 52/97 development is planned to feed the O Mon generating plants. These developments are detailed in the following sections.

The principal petroleum basins in offshore Vietnam are shown below in Exhibit 1-1, and the individual gas and oil fields in Exhibit 1-2. Gas fields are indicated by red, oil fields (which may have associated gas) indicated by green.

Exhibit 1-1: Principal Offshore Petroleum Basins V ietnam

Source: PVN website


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Exhibit 1-2: Offshore Oil and Gas Fields Vietnam

The gas field developments each have a dedicated pipeline to shore and dedicated end use customers. There is no gas pipeline interconnection between these developments, but there are plans in PVN’s draft Master Plan for Gas Development in Southern Vietnam (referred to henceforth as the Southern Gas Master Plan, SGMP) for such a pipeline to tie the principal gas supply sources together in the future. The gas from these four fields is of differing quality. For example, the gas from the Blocks B & 52/97 development may have up to 23% inerts (mainly CO2) whilst that from other fields is typically 2-8% inerts.

1.1.2 The Cuu Long and Nam Con Son Developments

The Cuu Long and Nam Con Son developments, whilst being quite separate and from different basins, are considered together here as the gas from the two pipelines is mixed onshore and they feed the same major end use customers.

A joint venture was established with Vietsovopetro in 1981 to develop the Bach Ho field and explore surrounding blocks in the Cuu Long basin. Oil production from the basin commenced in 1986, and initially the associated gas was flared.

Once there was an adequate production of associated gas, the 117 km long Bach Ho - Dinh Co pipeline and associated onshore treatment facilities were installed. This system also collects gas from the Rang Dong fields, which is piped to the Bach Ho compressor platform for transport to shore. The onshore facilities at Dinh Co include LPG separation, condensate separation, and gas drying. The gas is piped to the Ba Ria power plant, to the Phu My complex for power generation and fertilizer production, and to some major industrial users such as the Blue Scope Steel rolling plant.


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The design capacity of the Bach Ho pipeline system was initially 1.5 bcm/year, and it was upgraded to 2.0-2.2 bcm/year in 2001. As the Bach Ho and Rang Dong fields decline other fields in the Cuu Long basin will be developed to utilize the pipeline capacity.

The 2P reserves of the Cuu Long basin were 119.5 bcm, of which 97.8 bcm remained as at 2005 when the SGMP was prepared.

The Nam Con Son basin is located South East of the Cuu Long basin. Exploration activities started in 1992 leading to the discovery of an oil field and a number of gas fields. The Dai Hung oil field commenced production in 1994 and gas from the Lan Tay field has been utilized since 2003. BP is the operator of the Lan Tay field. Further gas discoveries have been made on neighboring blocks and development plans for these have been approved to ensure a continuing gas supply as the Lan Tay field declines.

Gas from the Nam Con Son basin is transported to shore by the 370 km long Lan Tay – Dinh Co pipeline which has a capacity of 7.0 bcm/year. The gas processing facilities for Nam Con Son gas at Dinh Co include condensate separation and gas drying. The dry gas is piped 32 km to the Phu My complex for fertilizer production and power generation.

The 2P reserves of the Nam Con Son basin were 150.5 bcm, of which 144.1 bcm remained as at 2005 when preparation of the SGMP began.

1.1.3 The Malay-Tho Chu Fields

The Malay-Tho Chu basin is in the South West of Vietnam and is in the continental shelf area with a common boundary with Cambodia, Malaysia and Thailand. Thailand and Malaysia have explored their parts of the basin since the early 1970’s and have developed some discoveries. The Vietnamese part of the basin has been explored since the early 1990’s and a number of discoveries made.

A production sharing agreement was signed with Talisman Malaysia in 1993 to develop the PM3-CAA block, with Talisman Malaysia as operator. Oil production commenced in 1997 and gas production in 2003. Vietnam is entitled to 50% of the gas produced from these fields at a price of 0.46 x the USD price of Medium Fuel Oil (MFO) on a calorific basis.

The gas sale and purchase agreement between the field developers and Petronas and PetroVietnam (PVN) allowed Petronas to receive Vietnam’s share of the gas produced until the infrastructure was in place in Vietnam to utilize the gas. This is now in place with completion of the pipeline to shore and the commissioning of the Ca Mau generating plants. Petronas will return an equivalent amount of gas to PVN from their share in later years.

Further discoveries have also been made, including the Cai Nuoc field, and development plans are being prepared to link these in with the PM3-CAA development.

The 298 km offshore and 27 km onshore PM3-CAA-Ca Mau pipeline transports gas from PM3-CAA fields to the end user complex at Ca Mau. This pipeline has a design capacity of 2.0 bcm/year. The Ca Mau 1 and 2 power plants (total 1500 MW) will use 1.7 bcm/year and there is allowance for a further 0.3 bcf/year to be used by the Ca Mau fertilizer works when completed.

The 2P reserves of the Malay Tho Chu basin were 151 bcm, of which 97.8 bcm remained as at 2005 when preparation of the SGMP began.


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1.1.4 The Block B, 48/95 and 52/97 Fields

Production sharing agreements covering Blocks B and 48/95 were signed between Unocal (now Chevron) and PVN in 1996 and covering Block 52/97 in 1999 respectively. Chevron is the operator of these blocks. During exploration, a number of gas fields were discovered and the reserves estimates have been approved by the Government.

The field development plan is to bring the gas ashore for a power generation complex to be built at O Mon (2670 MW), the Tra Noc power plant (183 MW) and industrial customers that will locate along the onshore portion of the gas pipeline. Depending on the landfall location and route selected, the pipeline length is estimated as either 278 km offshore plus 102 km onshore or 262 km offshore and 148 km onshore. The peak field production is expected to be 4.0-4.5 bcm/year, of which Tra Noc power station will use 0.3 bcm/year, the O Mon power stations 3.54 bcm/year, and other industrial users 0.3-0.5 bcm/year.

The 2P reserves of the Block B & 48/95 and 52/97 are 113 bcm and there is potential for a further 30 bcm in adjacent blocks.

These fields are typical of the other fields that Chevron has developed in the Gulf of Thailand. Their development plan calls for up to 31 wellhead platforms (hubs and WHPs) giving a field development of approximately 450 – 500 wells. With the dispersed geology of the basin and the large number of wells and structures, and with rapidly rising offshore development costs, the overall development requires more capital investment than the previous two developments. Also the gas is high in inert gases (up to 23%), which affects pipeline costs.

PVN and the field developers initiated commercial discussions in 2002 and have most recently been negotiating since 2006 trying to reach agreement on the gas price for the development. Until this negotiation is completed, no contracts can be awarded for the field development or the power stations.

1.2 GOVERNING LEGISLATION

The Vietnamese gas industry is still in its infancy. Legislative efforts and resources have been focused until now on oil-related matters. Various provisions of the Petroleum Law (as revised in 2000 and 2008) and Decree 48/2000 implementing the Petroleum Law are relevant to gas, but there is no comprehensive legislative or regulatory framework for gas nor any specific provisions in existing legislation that address coordination of gas supply and power generation.

Three gas issues covered by existing petroleum legislation are discussed below.

1.2.1 Contractor’s Right to Export Natural Gas vs. Domestic Market Supply Obligation

The question of whether petroleum contractors have an absolute right to export their share of natural gas has considerable bearing on the Government’s efforts to coordinate gas supply and power generation.

The 2000 Revised Petroleum Law provided for the right of a contractor to “export its share of petroleum under the agreement in the Petroleum Contract without having to obtain an export permit”. The 2000 Law also provided for the obligation of a contractor “to sell natural gas in the Vietnam market on the basis of agreements in gas development and production projects”. In addition, certain Vietnamese PSCs provide a right for the


1-46


Contractor to freely export, and have stabilization provisions protecting the Contractor in the event of change in policy or law.

The 2008 Revised Petroleum Law provides for a similar right of export but subjects this right to a domestic market supply obligation that may be invoked by the Government of Vietnam. This obligation is met on the basis of agreements for gas development and production.

The first issue is the nature of the domestic market supply obligation being on the basis of “agreements”. The current regulatory regime fails to address the scenario in which the relevant parties fail to agree on gas development and production projects. Whether the failure of relevant parties to agree could allow a contractor to export its share of natural gas is debatable. If yes, contractors could easily circumvent the domestic market supply obligation if they so desire. If no, contractors would find it difficult to comply with their obligation.

The 2008 Revised Petroleum Law stipulates that the trigger of the domestic market supply obligation is a request by the Government. This revision addresses the unclear issue under the 2000 Revised Petroleum Law as to when contractors have to supply natural gas to the domestic market. By adding such trigger in the law, the Government should be in a better position to coordinate natural gas supply and power generation needs.

Following the revisions of the Petroleum Law in 2008, a decree implementing the revised law is expected. The matter of export rights and domestic market supply obligation should be further clarified to facilitate the creation of a gas supply and power generation coordination mechanism.

1.2.2 The Government’s Right to Prepare a Gas Maste r Plan

The Petroleum Law provides for the right of the Government to prepare a master plan for the development of the petroleum sector. However, the Law is silent on how this master plan should be coordinated with planning in other sectors, or with national energy planning in general.

1.2.3 Government’s Approval of the Field Developmen t Plan (FDP)

Under the Petroleum Law, the Government must approve the field development plan (FDP) before petroleum discoveries can be developed. However, this provision does not stipulate whether and if so how the elements of an FDP (e.g. expected production volume, timing and cost) should be made available for planning in other sectors.

1.3 PENDING LEGISLATION

There are four principal laws or decrees currently under preparation or consideration, as described below:

• Decree implementing the revised Petroleum Law. The revisions of the Petroleum Law in 2008 necessitate the preparation and issuance of a decree implementing those revisions. The Government, MOIT, and other stakeholders may take this opportunity to put in place a well balanced gas supply and power generation coordination process.

• Gas Distribution and Transportation Decree. The Ministry of Planning and Investment prepared a draft decree on gas distribution and transportation a few years ago. However, this legislative exercise did not come to fruition.


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Given the new and clear petroleum management functions of the Ministry of Industry and Trade (MOIT) under the 2008 Revised Petroleum Law, it is most likely that the MOIT shall take up the remaining task.

• Gas Master Plan. There are two plans under development at this time: the Southern Area Gas Master Plan being prepared by PetroVietnam, and the Gas Industry Development Master Plan being prepared by PetroVietnam’s Institute of Petroleum (IP). These draft Master Plans remain subject to considerable changes by MOIT and other Government agencies. The current versions of these plans are examined further in Section 2.5.2 of this Report.

• Comprehensive Overhaul of the Petroleum Law. There have been various discussions (both for and against) within Government and MOIT with regard to the overhaul of the current Petroleum Law and drafting a new law that governs upstream, midstream and downstream activities in a more comprehensive integrated manner. Given the legislative process in Vietnam, it could take 3 to 4 years, if not more, to complete, prepare and enact such a law.

1.4 THE INSTITUTIONAL SETTING

1.4.1 The PSC Regime

Oil and gas development in Vietnam is undertaken under a production sharing contract (PSC) arrangement. PVN, under the supervision of the Ministry of Industry and Trade (MOIT), prepares a block tender and issues this to interested international oil and gas companies. This is typically a tender for one block only, but may cover more than one. The successful bidder then enters in to a production sharing contract with PVN and undertakes the exploration of the block. Under the PSC the international partner is the operator for the block and fully funds the exploration work. In the event of a discovery PVN has the right to participate in the development phase up to a prescribed percentage, and the right to purchase all of the gas produced that is landed in Vietnam.

The form of the PSC has been amended in recent years to more closely resemble the joint venture arrangements used in many countries for petroleum exploration. The new Joint Operating Agreement (JOA) is an extended conventional PSC where the international petroleum company bears all the risks and costs during the exploration phase, but there is more cooperation and participation throughout by PVN. A Joint Operating Company (JOC), a Vietnamese legal entity which merely acts as agent on behalf of the contracting parties, is established and PVN has the right to assign staff to the JOC from the beginning. Typically PVN will have 20-50% participation under a JOA.

1.4.2 The Ministry of Industry and Trade

The Ministry of Industry was established in 2003 under Decree No. 55/2003/ND-CP to manage the state’s interests in the industrial sector, including energy. It subsequently became the Ministry of Industry and Trade (MOIT). As can be seen from the organization chart below in Exhibit 1-3, MOIT has wide ranging responsibilities across all aspects of industry and trade, covering policy development and implementation, science and technology and international relations. The two departments within MOIT affecting gas and electricity are the Energy and Petroleum Department and the Electricity Regulatory Authority of Vietnam.


1-48


Exhibit 1-3: MOIT Organizational Structure

Source: MOIT website

The Ministry has established a separate body, the Electricity Regulatory Authority of Vietnam (ERAV), to regulate the electricity industry as it moves toward a market structure.

ERAV is currently developing the rules for the Competitive Generation Market (CGM) and will later regulate the CGM and develop the rules for Wholesale Competitive Market


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(WCM) and eventually full retail competition. The development of these markets is discussed further in the Volume 2.

The Ministry has overall control of the gas and electricity planning processes, develops strategy for the sector for government approval, and helps develop draft legislation to implement that strategy and manage tariff setting. The Electricity Law provides for preparation of national electricity development plans, which are referred to here as Power Master Plans (PMP), and the Petroleum Law provides for the preparation of national gas development plans, which are referred to here as Gas Master Plans (GMP). The responsibility for the master plans rests with MOIT, and they have to date contracted the Institute of Energy (a subsidiary of EVN) and the Institute of Petroleum (a subsidiary of PVN) to prepare the electricity and gas master plans respectively. ERAV is now developing a new power sector planning regime to cater for the new CGM, and ERAV has engaged a consultant to assist with this work.

The inter-relationships between MOIT and the other participants in the electricity industry are shown in Exhibit 1-4 below.

Exhibit 1-4: Current Electricity Industry Institut ional Relationships

In the gas industry PVN has a dominant position, and there is no equivalent of ERAV. However further gas industry restructuring has been contemplated, as outlined in Section 1.3, though it would not liberalize the sector to the extent the power sector is being liberalized under the Electricity Law. The inter-relationships between MOIT and the other participants in the gas industry are shown in Exhibit 1-5 below.



EndUsers

EVNTransmission

ERAV

Electricity flow

EVN Single Buyer

Sellelectricity

Sellselectricity

Managesthrough

PMPprocess

Regulation

Develops retail tariffs for approval by Minister, MOIT



Prime Minister

Approves PMP


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Exhibit 1-5: Current Gas Industry Institutional Re lationships



PVNWholesale


Non-GenerationEnd Users

All gassales

Gas flow


LPG




PSCPartners


PSCPartners

Prime Minister


1.4.3 The Electricity Industry

Electricity of Vietnam (EVN) is the state-owned corporation that operates in the areas of generation, transmission, distribution and retailing of electricity. It also has subsidiary companies active in power consulting, training, manufacturing and other electricity related areas.

EVN has a mix of generation assets including hydro power stations, coal fuelled thermal power stations, oil and gas fuelled thermal power stations, and gas fuelled combined cycle power stations. In addition to the EVN owned generating plant, there are a number of IPP, BOT and cogeneration stations. The latest information on system demand and the generation mix is for 2006, and is shown in Exhibit 1-6 below.

Exhibit 1-6: Installed Electricity System Capacity and Generation 2006

2006 MW % MWh % EVN Hydro 4,583 37.09 19,096 32.33 Coal fired 1,245 10.08 8,808 14.91 Oil fired 198 1.60 654 1.11 Diesel 285 2.31 54 0.09 Gas turbine (gas & oil) 3,107 25.14 17,906 30.31 Total EVN 9,418 76.22 46,518 78.75 IPP/BOT 2,939 23.78 12,550 21.25 Total 12,357 59,068 Source: EVN Corporate Profile 2006-7


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To reduce the capital demands on EVN and allow competition to develop in the generation market, other state-owned and private companies may also develop power stations. Non-EVN generation power stations that operate on the basis of a contract with EVN for electricity sales and a contract for fuel supply are referred to as independent power producers (IPPs). On the other hand, power stations developed under the Build-Own-Transfer (BOT) Law, which provides for government guarantees and other incentives or facilities for investors as provided for in a separate contract with Government, are referred to as BOTs. In practice, IPPs are locally owned while BOTs are foreign owned, though there is no requirement for local ownership of IPPs or foreign ownership of BOTs.

EVN operates the national transmission system through four transmission companies and a system operator. The backbone north-south transmission system is 500 kV (3,259 km) with secondary transmission at 220 kV (5,278 km) and 110 kV (11,820 km). There is a program of transmission system upgrades to meet the system load growth and to allow connection of the new generating stations.

EVN, through its Power Companies (PCs), also owns most of the county’s distribution network and retails to end-use customers. Electricity prices are regulated and the average per capita consumption for the country is very low. There is an active rural electrification program to ensure that electricity is available to the more remote areas.

Total system electricity sales in 2006 were 51,530 GWh, giving a system loss factor of 11.05%. The load growth over the period 2000 – 2006 has been in the range 13 – 17% per year. Despite the connection of a new generating plant there was significant peak demand period load shedding in August 2008.

The electricity industry is currently undergoing restructuring to allow the introduction of a competitive generation market and ultimately a competitive retail market. Details of the industry reform were covered in Volume 2.

1.4.4 The Gas Industry

From the 1960s until 1990 oil and gas exploration in Vietnam was undertaken by government ministries working with overseas partners. As the industry developed, the role of regulator and policy developer was left with the ministries, now the Ministry of Industry and Trade. In 1975 a separate state owned company, Vietnam Oil and Gas Corporation (PetroVietnam or PVN), was established to undertake oil and gas exploration, development and production.

Since its inception, PVN has grown into an integrated oil and gas company with interests in exploration, oil and gas field development, oil industry services, consulting, gas transport and supply, electricity generation, fertilizer production, petrochemicals, petroleum refining and property, finance and insurance. It also has exploration and production interests outside of Vietnam. PVN is the government partner in the production sharing contracts for field development and purchases all the gas produced for domestic use from the field developers. PVN does not supply or distribute refined petroleum products in Vietnam.

One of the PVN subsidiaries is PV Gas. PV Gas operates and maintains the pipeline and gas processing assets of PVN, but does not hold the gas contracts, own the gas or set tariffs for gas transportation. The responsibility for negotiating the gas contracts rests with PVN.

Exhibit 1-7 below shows the PVN’s organizational structure.


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Exhibit 1-7: PVN Organization Chart

Source: PVN website

As detailed in an earlier section the oil and gas industry operates under the Petroleum Law. The present law does not give PVN the exclusive rights to purchase all gas produced and on-sell this to their own subsidiaries or other end users, but the custom is for this to happen (at least for domestic sales) and it is doubtful that any other arrangement would be approved at this time. The gas industry has not yet started to develop a competitive market and there is no formal regulation of the industry. However legislation is being developed that in the future may allow the other production sharing partners in a development the right to sell domestically a proportion of the gas produced from their field.


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1.5 THE DEVELOPMENT ENVIRONMENT

1.5.1 The Electricity Master Plan

Electricity planning processes are well established in Vietnam with the Sixth Power Master Plan (PMP6) covering the period 2006-2015 approved by the government and the seventh master plan under preparation. MOIT is responsible for the development of a PMP every 5 years, and contracts the Institute of Energy (IoE), a subsidiary of EVN, to undertake the work.

The current process for producing a PMP is shown in the flow diagram in Exhibit 1-8. As part of the introduction of the new CGM, ERAV is developing new planning procedures. At this time it is not clear how these new procedures will interact with the existing PMP processes.

Exhibit 1-8 Flow Diagram of the Current PMP Process

MOITAppoints IoE

IoE PreparesCost Data

Bases

PMApproves

PMP

MOITDesignates

DevelopmentModality


Plan


IoE PreparesDraft PMP

Hydro Plans

IoE PreparesDemandForecast

RegionalElectricity

Plans

IoE PreparesFinal PMP




The Sixth Power Master Plan has a base case for growth of annual energy demand of 16.0% over the period 2006-2010, reducing to 11.0% over the period 2011-2015, 9.1% over the period 2016-2020, and 8% over the period 2016-2020. Installed capacity (including imports) will increase from some 9,700 MW in 2005 to 24,919 MW in 2010 and 53.619 MW in 2015. These very high growth rates require a corresponding rapid generation development program, and are driving the very high gas demand forecasts. It is likely that the recent global economic downturn will moderate this growth.

In preparing the demand forecasts for the PMP, IoE consults widely with industry players, major customers, government departments and the distribution companies. From this consultation a national energy demand forecast is prepared with various alternative growth strategies. As well as a demand forecast, a plant capital cost data base, a fuel availability and cost data base, and an operating and maintenance cost data base are established.


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Having established a national demand forecast and the fuel, capital and maintenance cost data bases, IoE undertake a least cost generation expansion planning exercise to determine the optimum generation expansion plan. IoE uses the system planning package STRATEGIST and checks the results of this modeling against outputs generated from other internationally recognized planning software packages like PDPAT II and WASP (Wein Automatic System Planning – developed by the International Atomic Energy Agency). The results of this modeling are used to produce a table of new generating plant required for the system growth.

At this stage of PMP preparation the modality for development of the individual stations has not been established. The proposed plant schedule is then submitted to MOIT, which then determines which plants will be developed by EVN, which as IPPs and which as BOTs. The revised plant schedule and other comments from MOIT are incorporated into the PMP, which is then submitted to MOIT for final review and onward submission to the Prime Minister for approval.

The capital investment needs under PMP6 for electricity generation growth are estimated as approximately USD114 billion. To help reduce the internal demand for funding for power generation projects it is planned that between 8,225 and 14,675 MW of new BOT capacity will be built between 2011 and 2015. For some of the new plants identified in PMP6 the development modality has been designated as either IPP or BOT; hence the range in planned BOT capacity additions.

The PMP also addresses transmission system expansion planning to ensure that there is a secure grid able to handle the output of the planned new generating stations. EVN has established separate subsidiaries for transmission asset ownership (Transmission Network Owners or TNOs under the CGM) and a System and Market Operator (SO/MO). ERAV is also developing a transmission open access regime and a new transmission pricing structure. This structure will be based around shallow connection costs for the generators, deep connection costs for the distribution companies and no locational pricing (i.e. it will rely on postage stamp charging). At this time the pricing has not been quantified and the model contracts are still under development.

1.5.2 The Gas Master Plan

Unlike electricity planning, which has been established for many years, gas planning in Vietnam has commenced relatively recently. PVN began preparation of the Southern Gas Master Plan (SGMP) in 2005, and final review and approval by MOIT is expected soon. Given that there are no significant indigenous gas resources outside of the southern part of the country, the SGMP will serve as a major input to the national Gas Industry Development Master Plan (referred to henceforth as the Gas Master Plan, GMP). MOIT has appointed the Institute of Petroleum (IP), a subsidiary of PVN, to prepare the GMP. The process for the preparation of the GMP is shown in the flow chart in Exhibit 1-9 below.


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Exhibit 1-9: Flow Diagram of GMP Processes

MOITAppoints IP


Forecast

PMApproves

GMP

MOITReviews Draft

GMP



Forecast


PSC ReservesReports


Plans




The draft SGMP follows the normal processes of assessing the demand for gas in the southern part of the country, assessing the reserves in the basins that have been developed and the basins that could be developed, and matching supply and demand. It also briefly addresses the issue of gas import from the proposed Trans-Asia Gas Pipeline (TAGP) pipeline linking neighboring countries, and acknowledges that this has been a long time in gestation and it will probably be some years yet before there is commitment to the project. It also looks briefly at liquefied natural gas (LNG) and concludes that LNG imports are unlikely at current world LNG prices. PV Gas is also preparing a new report on LNG importation, which was due to be completed at the end of 2008.

It is expected that IP will follow similar processes in preparing the GMP, but they will take a national view rather than just covering part of the country as in the draft SGMP.

On completion of the draft SGMP or draft GMP they are submitted to MOIT to ensure that they meet the government’s energy strategy and once finalized, MOIT submits them to the Prime Minister for approval.

This report does not attempt to review the content of the SGMP or the GMP, but looks at the processes around gas and electricity planning. It is important to note that as 80% of gas is used for electricity generation, and that percentage will rise as more gas fuelled generating plants are commissioned, the GMP is essentially a production plan to meet the demand for gas from the electricity sector.

1.5.3 Gas and Electricity Master Planning Co-ordina tion

For the GMP and PMP processes to be successful there needs to be careful coordination between the two processes. Ideally they should be carried out at the same time with a great deal of interaction between IoE and IP. The current PMP6 was prepared in advance of the draft SGMP and GMP. The following section is based on the current planning processes, which may change once ERAV has promulgated the new electricity planning


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procedures for the CGM. When this matter has been discussed with ERAV the consultant for this work had only just commenced work and results were not yet available.

With the very high load growth in the country there is an urgent need for new generating plant. Currently there is one gas project (O Mon) in the process of negotiating a fuel supply agreement, two coal BOT projects that are in the process of negotiating fuel supply agreements and PPAs, and a coal-fuelled BOT project that is seeking bids from BOT developers. It appears that the assumptions used for fuel pricing and capital cost for O Mon in the preparation of the PMP are no longer current, and that the current fuel and capital costs will result in electricity prices that would contribute to higher than anticipated retail prices. During 2008 there was significant load shedding occurring on a regular basis.

This disconnect between the fuel price assumptions used in the planning process and the realities of today’s markets highlights the lack of coordination between fuel planning and pricing and the power master plan development process. These issues are discussed further in Section 3 of this report and some suggested solutions are provided in Section 5.

1.6 PAST AND CURRENT GAS DEVELOPMENTS

A brief review of the three major gas developments that have been undertaken in Vietnam to date is presented below. Whilst looking backwards can provide some useful guidance on past successes and failures, the review also considers the recent international market for power plants and offshore oil and gas developments. In the last few years the escalation of capital costs for major projects has greatly exceeded normal escalation. As an example of the escalation of offshore costs, development of the Kupe offshore gas condensate field in New Zealand was estimated to cost around USD 300 million in 2004, but costs had risen to USD 750 million by the time of project commitment in early 2006.

There has also been reluctance from the major contractors to commit to EPC contracts or to hold tender prices for more than three months. However, with the current global economic slowdown, EPC contractors may become more flexible and commodity prices for steel and other materials have already started to moderate.

1.6.1 The Cuu Long, Nam Con Son and Phu My Developm ents

Bach Ho and related fields in the Cuu Long basin were developed initially as oil fields with the associated gas being flared. As production grew the associated gas was collected, piped to shore and used for power generation and industrial plants. As a lot of the infrastructure (wells, platforms) and exploration costs were covered by the oil sales revenue it was possible to land gas at low cost (from PMP - USD 2.2./million BTU) with an annual escalator of 2%. This set the benchmark for gas pricing in Vietnam.

The Nam Con Son development is based on the Lan Tay and the Lan Do fields in Block 06.1 and is essentially a dry gas development with some condensate. Thus it did not have the benefit of oil sales revenue to underpin the project, and it is much further from shore than Bach Ho. However the reservoirs are large and have good permeability allowing development with few wells. The project was developed to supply gas to the Phu My power and fertilizer complex.

The price for gas (from PMP – USD 3.22/million BTU) from this development was arrived at by a lengthy set of negotiations covering gas sales, electricity sales and project development. The project took 12 years from the signing of the PSC contracts to the signing of the contracts for the commercial development of the field and the end user


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plants. The escalator in the gas price is 2% annually, giving a falling gas price in real terms.

PVN contracted to purchase all the gas from the Nam Con Son development under a take or pay contract. PVN then on-sold some of the gas to EVN for electricity generation, some to a consortium led by Electricitie de France (EDF) for the Phu My 2-2 generating plant, and some to the fertilizer works. However, after these sales contracts PVN still had a take or pay obligation which exceeded their sales volume.

At this point BP, who is the field operator, brought together a consortium including SembCorp Utilities of Singapore, Sojitz Corp. (formerly Nissho Iwai Corporation) and Kyushu Electric Power Co to build the 715 MW Phu My 3 generating plant. This plant utilized the outstanding take or pay volume under the Nam Con Son contract, thereby reducing PVN’s exposure to take or pay payments under their gas purchase contract. This is an example of a gas field developer taking positions throughout the entire gas-to-power value chain to reduce project risks. BP and their PSC partners could have taken no action and accepted the take or pay payments, but gas field developers prefer to operate the field and pipeline at design output as this provides maximum liquids recovery and lowest overall operating costs.

Phu My 3 was the first gas fired BOT project completed in Vietnam, and had a very long gestation period. The BOT contract was signed in 1995, but the GSA, PPA and EPC contracts were not signed until 2001. Once these were signed the project moved ahead quickly, with ground breaking on site in December 2001, and commercial operation in early 2004, a 26 month construction period. The structure of the Phu My 3 development is illustrated in Exhibit 1-10 below, and is typical of the structure required for a BOT project to proceed.

Exhibit 1-10: Phu My 3 BOT Project Structure


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To reduce the development risks on the Phu My 3 project, the plant has been built for gas or liquid fuel operation, and has sufficient liquid fuel storage on site for six days operation at full load. The plant has operated on liquid fuel, but only long enough to meet the requirements of the performance tests under the EPC construction contract. First gas from the Nam Con Son development flowed in November 2002, and gas was available to the plant at commissioning. The liquid fuel risk mitigation has until now never been called upon for commercial operation. It continues to provide a back-up in the event that there is a problem with the gas field or the gas pipeline.

The Phu My 2-2 generating plant (715 MW) was also developed under a BOT contract following an international tender process. The BOT contract was awarded in 1999, and the station was commissioned in February 2005. Phu My 2-2 was developed by a consortium of EDF, Sumitomo and Tokyo Electric Power Company.

As the Lan Tay and Lan Do fields decline the Rong Doi and Rong Doi Tay fields in Block 11.2 are being developed by a PSC operated by Korean National Oil Company (KNOC) to meet the ongoing gas demand. However, this gas will be at a considerably higher price than the present Phu My contracts.

1.6.2 The Malay-Cho Thu and Ca Mau Development

The Malay-Cho Thu gas development is similar in some respects to the Bach Ho development. The field was already being exploited for oil, and the gas produced was being sold to Petronas until a pipeline to Vietnam was built. Since the pipeline to Vietnam has been constructed the gas production is shared between Petronas and PVN, with PVN having rights to an additional volume equal to the 50% of the gas produced prior to the pipeline construction.

Because the infrastructure for field development was already in place, the gas development costs were lower and the risks to the IPP power station developer, PVN, were reduced. Apart from the power station plant, the only additional construction risks lay around the pipeline to shore. In addition to Ca Mau 1 (750 MW CCGT) and Ca Mau 2 (750 MW CCGT) power stations, an EPC contract has been signed for a fertilizer plant at Ca Mau.

For this development the gas price is set at 0.46 x MFO price expressed in USD on a calorific basis. This means that the gas price rises directly as oil prices rise. With the very rapid rise in oil prices in the first half of 2008 (to around USD140/bbl), the price of this gas rose rapidly. In May 2008 EVN was dispatching the 750 MW Ca Mau plant at 450 MW and buying electricity from China as it was cheaper than gas generated electricity from Ca Mau. With the recent fall in oil prices the Ca Mau gas price has dropped, but is still higher than the Phu My contract price.

The important lesson from the Ca Mau development relates to the impact of a primary fuel price escalator on dispatch when retail electricity prices are fixed. The world trend is to link gas prices to oil prices, which in recent times has led to rapid gas price rises. For example, LNG prices are often linked to the “Japan Crude Cocktail” (JCC), a price benchmark based on Japan’s average monthly price for imported crude oil. This rapid gas price rise would normally pass through to a rise in electricity prices, but in Vietnam the retail electricity prices are controlled and fuel price rises that are passed through PPAs can lead to large operating losses at the wholesale level. This loss is carried by EVN at present, but in the future CGM either the station wouldn’t be dispatched or the effect of the higher fuel prices would flow on through the regulated tariff process to the retail customers.


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1.6.3 The Blocks B, 52/97 and 48/95 and O Mon Devel opment

Block B and associated fields are quite different to the other developments to date. These fields are similar to other Gulf of Thailand fields, with small pockets of dry gas containing relatively high inerts. For the full field development, it is anticipated that 450-500 wells and up to 31 platforms will be required.

As a consequence, gas production costs are higher than for conventional developments, and the field developers’ gas price requirements are consequently higher given the full life cycle costs of the project. This gas price results in a generated electricity cost that is challenging for the present regulated price market in Vietnam, and the parties are still locked in gas sale and purchase contract negotiations.

The O Mon generating complex will eventually comprise the following stations:-

• O Mon 1 Unit a - 300 MW conventional thermal plant developed by EVN capable of using fuel oil or gas. Currently under construction and scheduled for 2009 operation.

• O Mon 1 Unit b - 300 MW conventional thermal plant developed by EVN capable of using fuel oil or gas. Scheduled for 2010 operation.

• O Mon 2 – competitively tendered BOT 750 MW CCGT. Scheduled for 2013 commissioning

• O Mon 3 – 750 MW CCGT developed by EVN. Scheduled for 2011 commissioning

• O Mon 4 – 750 MW CCGT developed by EVN. Scheduled for 2014 commissioning.

One of the issues for the gas field investors is the period over which the gas demand increases and the risk that the planned generating plants may not be built. For a high cost development such as Block B and associated fields, it is essential that the infrastructure reach design capacity as quickly as possible to accelerate and maximize the revenue stream. To do this requires a coordinated and prioritized program of generation development, to reduce the end-to-end project risk to the field developers. One way for the field developers to reduce the financial risks to all parties is for them to negotiate an equity position in those generation projects and the pipeline to shore, so that they can exert pressure to ensure that all aspects of the projects along the gas-to-electricity value chain proceed on schedule.

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2. KEY GAS SECTOR ISSUES

2.1 NATIONAL ENERGY STRATEGY

By Decision No 1855/QD-TTg dated 27 December 2007, the Prime Minister approved the National Strategy of Energy Development up to 2020, Vision to 2050. This decision outlines in broad terms the government’s strategy for energy development and presents their vision for the energy future of Vietnam.

The decision document outlines at high level the objectives of the strategy, but it does not quantify the indigenous resources available to meet that strategy, and nor does it allocate priorities to different fuels or sectors of the economy. It forms a good basis from which to proceed forward and quantify energy demand by sector of the economy and fuel type, and quantify the indigenous and imported fuel available to meet that demand.

A Quantified National Energy Strategy Report should be prepared that would cover issues such as:

• Demand for energy across all sectors of the economy

• Indigenous and imported energy resources to meet these demands

• Prioritization of energy technologies

• Energy conservation and efficiency

• Energy security

• Environmental considerations, sustainability, and carbon impacts

• Accessibility and social impacts

• Government funding and support across fuels and sectors

• Energy pricing and policy across fuels and sectors

The present sectoral preparation of master plans cannot address all of the issues for the energy strategy in an integrated or consistent manner. The quantification of the energy strategy and vision decision through a Quantified National Energy Strategy Report would tie the various sectors, such as electricity, gas, LPG, coal, and liquid fuels together in a way that meets the overall economic objectives, and determine the best use of the indigenous energy resources from a national perspective rather than a sector perspective. For example, the Report should address whether it is best from a national perspective to use gas for electricity generation or for fertilizer production or for transport by means of CNG. The linkages between fuel pricing in one sector with pricing in another sector can also be considered in a more integrated or consistent manner.

A Quantified National Energy Report would be also an effective mechanism to begin addressing issues around greenhouse gas emissions and any policy development in that area. Vietnam is a signatory of the Kyoto Protocol, and is a non-Annexe 1 country and not subject to emissions limits. However, post-Kyoto there will be increasing pressure on the developing countries to participate to some extent in the future greenhouse emissions control regime that is developed. The work in preparing the Quantified National Energy

2. Key Gas Sector Issues

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Strategy Report would allow greenhouse gas policy issues to be addressed and guidance given to the sector master plans as they are developed.

The lack of a comprehensive treatment of energy issues can result in:

• Lack of coordination between the sectors within energy markets

• Sub-optimal project development

• Increased cost to the national economy

• Difficulties in implementing sectoral energy policies.

Quantification of a national energy strategy is a major undertaking and requires a significant commitment from all sectors of the energy industry and from the economists of the various planning departments. However, the impact of the recent world oil price rise and subsequent decline shows the importance of having a robust economic model of the country’s energy industry and of the effect of international energy prices on the local economy.

If a Quantified National Energy Strategy Report is prepared it is essential that this be a “living document” that can respond to the rapid international energy price changes that are occurring. This means that once approved the report, which should have a life of around five years, should be updated every year and a supplement issued.

2.2 STAKEHOLDER PARTICIPATION IN THE PLANNING PROCE SS

During country visits for this report, discussions were held with officials, managers of the state companies and with private sector gas and electricity generation developers. Whilst those who are responsible for the preparation of the SGMP and PMP have tried to seek the views of all stakeholders in the development process, there is a clear message that there is insufficient consultation and discussion with the private sector.

Particularly where foreign capital is required for the new investments, such as BOT generation projects and gas field development, it is essential that the developers and their financiers have confidence in the whole industry. This includes their being consulted and involved in the planning process, and ensuring that there is an open and transparent regulatory regime and business environment.

If the developers of Block B had been consulted during preparation of the current PMP, they may have provided an early indication that the price of gas from this development was high, and the project may have shifted within the least cost generation expansion plan or the issues around pass-through of the higher gas cost could have been addressed earlier. Stakeholders’ views on gas pricing should of course be critically reviewed against world gas prices, local conditions, and independent assessments by domestic institutions.

2.3 GAS PRICING

Gas pricing in Vietnam has tended to be cost driven rather than market driven. The first large gas supply came from the Bach Ho development, and as it was an associated gas supply the cost of development was relatively low. This low price (USD2.2/million BTU) of gas allowed existing oil fuelled power stations to be converted to gas and major industrial customers to take supply.


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Similarly with the Nam Con Son development, PVN, EVN and the developers were able to negotiate a price (USD 3.22/million BTU) that enabled electricity to be generated at a price that was compatible with electricity prices prevailing at that time. Both Bach Ho and Nam Con Son gas contracts have a 2% escalator.

In contrast, Malay-Tho Cu gas is priced at USD 0.46xMFO. Whilst this may have been an attractive price when crude oil prices were around USD 30-40/barrel, it is now, by Vietnam electricity standards, a high gas price and EVN may not be recovering the full cost of the electricity generated by the Ca Mau plants from the retail electricity price. Depending on how this price is benchmarked, at USD 50/barrel for MFO this equates to around USD 3.60/million BTU and at USD 140/barrel it equates to around USD 8.60/million BTU. Although this may be a higher price than the Vietnam electricity market can withstand, it is not a high price by international standards, as is shown by the prices in Exhibit 2-1 below for August 2008 and January 2009 (though these prices are volatile as shown in the Final Workshop materials attached in Appendix B). Typically LNG is trading at around 65% of oil price parity, but some spot cargoes have traded above oil price parity.

Exhibit 2-1: International Gas Prices

Country

Location

Price Aug 08

USD/mmBTU

Price Jan 09

USD/mmBTU USA SoCalGas 7.64 7.37 USA Henry Hub 8.26 7.66 Japan Gas Linked 12.12 14.61 Japan Oil Linked 22.67 19.00 Netherlands Title Transfer Facility 11.19 10.15 UK National Balancing Point 10.31 10.43 Source: FERC website and Platts

http://www.platts.com/Natural%20Gas/Resources/News%20Features/gasdivergence/chart3.xml

The Block B & 48/95 and 52/97 development is a high cost development. The field requires 450-500 wells, up to 31 platforms and a larger than normal pipeline to shore to transport the high CO2 gas to the power stations. The field developers and PVN as gas wholesaler have been in negotiations for some years to try and reach an agreement on a gas price that will allow the field development to proceed.

Once the CGM is in place there will be least-cost dispatch and some of the higher fuel price stations may at times not be dispatched. There will also be provisions to allow higher fuel prices to be passed through to the retail tariffs, but there will be bid caps based on technology type and domestic fuel use. ERAV has designed the CGM and is currently finalizing the rules, but has not yet developed a market simulation model that will allow them to quantify the retail tariffs resulting from the introduction of the CGM or to quantify various caps and collars and the price for the BNE (best new entrant), a critical component of market price setting. It is important that a robust market simulation model be developed as soon as possible and made available to stakeholders to use, firstly to build confidence for the CGM with existing market participants, and secondly to allow Government and developers to be able to model the impact of the proposed fuel supply contracts, PPAs and the CGM on specific projects.

The price for gas for electricity generation can be set in a number of ways:

• Cost of production

• Value for alternative uses

• Cost of alternative generation (netback)


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• Negotiation.

A cost of production regime is a regulated regime where the developers would be required to submit the costs for the proposed development and would be entitled to earn a regulated rate of return on those costs. Where there is both liquid and gas production from a field the costs should be allocated equitably to the two revenue streams. The concept of the cost of production is familiar to the international oil companies, as it is used in the royalty regime in some countries.

To establish gas pricing from the value for alternative uses would be difficult in Vietnam, as the gas industry is dominated by electricity generation and there are limited alternative large gas users. However a model could be developed to value the gas against the alternative use for large scale fertilizer production or methanol production. Another alternative use that may become a competitor to electricity generation for the fields that are a long way from the end-use customer is floating LNG production. There are a number of companies (e.g. Flex LNG, Mustang, BW Offshore) proposing floating LNG plants with the objective of monetizing otherwise stranded gas resources. Flex LNG has ordered the first four floating LNG ships, with the first committed to a field in Nigeria. Such a plant allows the gas field developer to access the international LNG market and avoid the cost of the pipeline to shore.

The least-cost generation expansion planning model essentially sets the value of gas for electricity generation by modeling large coal fuelled generating plant based on domestic and international supply of coal. Such a station sets the benchmark for electricity prices going forward, and the gas price can be determined from the capital costs, operating costs and efficiency of a modern CCGT plant. One factor that complicates this process is a carbon pricing regime. That will add more to the cost of coal generation than to gas generation, and if a carbon pricing regime is to be introduced then it should be factored in to the least cost generation expansion plan.

Negotiation is the process currently used in Vietnam. All parties to this negotiation will have undertaken their own analysis using one or more of the above methodologies and will have a view on what the gas price should be. Where the process encounters difficulties is where the electricity price that arises from the gas negotiations is greater than the electricity market can manage because there is no pass through of electricity generation costs. This is the present situation.

In an open and competitive market the gas price will rise to the value of the gas for alternative uses or the price where it is cheaper to use an alternative fuel (usually coal) for thermal generating plant.

2.4 PIPELINE GAS SPECIFICATIONS

The gas from the four fields that have been developed or are in development is of differing quality and composition and there is no national gas quality standard. At present the only two gas supplies that are linked are those from the Bach Ho pipeline and the Nam Con Son pipeline. The SGMP envisages interconnecting pipelines to allow balancing between the various sources of gas, but is silent on the matter of a national standard.

If there is to be further interconnection of gas sources then a national gas standard will have to be established, and all end users that are currently not being supplied with national pipeline standard gas, other than some large end users who may wish to stay on an untreated gas standard direct supplied by one field, will have to convert their equipment to the new gas standard.


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The associated gas delivered by the Bach Ho pipeline is high in LPG and is stripped of the LPG on shore to bring the gas to a similar specification to the Nam Con Son gas to enable the two gas flows to be mixed. This gas has the lowest level of inerts of all the fields, and may well become the national pipeline standard.

The Malay-Tho Chu pipeline gas has around 8% CO2, and would have to be treated to remove some of this CO2 if it is to be used in a national pipeline network. One option is to leave the Ca Mau complex operating on the untreated gas, but then it unlikely that it could then benefit from a back-up supply from the other fields.

The gas from Block B and related fields contains around 23% inerts, mainly CO2. The O Mon generating plant is being designed to utilize gas of up to 23% inerts. Again, if this gas is to be utilized for the national pipeline, then it will need treatment to bring it to the national gas standard, and if the O Mon complex continues to operate on untreated gas it is unlikely to be able to utilize national gas standard gas for back-up supplies.

By implementing a national gas standard, building an interconnecting pipeline network and gas treatment plants it may be possible to defer expensive offshore gas field development.

2.5 UPDATING THE MASTER PLANS

The GMP and the PMP are prepared under a five year planning cycle. PMP6 has been approved by government and covers the period from 2006 to 2015. The SGMP covers the same period and serves as the basis for the GMP, but has not yet been finalized and approved by government.

Although for the PMP there is an annual review of the assumptions and modeling of the system to cater for changes in the market place, there is no formal process to issue a revised PMP or even an addendum listing the key market changes and the results of the modeling. Thus the schedule of stations to be built and the commissioning dates in the public domain stays the same, and does not adjust to changing market conditions.

The draft SGMP has not yet been formally approved, and will be replaced by the GMP now under preparation. The draft SGMP in circulation has dates that cannot be achieved and does not reflect the reality of current high international gas and oil prices or the high costs of any offshore development.

If the GMP and PMP are to maintain their relevance as the key planning documents for the industry, then following government approval of the plans there should be a coordinated annual review program that produces updated plans or an addendum document that details the changes to the plans.

With the introduction of the CGM the planning processes will become more complex, as there will be another set of electricity planning procedures under ERAV. At the time of this writing it is not clear how this new planning process will operate as the ERAV consultant has not completed this work. However, for the new process to be effective it is essential that it is a dynamic process with regular updates and extensive stakeholder consultation. The output of the CGM least-cost planning process may well form the basis for the annual update of the PMP.

2.6 GAS INDUSTRY RESTRUCTURING

The electricity industry is undergoing a series of major structural changes to introduce a competitive electricity market. Key to that process is the separation of the monopoly sectors of the industry, such as transmission and distribution, from the potentially


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competitive sectors, such as generation and retailing. In Vietnam the various sectors are being separated internally within EVN and some parts will become joint stock companies. Many other countries require a greater degree of separation, and have strict rules about cross ownership, for example of a generating plant by a transmission company.

In the gas industry in Vietnam, PVN holds a dominant position. There is no formal separation of gas transmission or distribution and no common carrier regime exists. PVN is the only wholesale buyer of gas, and at the same time is a purchaser of gas for its own electricity generation projects, a retailer of gas and the principal player in all gas transport. While PVN hold such a dominant position in the gas market it may be difficult to bring greater competition into the electricity generation market through gas-fuelled generating plants, particularly in the southern part of Vietnam where there are limited indigenous fuel alternatives.

An open access regime for gas transmission could contribute to greater competition in the electricity market, and could help mitigate some of the conflicts of interest inherent in PVN serving as PSC partner, the monopoly gas supplier, the gas transmission company, and as a participant in the electricity generation market. As a minimum, to affect an open access regime PVN should undertake accounting separation for their gas transmission and distribution assets and publish separate accounts for this business unit to allow a degree of transparency over transmission pricing. A better regime would involve a more formal separation of the upstream (gas production) activities of PVN from the monopoly activities (transmission and distribution) and the competitive activities (gas wholesaling and retailing). This would be similar to the restructuring of EVN that is occurring in the electricity sector, and allow the development of a gas market.

However, it is acknowledged that in order to reduce the capital expenditure risks the field development partners may wish to invest along the full gas-to-electricity value chain - i.e. invest in the pipeline to shore and the end user plant as well as the field development. Even though there may be take or pay contracts, developers do not wish to earn their income from enforcing those contracts when they have a stranded production plant awaiting an end user plant completion or a pipeline completion. Should that occur, as is the situation with the existing major gas pipelines to shore, then a suitable regulatory regime will be required.

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3. BOT DEVELOPMENT RISKS AND MITIGATION

3.1 THE GAS-TO-POWER VALUE CHAIN

The gas-fuelled electricity generation projects in Vietnam to date have been field specific and therefore the gas and electricity projects are tightly linked. This is quite different to developing a gas field or a power station in, for example, the United States where there is a deep gas market. In a deep gas market a gas field developer has access to a network of gas pipelines and a range of gas purchasers. Similarly the power station developer has access to the gas transmission network and from that a range of gas sellers. In such a market there is usually a spot market for gas and the price the customer pays can be the spot price or a contract price set outside the spot market. There are also likely to be financial contracts, such as contracts for differences (CFDs), available to hedge the spot price risk.

Thus in a deep gas market a BOT generation project developer is able to develop the generation project without exposure to the upstream gas field development or gas transmission development risks. Similarly for the electricity output side of the project, there is likely to be a developed wholesale electricity market with multiple potential buyers for the output of the station and a strong electricity grid with established transmission access and pricing regimes.

In the field-specific development scenario in Vietnam, in order for a gas fuelled power generating project to proceed to construction a complex web of interlinked contracts must be finalized. If any one of the contracts along the value chain fails, then not only the investment in the generating plant is at risk but also the equally large investment in the fuel supply development. Where the gas field being developed has a high level of liquid production, then the liquids revenue, which often exceeds the gas revenue, is also jeopardized if part of the value chain is not completed. This value chain and the major contracts required for an interlinked gas field and power station development are shown in Exhibit 3-1 below.

Exhibit 3-1: Gas and Electricity Development Contr acts


GasTransmission

PowerStation



Energy Flow

GasWholesaler

GTA

PPA

TCA

GSAGSPA





FinancingAgreements

GSPA – Gas Sale and Purchase AgreementGSA – Gas Sales AgreementGTA – Gas Transport AgreementPPA – Power Purchase AgreementTCA – Transmission Connection Agreement

BOTAgreement

3. BOT Development Risks and Mitigation

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The above flow chart excludes the many other smaller contracts that are required, such as site purchase, market participation, water supply etc. For a development of this type this family of contracts is signed contemporaneously or there is a condition precedent clause in the contracts such that they do not come in to effect until the last contract is signed.

3.2 RISKS AND RISK MITIGATION FOR THE BOT DEVELOPER IN THE GAS-TO-POWER VALUE CHAIN

With highly interlinked developments such as field specific power generating projects there are many risks that could cause delays or problems with reaching commercial operation. Some of these delays are common regardless of the development modality of the generating plant, while others are specific to a BOT development modality, and yet others are unique to gas-fired projects.

The flow chart in Exhibit 3-2 below maps the process for implementing a BOT project and highlights the development risks that must be addressed for a successful project.

Exhibit 3-2: BOT Development Risks

MOITProcures

BOT


NegotiateBOT

Agreement


NegotiatePPA

PowerPlant

Developed


Agreement

EPCContract


GasFieldDeveloped



1

Risks

2

3

4

5

6 10

9

7

8

Exhibits 3-3 and 3-4 below identify these risks, quantify the impact on the affected parties and identify mitigation mechanisms. Exhibit 3-3 covers those risks that are specific to the gas aspects of a gas-fired BOT project, and Exhibit 3-4 covers risks common to all forms of thermal BOT projects. The Risk No. is from Exhibit 3-2 above.


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Exhibit 3-3: Gas-Specific BOT Development Risks, I mpacts and Mitigation

Risk No

Risk Impact Mitigation

5A Unable to negotiate GSA

No contract, no project

Thorough GMP process to ensure likely gas price allows a generation project to proceed.

Indicative gas price in BOT tender documents.

Draft GSA in tender documents

5B Protracted GSA negotiations

Project cost escalation

As 5A above

Facility to update PPA for changes in EPC contract price.

6A Unable to negotiate GTA


Standard gas transmission pricing and access regime.

Draft gas GTA in BOT tender documents.

6B Protracted GTA negotiations


As 6A above

Facility to update PPA for changes in EPC contract price.

9A Gas Field development delayed

BOT developer has to meet obligations under PPA and financing agreements

Liquidated damages clauses in GSA contract

PPA provides for fixed cost payments to BOT developer if unavailability is not developer’s fault

9B Gas field does not deliver at required rate or for the contracted time

BOT developer has to meet obligations under PPA and financing agreements

Force Majeure under PPA and financing agreements

Liquid fuel back-up

Reserves assessments to international standards

PPA provides for fixed cost payments to BOT developer if unavailability is not developer’s fault

10 Gas transmission not available at commissioning

Project not able to operate

Liquidated damages in the GTA

Developer stake in the gas transmission construction

Liquid fuel back-up


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Exhibit 3-4: Common Thermal BOT Development Risks, Impacts and Mitigation

Risk No


1A Unable to agree PPA price and terms


Thorough PMP process to check project viability before BOT tender. Indicative wholesale electricity price in BOT tender documents. Draft PPA in BOT tender documents Use competitive tendering to minimise need for price negotiations

1B Protracted PPA negotiations


As 1A above Facility to update PPA for changes in EPC contract price.

2A Unable to agree TCA price and terms


Standard electricity transmission pricing and access regime. Draft TCA in BOT tender documents.

2B Protracted TCA negotiations



3A EPC contract price varies

Increased cost to BOT contractor

Efficient BOT process to keep period from tender to approval of BOT and other contracts short. Facility to update PPA for changes in EPC contract price.

4A Unable to agree BOT contract terms


Standard BOT contract in BOT tender documents.

4B Protracted BOT negotiations



7 Electricity transmission not available at commissioning


Liquidated damages in the TCA Developer stake in the transmission construction

8 Power station commissioning delayed

BOT developer has to meet obligations under PPA, GSA, TCA and GTA

Liquidated damages clauses in EPC contract

Some of these risks will be mitigated by the work that ERAV is undertaking in areas such as an open access regime for electricity transmission, the development of market rules, regulated retail tariffs, and standard transmission connection agreements. But, until the


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CGM is implemented and the details of the new regime promulgated, the institutional uncertainty increases the risk to the BOT developers. The CGM is now likely to be implemented in 2010 or later.

3.3 INSTITUTIONAL MEASURES TO REDUCE BOT DEVELOPMEN T RISK

There are a number of ways that the government (through MOIT) can reduce the risks in the BOT development process. These arise from the government’s control of the planning process and of the BOT developer selection process.

The first way to reduce BOT developer risk is to build the confidence of the developers in the energy sector planning processes and the selection of the projects for BOT development. This requires a robust and dynamic planning process.

Recommendation 1

Develop a robust process of gas and electricity planning to ensure that the projects that proceed through to BOT development are viable in the electricity and gas markets that prevail at that time.

The second way to reduce the BOT development risk is to ensure that when the BOT tender documents are released they are comprehensive and provide the developer with clear guidance on all aspects of the project. This is under the government’s control through the Inter Branch Working Group (IBWG) that issues the BOT tender documents.

Recommendation 2

Spend the necessary time before the BOT tender documents are issued to prepare a comprehensive set of draft contract documents covering the BOT contract, GSA, PPA, GTA and TCA.

If these recommendations are accepted then it should be possible to complete the process of tendering and contract negotiation quickly, before the project is affected by major changes, such as the price of steel or the availability of manufacturing plant for gas turbines. Lengthy contract negotiation and award processes inevitably lead to problems as the surrounding markets change.

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4. MECHANISMS TO IMPROVE COORDINATION OF GAS AND EL ECTRICTY PLANNING

4.1 GAS AND ELECTRICTY PLANNING IN AN IDEALISED MAR KET

In an ideal energy market scenario the following conditions would prevail, allowing an open and free flow of information to allow market participants to make considered and rational decisions on gas field development and generation investment. These conditions include:

• A competitive generation market with a clear set of rules that also allows demand side response.

• A competitive retail electricity market that reflected generation prices.

• A competitive gas market with a clear set of rules.

• Separation of the monopoly sections of the gas and electricity businesses (transmission and distribution) with economically efficient tariffs and open access.

• A regulatory regime for monopoly sections of the industry and a light handed regulatory regime for the competitive sectors.

These ideal conditions do not exist in Vietnam, or in any other country, but there are moves under way to address some of these issues. Currently some of the constraints in Vietnam are:

• Competitive generation market – this is being developed but the full details are not yet known. At this stage a market simulation model hasn’t been developed to model the impact of the new market structure and the various rules, service charges and bid caps quantified.

• Open access regime for electricity transmission – this is being developed by ERAV and EVN, and the basic structure of the transmission regime has been established. However the new pricing regime has not been quantified and the model contracts are still under development.

• Open access regime for gas transmission – this issue is yet to be addressed.

• Competitive gas market – this issue is yet to be addressed.

• Regulatory regime – with the establishment of ERAV progress is being made in electricity but there has been no work yet on the gas industry.

In order for gas and electricity planning coordination to improve progress needs to be made on removing the constraints identified above. Some of this work is now under way, particularly in the electricity sector, but the impact of this work will not be known until late-2009 when the studies have been completed, the market rules finalized and the CGM market simulation model completed.

4. Mechanisms to Improve Coordination of Gas and Electricty Planning

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4.2 GAS PLANNING

4.2.1 Updating the GMP

The GMP process is based around a 5 year cycle, and once the plan is approved this is essentially locked until the next major review. Whilst this may have been satisfactory in an environment where change was slower, it is not adequate when there are rapid changes occurring in the international energy markets that affect Vietnam. In the past Vietnam has been somewhat insulated from the world energy markets through the use of hydro generation, indigenous gas and indigenous coal. Going forward the country will be more exposed to international energy prices, as to meet the forecast growth for energy imported coal, LNG or nuclear generation will be needed.

To be an effective tool for managing development, the GMP must be prepared in coordination with the PMP and approved quickly (or it will no longer be current by the time it is approved), and a process of annual review and update established. This annual review and update should address such things as changes in reserves, project timing, gas price and forecast demand as a result of further information that has become available in the preceding 12 months, and should update the key tables, charts and development programs. It would not normally address gas policy issues, which would normally be covered in the five yearly revision of the GMP. The results of the annual review should be published as an addendum to the GMP.

This update of the GMP should be closely coordinated with the update of the PMP, as the majority of the gas demand comes from the electricity sector.

Recommendation 3

That the GMP should be completed promptly, a process of annual review and update established, and the results of the annual review should be published as an addendum to the GMP.

4.2.2 Gas Price Formation

The quality of the information passed from the gas planning process to the electricity planning process is critical to success of the electricity least cost generation expansion planning model. The critical information required for successful electricity planning is

• Reserves quantity

• Delivered gas price

• Timing of development

To date there have been no particular issues with the reserves quantity information. The new developments have been identified and there is a program of further field development to ensure that the existing pipeline capacity is fully utilized. This is well covered in the draft SGMP.

The problem area is around price formation for new gas supplies. The practice of forecasting prices on the basis of earlier developments has resulted in an underestimation of the cost of gas, and therefore delays when it comes to contract negotiation and the expectations of all parties are not met. The gas cost for a particular field development will depend on factors such as the reservoir characteristics, the gas/liquids ratio, location, gas quality, water depth etc and the world market for oil and gas equipment. The development


4-3


specific factors and their associated costs must all be considered when developing a price forecast for gas. This is particularly true in the current market where offshore construction costs have escalated rapidly.

Gas price problems are causing delays to projects and consequent shortages of generation in the electricity market.

A process to develop an indicative gas price during the gas field development and how it should interact with gas planning is shown in Exhibit 4-1 below.

Exhibit 4-1: Flow Chart Gas Field Development and Gas Planning

PSCDiscovery

Draft ReservesAssessment


GOV InitialApproval

Final ReservesAssessment


GOV FinalApproval

ProjectDevelopment

GMP Preparation

GMP AnnualUpdate

Initial Price and ReservesInformation

Updated Price and Reserves Information

Initial GasPrice and ReservesInformation to PMP

Updated GasPrice and Reserves Information to PMP

The price formation should be a two stage process, with an initial indicative gas price based on an expected rate of return on field development costs being prepared off the outline field development plan and provided to those preparing the GMP. When the final field development plan is prepared then an updated indicative gas price can be provided to the GMP team for incorporation in the next GMP update. These gas prices are indicative prices based on field development costs, and will not be the contracted gas prices that result from the gas contract negotiations.

Recommendation 4

That for new field developments a two-stage gas price formation process driven by the outline field development plan and the final field development plan be utilized to provide more accurate gas price information to the gas and electricity master planning process. These estimates can later be replaced by contract prices once known.

4.2.3 Stakeholder Consultation

There are many stakeholders in the gas market in Vietnam, and this number is increasing as competition is introduced to the electricity market and new sources of capital are sought to fund the rapid addition of generating plant necessary to meet the growth in


4-4


electricity demand. The number of stakeholders will increase even further as changes are made to the gas industry and if a wholesale gas market is developed.

Some of the key stakeholders for the gas industry are:

• MOIT

• EVN

• PVN

• IPP developers

• BOT developers

• End use customers

• PSC partners

• ERAV

• Financiers

• Development agencies

For the GMP process to be effective all of these stakeholders must be consulted and their views and needs incorporated in the planning process. This is best achieved by a formal consultation process with feedback to the parties as the planning proceeds.

This consultation could take the form of a kick-off workshop where the key policy parameters and a review of the present gas position are presented. Participants could then table their key concerns and issues and follow with written submissions. This could be followed by a mid-planning cycle workshop where the initial planning results are presented, and then a final workshop to present the GMP following GOV approval.

For the annual GMP review process stakeholder consultation is also important. The review process is shorter and not as wide ranging as the preparation of the GMP, and a single workshop at the commencement of the process would be sufficient. This workshop would allow stakeholders to express concerns about issues in the current GMP and identify issues that should be addressed in the review.

Recommendation 5

That there be greater stakeholder consultation in the preparation of the GMP and that a formal structure of stakeholder consultation through workshops be implemented.

4.2.4 Gas Industry Restructuring

The gas industry is dominated by PVN, which is involved in all segments from production to end use. If there is to be greater competition introduced to the electricity industry through gas-fuelled BOT generation projects, then changes will be required to the gas industry to allow greater competition and an open access transmission regime as discussed in Section 2.6.


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To help formulate policy for the reform of the gas industry reform a road map is required, similar to the road map that was prepared for introducing competition to the electricity industry. Changing the role and status of monopoly state-owned oil companies has been contentious in virtually every country that has taken on the challenge, but those that have done so have reaped substantial rewards.

The roadmap process should also include a cost benefit analysis of establishing a national pipeline gas standard, the interconnection of the producing fields and the option of a gas pool pricing mechanism.

Recommendation 6

That a road map be prepared for the introduction of greater competition to the gas industry in Vietnam, with a view towards accelerating gas utilization and contributing to the successful operation of the electricity market.

4.3 ELECTRICITY PLANNING

4.3.1 Electricity Load Forecasting

The PMP forecasts electricity growth rates of 16.0% over the period 2006-2010, reducing to 11.0% over the period 2011-2015, 9.1% over the period 2016-2020, and 8% over the period 2016-2020. These are very high growth rates and require a corresponding major expansion of generating capacity, which through the least cost generation expansion planning process are driving the high demand for gas and coal in Vietnam.

Because these forecasts underpin a very large capital expenditure program for electricity generating plant, gas field development and electricity transmission and distribution systems, it is essential that they be as accurate as possible. If these forecasts are too high, there will be an excessive allocation of scarce capital resources to the energy sector at the expense of the economy in general.

As for all other aspects of the PMP, the load forecasts should be reviewed annually and the revised forecasts used for the annual PMP update. Because of the impact of the forecasts on the gas and electricity sectors, an independent expert review should be undertaken to benchmark the process going forward. This is particularly important since IoE, which prepares the forecasts and drafts the plan, is a subsidiary of EVN, the major player in the sector.

Recommendation 7

That an independent expert review of the electricity load forecasts be undertaken to establish a benchmark forecast for the ongoing annual PMP review process.

4.3.2 Updating the PMP

As for the GMP, the PMP process is based around a five year planning cycle. The current PMP is the sixth such plan and preparation of the seventh plan has commenced. There are occasional updates of the PMP, but the results are not published in a formal way.

To be a more effective tool for managing development, the PMP needs a process of annual review and update. This annual review and update should address such things as changes in project timing, demand forecast, fuel availability and price, and electricity transmission development based on the further information that has become available in the preceding 12 months. It should update the key tables, charts and development


4-6


programs, and these should be published as an addendum to the PMP. It would not normally address electricity policy issues, which would be covered in the five yearly revision of the PMP.

This annual review, which will need to be integrated with the planning under the CGM least-cost planning procedures being developed by ERAV and the annual review of the GMP, will allow closer integration of gas and electricity planning as new information on gas prices becomes available as the PSC partners finalize the field development plans. At the same time the PMP planners are able to provide information to the GMP planners about expected electricity demand and prices, and the gas fuelled generation projects that may therefore be economic to develop.

Recommendation 8

That a process of annual review and update be established for the PMP, and that the results of the annual review should be published as an addendum to the PMP.

4.3.3 Least Cost Generation Planning

At the core of the PMP is a least cost generation expansion plan that produces a list of projects that need to be developed in order to ensure that the forecast demand for electricity is met. This least cost plan is developed using recognized international planning software packages. Critical inputs to this process are the capital cost of the various types of plant, the plant efficiency, the fuel cost, and the operations and maintenance costs.

For PMP6 the fuel input costs were low and resulted in a plan that is struggling to be implemented. Two coal fuelled projects and a gas fuelled project have been negotiating their fuel supply contracts for some years. The two stage gas price formation process outlined in Section 4.2.2 above will provide a more accurate gas price forecast for the least cost planning process until a negotiated gas contract price is known. This, combined with the annual update process for the PMP, should ensure that the list of projects to be developed reflects the prevailing market conditions.

Note that under the CGM the least cost planning may shift from the PMP process to the CGM least-cost generation planning procedures, but the same recommendation applies.

Recommendation 9

That the output from the two-stage gas price formation process recommended for the GMP be used as the input gas price for the PMP development process and CGM least-cost planning procedure until the negotiated gas contract prices are known.

4.3.4 Electricity Price Discovery

The PMP process produces a least cost development plan for generation expansion, but doesn’t compare the cost of generation from the selected stations with the prevailing wholesale price for electricity. This means that some of the least cost developments may result in major increases the wholesale price. If EVN, or the Single Buyer in the future, as the counterparty to the PPA, purchases the output of such a station they may not be able to recover the cost of purchase from the retail tariff. Whilst this may be satisfactory for small purchase volumes, it will lead to major trading losses if allowed to happen frequently.


4-7


To avoid this situation the PMP should be extended to include a section on the wholesale price profile that will result from the least cost development plan. This will allow ERAV and GOV to clearly see the impact of new generation on the wholesale electricity price and the need for retail tariff rises. This process of price discovery will be greatly improved if ERAV develop a market simulation model and the BNE process established under the CGM.

The process for developing a wholesale price forecast within the PMP is illustrated in the flow chart in Exhibit 4-2 below.

Exhibit 4-2: Development of a Forward Wholesale El ectricity Price Curve

Fuel Quantity andCost Forecasts

Thermal PlantCapital CostEstimates

O & M CostEstimates

Hydro ProjectCost Estimates

Least CostModelling

Least Cost Development List

WholesaleElectricity

Price Model

ForwardWholesale

Electricity PriceCurve

This forward price curve for wholesale electricity can then be utilized by MOIT in the development of energy policy and as an input to other economic planning processes, particularly for industry developments that have a high energy requirement.

Recommendation 10

That the PMP process be extended to cover the development of a forward price curve for wholesale electricity in conjunction with an ERAV market simulation model.

4.3.5 Stakeholder Consultation

There are many stakeholders in the electricity market in Vietnam, and this number is increasing as competition is introduced in to the electricity market and new sources of capital are sought to fund the rapid growth in generating plant necessary to meet the growth in electricity demand. Some of the key stakeholders for the power industry are:

• MOIT

• EVN

• PVN


4-8


• IPP developers

• BOT developers

• Distribution companies

• End use customers

• PSC partners

• ERAV

• Financiers

• Development agencies

• Peoples Committees

For the PMP process to be effective all of these stakeholders must be consulted and their views and needs incorporated in the planning process. As with the GMP process, a similar set of stakeholder workshops should be held for the PMP planning process and for the PMP review process.

Recommendation 11

That there be greater stakeholder consultation in the preparation of the PMP and that a formal structure of stakeholder consultation through workshops be implemented.

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5. CASE STUDY – THE O MON – BLOCKS B, 52/97 AND 48/ 95 DEVELOPMENT

5.1 OUTLINE OF THE CASE STUDY

This case study looks at the development process for the O Mon – Blocks B, 52/97 and 48/95 development. Whilst the history of this development as presented here is a simplified version and may not be correct in every detail, it serves to illustrate how the present master planning processes are working and how they can be enhanced to move from a static planning process to a more dynamic process that can respond quickly to changes in the energy market.

In the enhanced planning process it is suggested that the preparation of the GMP and PMP be completed quickly in a coordinated manner and that both are then updated annually to incorporate new market information. This, combined with a two stage gas price discovery process and the electricity generation planning procedures that ERAV are planning to introduce under the CGM should result in a more open and transparent planning process that provides more accurate and up to date information to the market, to the benefit of all current and potential market participants such as BOT project developers and financiers.

The final part of the case study looks at international experience, particularly Thailand and Indonesia, as they have experienced many of the problems that Vietnam is now experiencing.

The outcome under the enhanced planning process for the O Mon – Block B project may not have been any different from that currently experienced, but the end point would have been arrived at in a more open manner and all participants would have been more aware of the risks as they proceeded along the development path.

5.2 THE EXISTING PLANNING PROCESS

The electricity market in Vietnam is moving through a period of change from a fully centrally planned model towards a regulated competitive market. Nonetheless, a Government master plan will continue to provide overall planning guidance, through the application of a least cost generation expansion planning model and decisions on which stations will be built where, when and by whom to meet the forecast load demand. In numerous cases developers will need to compete to build and operate these stations, and as discussed in Volume 2 there should be a more transparent process to determine the plant development modality (EVN, IPP or BOT) and mandatory use of competitive bidding in all but the most exceptional cases. This process is continually evolving as the CGM is introduced, and the processes described here are a snap-shot in time of this market.

There is no gas market in Vietnam. PVN has a monopoly position as a field development participant and single buyer under the PSCs, a monopsony position as the sole bulk seller, and is an end use customer, e.g. as a power generator. Despite this, a planning process has started with the preparation of the draft SGMP and now the draft GMP, and the gas sector will then be part of the five year planning process.

The existing planning processes may best be characterized as one of silos. The upstream field development planning, the gas master planning and the electricity master planning operate largely in isolation with limited interaction. This lack of interaction is exacerbated by the five year master planning process. Once completed the master plans are essentially fixed for five years and there is only limited updating, at least available publicly.

5. Case Study – the O Mon – Blocks B, 52/97 and 48/95 Development

5-2


The process for the O Mon Development is illustrated in Exhibit 5-1 below. This shows what appears to have happened: the field development plan, the GMP and the PMP have largely proceeded in isolation and have not really come together until the parties sat down to negotiate the GSPA. Once these negotiations got under way it was found that the gas price from the field was high, the generating plant had increased in cost, and the field development was not viable at the current gas price (which is essentially a reflection of electricity price) expectations. The result has been a protracted GSPA negotiation, and all the O Mon generating plant is slipping behind schedule in the PMP, adding to the shortage in generating capacity going forward.

Exhibit 5-1: Current Status of GMP and PMP Planning Process

If there had been greater coordination of the field development, GMP and PMP processes, as recommended below, then the problem would have been identified earlier and either another project would have displaced the O Mon projects in the least cost development plan or other measures could have been taken to ensure that everyone received an adequate return along the gas-to-power value chain.

5.3 THE PROPOSED PLANNING PROCESS

Under the proposed planning process the GMP and PMP planning processes change from static processes to dynamic processes, with annual updates of the plans and a two stage gas price discovery process. For a newly discovered field the two stage gas price discovery process allows an initial view of the gas to power value chain to be taken at the time of the initial field development plan preparation, and if there is insufficient value along


Discovery

PM Approval



PM Approval



MOIT Contracts IP

Draft SGMP Reviewed

Draft SGMP

MOIT Contracts IE


Draft PMP

MOIT Review

PM Approval


Demand Forecast




5-3


the chain for all participants then actions can be taken early to enhance the returns to the affected parties or the project will drop out of the PMP when the least cost generation development model is next run.

The two stage gas price discovery process and its interaction with the upstream field development processes is illustrated in Exhibit 5-2 below.

Exhibit 5-2: The Two Stage Gas Price Discovery Proc ess

If the development passes this initial test then the gas resource can be included in the next iteration of the PMP and GMP. The parties can then refine their cost estimates, reserves and development plans, and the value chain can be checked again once the final field development plan and reserves estimates are completed. This dynamic planning process is illustrated in Exhibit 5-3 below.

Exhibit 5-3: The Enhanced GMP and PMP Planning Proc ess

Discovery

Is Indicative Gas Price

OK?

Initial ReservesAssessment


No

Yes

Reduce Field Development

Costs



Is Updated Gas Price

OK?No

Yes


Costs

GMPProcess

GMPAddendum


Model


Model


Discovery

PM Approval



PM Approval



MOIT Contracts IP

Draft GMP

Demand Forecast

MOIT Contracts IE


Draft PMP

MOIT Review

PM Approval


Demand Forecast

Gas Reserves Information


MOIT Approval

PM Approval

Supply Forecast

Electricity gas demand information

Gas Price Information


5-4


For a BOT development it is essential that issues around pricing are fully understood and that only projects with a high expectation of success proceed to BOT tender. The BOT tender process is very expensive for the country and for the bidders, and the BOT process will loose credibility with developers if the projects always strike problems.

In the event of a project striking problems, such as seems to be occurring with O Mon, there are a number of ways that the government can facilitate the process if it is felt to be in the national interest for that gas field to be developed. These include the deployment of legal and contractual mechanisms to provide fiscal relief, special tax and royalty arrangements for the PSC partners for that field, and special arrangements for the BOT developer such as tax measures.

Following a more interactive planning process and annual updates of the GMP and the PMP, the outcomes for the Block B – O Mon development might have been:

• That O Mon was dropped from the least cost development plan and replaced by another gas plant having cheaper gas or a coal plant, or

• The field developers might have found an alternative higher value use for the gas, or

• O Mon may have retained its position in the least cost generation development plan, but wholesale electricity prices were adjusted upwards to accept higher cost new generating plants.

5.4 INTERNATIONAL EXAMPLE - THAILAND

5.4.1 Energy Policy

Thailand has embarked on a wide ranging reform of the energy sector with the objective of making it more competitive and transparent. The sector has long been dominated by the two state monopolies, Electricity Generating Authority of Thailand (EGAT) and Petroleum Authority of Thailand (PTT). In 2001 PTT was corporatized and conducted an Initial Public Offering of shares that resulted in the company being listed with 47% public shareholding and in 2005 EGAT was corporatized, but this corporatization has now been revoked and EGAT is a statutory corporation. The Ministry of Energy was established in 2002 with overall responsibility for the sector, and established the Energy Policy and Planning Office (EPPO).

A new Energy Industry Act came in to effect in December 2007. This act establishes a new regulatory regime for the electricity and gas sectors. One of the objectives of the act is to separate policy making, regulatory and operational functions in the sector. To this end an Energy Regulatory Commission has been established to prevent abuse of monopoly powers, protect the consumers’ interests, and regulate prices. The Commission will issue licenses for all participants in the industry. Draft regulations under the new act are currently under public consultation.

Thailand has conducted two solicitations for bids for IPP projects. The first in 1994 resulted in seven PPA contracts being signed and all projects obtained finance. The second solicitation for 3,200 MW of base load capacity was released in June 2007, and four winners for 4,400 MW of capacity were announced in December 2007. The PPAs for these projects are expected to be signed shortly. The solicitation process was conducted by EPPO using an electronic process with standard form PPA documents and known clear evaluation and award procedures.


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5.4.2 Power Sector Planning

In Thailand there are three state entities involved in electricity – EGAT as the state generator and transmission company, and the Metropolitan Electricity Authority (MEA) and the Provincial Electricity Authority (PEA) as distribution and retail companies.

Power sector planning is well advanced, with the latest Power Development Plan (PDP 2007) covering the period 2007 – 2021 approved by the National Energy Policy Council (NEPC) and endorsed by Cabinet in June 2007. To cope with the changes in the demand forecast, the new IPP solicitation and changed imports from neighboring countries, a revised plan called PDP 2007 Revision 1 was submitted to NEPC for approval in December 2007. This shows how a more dynamic approach to planning can adapt to market changes.

The PDP is prepared by EGAT under the policy framework of the Ministry of Energy which includes addressing reliability of power supply, fuel diversity, power purchases from neighboring countries, demand forecast etc. Thailand is a non-Annex 1 country, but regardless is trying to address global warming issues. To prepare the PDP the normal processes of developing a least cost generation expansion plan are followed and a corresponding grid development plan is prepared.

The national load forecast, critical to the success of any generation expansion planning, is prepared by the Thailand Load Forecast Sub-Committee. This process allows wider participation in the development of this critical forecast than if it had been prepared by EGAT alone. Demand is expected to grow at 5.7% per year, down from earlier levels of around 13% per year from 1986 to 1997.

Although there have been plans to introduce a competitive generation market in Thailand and to restructure EGAT to separate the monopoly transmission functions from the generation functions, these have not been implemented.

5.4.3 Gas Sector Planning

The gas industry is dominated by PTT which is a vertically integrated company covering upstream, gas transmission and distribution, gas retailing, and a wide range of activities in refineries and liquid fuels and chemicals. The gas infrastructure in Thailand is more developed than in Vietnam, with a total gas transmission pipeline length offshore of 1783 km and onshore of 1397 km. This gas transmission network includes pipelines linking Thailand to Malaysia and Myanmar. Electricity generation, by both IPPs and EGAT, is the major use for natural gas in Thailand, using 71% of production.

The extensive infrastructure and the linking of many different gas fields has allowed PTT to establish a gas pool price, and the gas price for EGAT and the IPPs is the pool price plus 1.75% supply margin plus a fixed transmission tariff. This extensive transmission network means that any one generating plant is not wholly dependant on the development risks of one field. Despite the well developed upstream resources, the country is planning for an LNG import terminal, to prepare for the eventual production decline from the indigenous fields.

Because PTT is vertically integrated, gas sector planning is internalized. For the preparation of the PMP, PTT has provided an estimate of the gas availability for power generation and the price. This information has been used in the least cost generation expansion planning.


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5.4.4 Lessons from the Thailand Experience

Although the energy industry in Thailand is larger and further developed than in Vietnam, the same major issues are present. In some areas Thailand has made greater progress but in most they are struggling with the same issues.

The following lessons are relevant for Vietnam:

• It requires great political determination to carry through regulatory reform in the energy industry.

• Separation of the functions of policy development, regulation and company operation is important.

• Even if a degree of competition is developed in the energy markets regulation is still required, particularly for the monopoly aspects of the industry. One regulatory authority covering gas and electricity is an effective way of reducing overheads and ensuring that similar regulatory regimes are established for both energy types.

• Open access regimes with regulated published tariffs are required for gas and electricity transmission to minimize bottlenecks and improve timeliness and efficiency.

• The benefits of establishing a national gas quality standard, linking the various gas sources and establishing a gas pool price should be investigated.

• Master Plans should not be fixed, but should be revised as market conditions change.

• An open and participative process is required to develop the load forecast that underpins the PMP.

• With well prepared standard contracts and fuel and electricity price information a BOT tender process can proceed to signing quickly.

Vietnam is proceeding along a roadmap for electricity sector reform and, if a similar roadmap was prepared for gas sector reform, could establish a well planned energy sector able to meet the changes ahead.

5.5 INTERNATIONAL EXAMPLE - INDONESIA

5.5.1 Gas Industry Prior to Reform

The oil and gas industry in Indonesia up until 2004 was structured in a very similar way to that in Vietnam. Pertamina was the state oil and gas company and had a very similar role to PVN. It operated across all sectors of the gas industry and:-

• Functioned as mandatory partner to the foreign PSCs

• Prepared exploration blocks for tender

• Negotiated, signed and supervised PSC contracts

• Purchased all gas produced


5-7


• Transported and sold all gas

The president of Indonesia approved the award of block contracts following the tender process, in a similar way to the Prime Minister approving such awards in Vietnam. The industry had a degree of regulation by the Director General of Oil and Gas through the setting of tariffs. This industry structure is shown in Exhibit 5-4 below.

Exhibit 5-4: Indonesia Pre-2004 Gas Industry Struct ure

5.5.2 Gas Industry Reform

The Indonesian Oil and Gas Law No 22/20014 completely restructured the oil and gas industry as shown in Exhibit 5-5 below. Pertamina is now treated the same way as any other oil and gas company under the PSC regime, and foreign oil and gas companies are no longer required to partner with Pertamina under a PSC.

A new government body, BP Migas, was established to be the counterparty under the production sharing contracts and to sign and supervise the PSCs. A new regulator for the downstream industry, BPH Migas, was established to set pipeline tariffs and retail tariffs for small customers. The Director General of Oil and Gas now develops policy, standards and processes for the oil and gas sector, and offers new exploration blocks and manages the upstream data.

Domestic gas sales are now contracted on a direct basis between the gas producer and the end-use customer. A Domestic Market Obligation has been introduced to ensure that gas is available for the domestic market rather than all of it being exported as LNG or via pipeline.

4 Though the law was enacted in 2001, implementing regulations and fundamental changes in the industry did not occur immediately. It is probably more accurate to view 2004 as the year in which these reforms began to take effect.

Pertamina

Pertamina

Gas Producers

Gas flows

ConsumersOil and gas producers include:� Total FinaElf� ExxonMobil� VICO� BP� ConocoPhilips� Unocal� Caltex� PetroChina

Gas Producers

Gas Producers

Gas Producers

Foreign PSCs

LNG

Directorate General of Oil & Gas

“Migas”

Sets tariffsAwards & supervises PSCs; partner with all PSCs

President of

Indonesia

Approves block tender awards


5-8


Exhibit 5-5: Indonesia Current Gas Industry Structu re

These gas industry reforms have resulted in rising gas prices, but consumption has grown greatly as the reforms have eliminated or reduced bottlenecks to availability. (See Exhibit 5-6 below). Customers can now clearly see the prices for production, transport and retailing and can negotiate their gas supply contracts directly with the gas producers. Gas producers can now market and sell their output directly to consumers, reducing the time required and risks involved compared to previously going through a single buyer.

Exhibit 5-6: Indonesia Gas Sales Price and Volume

5.5.3 Lessons from the Indonesia Experience

Indonesia has made considerable progress with the reform of their gas industry. The following lessons are relevant for Vietnam:

• It is possible to reform a county’s gas industry even when it is controlled by a powerful monopoly. Such reform can result in greater benefits for the entire economy.

Natural Gas Consumption

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Year

MMSCF

0

1

2

3

4

5

6

7

USD/MMBTU 1,000KMs

Domesticconsumption inMMSCFPrice inUSD/MMBTU

Pipeline length in1,000 KM

New Oil & Gas Law

Operationalization of new agencies

Typical gas prices prior to Law 22/2002

Typical current gas prices

Pipeline Companies,

e.g. PGN

Gas Producers

Gas flows

Consumers

Upstream Implementing Agency

“BP Migas”Signs & supervises PSCs; Appoints sellers of Gov’t share

Oil and gas producers include:� Total FinaElf� ExxonMobil� VICO� BP� Pertamina� ConocoPhilips� Unocal� Caltex� PetroChina

Gas Producers

Gas Producers

Gas Producers

Oil & Gas Producers

LNG

Downstream Regulator

“BPH Migas”


“Migas”

Sets pipeline & retail tariffs for small consumers

Develops sector policies, standards & processes;

Offers new blocks; Manages data

Energy Conversion

Companies, e.g. small power

plants or LPG processors

Gas products (e.g. LPG) or

Electricity


5-9


• Gas consumption can increase greatly even if gas prices rise, since higher prices may be necessary to increase availability.

• Large end-use customers and gas producers both benefit from direct negotiations for gas supply in terms of availability, timeliness and price.

A-1


APPENDIX A: ASSIGNMENT TERMS OF REFERENCE

This appendix presents the terms of reference for the assignment.

TORs: Study for the Development of the Power Market and Competitive Tender Framework for Thermal IPPs in Vietnam 1

STUDY FOR THE DEVELOPMENT OF THE POWER MARKET AND COMPETITIVE TENDER FRAMEWORK FOR THERMAL IPPS IN

VIETNAM

TERMS OF REFERENCE

TABLE OF CONTENTS

1. INTRODUCTION.......................................................................................................................3 2. BACKGROUND.........................................................................................................................5 3. OBJECTIVES OF THE CONSULTANCY................................................................................7 4. SCOPE OF WORK .....................................................................................................................9

4.1 TASK 1: ASSESSMENT AND INCEPTION REPORT.......................................................9 4.2 TASK 2: FRAMEWORK FOR INTERNATIONAL COMPETITIVE TENDERS OF

THERMAL IPPS ...................................................................................................................12 4.3 TASK 3: STRATEGY TO INTEGRATE IPPS IN THE POWER MARKET ..........................14 4.4 TASK 4: ANALYSIS AND COORDINATION OF NEW GAS FIRED GENERATION

WITH DEVELOPMENT OF NATURAL GAS RESOURCES. .........................................................16 TASK 5: FINAL REPORT......................................................................................................18

5. ORGANIZATION AND WORKPLAN ...........................................................................19 5.1 COORDINATION AND WORKING GROUP..................................................................19 5.2 WORKSHOPS...........................................................................................................19 5.3 REPORTING.............................................................................................................20 5.4 WORKPLAN ............................................................................................................20


STUDY FOR THE DEVELOPMENT OF THE POWER MARKET AND COMPETITIVE TENDER Framework FOR THERMAL IPPS IN VI ETNAM

TERMS OF REFERENCE


1. INTRODUCTION Vietnam is experiencing fast growing economic development that, among other things, impacts the power sector with electricity demand growing at very high rates. Since 1990, power generation increased fivefold from 8.7 TWh in 1990 to 46.2 TWh in 2004 and 53.6 TWh in 2005, an annualized growth rate of 12.5%. Load growth has been faster and load forecast scenarios have been revised. In the latest power master plan, demand is expected to grow during 2006-2010 around 15 – 16 % per annum and then in the period 2011-2015 around 11%. To meet the forecast demand, installed generation capacity is required to increase from around 11,000 MW in 2004 to more than 25,000 MW by 2010. This means that the system must add over 2,700 MW per annum during the period 2005 to 2010. Electricity of Vietnam (EVN) is the dominant electricity utility that owns hydro and thermal generation, owns and operates transmission and some distribution systems. EVN has been developing and implementing an equitization program1, included in which are thermal power stations. As the first steps in the equitization program, hydro power plant of 135 MW aggregate capacity, a pilot provincial distribution utility and two thermal power plants, including 1000 MW Pha Lai coal power plant, have been equitized. Vietnam’s Electricity Law, which was passed in November 2004 and went into effect in July 2005, set in motion a large-scale reform program in the electricity sector and assigned to the Ministry of Industry (MOI) the responsibility of preparations for restructuring and power market development. The Law provides for a market-oriented electricity industry, the restructuring of EVN, and the establishment within the Ministry of Industry of a separate unit for regulation of the power sector. The Electricity Regulatory Authority of Vietnam (ERAV) has been created under the Minister, and its functions and organization has been established through a Prime Minister Decision. These include, among others, function on review and approval of PPAs and least cost generation planning. The Prime Minister has already approved the Roadmap for the formation and development of the Vietnamese electricity market, proposed and submitted by MOI. The Roadmap defines the overall plan for the market development through six phases of increasing competition: • First phase (2005-2009): An internal EVN generation competitive market is

operating as a trial market, for existing power plants within EVN. • Second phase (2009-2014): A generation competitive market (Single Buyer model)

for all generation companies. • Third phase (2014-2016): A pilot wholesale competitive market will be

implemented, with a limited number of distributors and wholesalers selected to participate in this trial market. It will be the transition step to the next phase with a fully wholesale competitive market.

• Fourth phase (2016-2022): Wholesale competitive market.

1 Equitization is converting a SOE into a shareholding company and selling shares to investors.


• Fifth phase (2022-2024): A pilot retail competitive market will be implemented, as a transition to the next phase with a fully retail competitive market.

• Sixth phase (from 2024): Retail competitive market.


2. BACKGROUND Between $1.5 billion to $2 billion per year of new financing will need to be mobilized to meet the rapid growth in demand during the balance of this decade. To achieving the targets in generation investment, greater reliance on more diversified sources of finance is essential, as well as attracting private investment, carefully design investment plans and coordinated development of fuel resources. In light of this, the Government of Vietnam (GOV) has initiated a comprehensive reform of the power sector, developed a roadmap for competitive power markets (the Roadmap), passed significant legislations for private foreign investors’ participation in BOT projects, and establishing new institutional arrangements. In 1997, the GOV had set a target of obtaining investment finance from private sources for 20% of generation. Until 2005, this target was met mainly through two foreign owned BOTs (gas fired generation) in the Phu My complex. Local non EVN owned generation has been developing, called local IPPs, mainly driven by State owned enterprises (SOEs). The IPP target has increased, with generation estimated roughly 33% from private sources and 66% from EVN. In particular, new foreign owned BOTs are planned. In addition to foreign-financed BOTs and local IPPs, there also needs to be greater reliance on non-government domestic sources of finance, through joint ventures, domestic bond issuance and equitization. As a way to increment the access to financial resources for generation expansion, the GOV contemplates that several thermal generation projects in the power sector master plan will be financed and developed with the participation of the private sector2. In particular, some thermal generation projects will be developed by foreign investors within the BOT framework. This legal framework is being revised to facilitate and improve further the investment climate and the development of BOT projects. The GOV has already successfully attracted private foreign BOT investment in two large gas fired generation projects, Phu My 2.2 and Phu My 3, with competitive bidding for Phu My 2.2. These experiences provide the basis for further thermal generation BOT tenders, and also valuable lessons on the challenges and need for efficient coordination between least cost generation plans and natural gas planning and developments. Although there have been no competitive tenders for large generation projects since Phu My 2.2 and new generation built by private investors or SOEs have been agreed in direct negotiations, the intention of the MOI is to introduce greater transparency and predictability in IPP transactions, as can be obtained by competitive tenders and by mechanisms and strategies that protect a smooth future integration of the IPPs into the power market at its later stages with increasing competition. After the successful experience in the competitive tender of Phu My 2, the MOI is in the process of launching an international tender for thermal generation (possible coal fired) by a foreign investor as a BOT project. For this specific project, the MOI has contracted International Finance Corporation's (IFC's) Advisory Services to assist the tender and 2 The Electricity Law provides that large scale strategic generation will be fully State owned.


transaction process. This would be the first of a series of thermal generation projects to be tendered in the foreseeable future. For this work and other generation BOT under consideration, the MOI has organized an inter-ministerial working group (the BOT group) lead by the electricity department coordinating the BOT program. The BOT working group will also participate in this assignment, in discussions, information exchange and comments to deliverables. The MOI is also reviewing and may carry out additional studies and plans regarding development of natural gas fields and pipelines together with new gas fired generation. To facilitate future gas fired generation transactions, the MOI is interested in developing strategies and studies on the efficient coordination between natural gas development and the supply and the development of gas fired IPPs, minimizing risks and improving the overall supply security. The Public-Private Infrastructure Advisory Facility (PPIAF) has approved a grant to hire consultancy services to develop the framework for tendering of thermal IPP projects, the harmonization of IPPs with the future planned power market development and coordination with natural gas development for gas fired generation. PPIAF is a multi-donor technical assistance facility aimed at helping developing countries improve the quality of their infrastructure through private sector involvement. A consultant group will be selected for this work. The Consultant team must include experts in IPP programs and transition to competitive electricity markets, as well as an international legal expert on these matters, and a gas and planning expert.


3. OBJECTIVES OF THE CONSULTANCY The general objective of this consultancy is to provide the following assistance to MOI: • Draft a framework to set the principles, guidelines and general procedures to

implement tenders for thermal IPPs under the general BOT framework existing in Vietnam, ensuring an efficient and transparent competitive process;

• Analyze and develop principles and mechanisms for the coordination between planning and investment in natural gas and in gas fired generation; and

• Develop a strategy to harmonize the IPP program with the future competitive power markets approved in the Roadmap, with the objective of attracting sufficient private investment at the best possible prices and conditions prior to the initiation of wholesale competition, and at the same time minimize risk of stranded costs and impediments to the efficient development of the market roadmap.

The specific objectives of this consultancy are the following:

1. Assist the MOI in designing the general framework for procurement and competitive tender of thermal BOT generation, to create predictability and a level playing field for private investors, and ensure transparency. This includes the drafting of standard principles and procedures for tenders of thermal generation projects, for MOI to issue the instructions for the implementation of the BOT Decree when applied to generation projects. The main purpose is developing standard rules that would apply to all thermal BOT tenders, to avoid a case-by-case approach and achieve a level of standardization and predictability that facilitates and speeds up the implementation and administration of future thermal BOT transactions and new Power Purchase Agreements (PPAs).

2. Asses and identify specific considerations and mechanisms to coordinate the efficient development of new thermal gas fired IPPs with development and investment in natural gas.

3. Assess and design the recommended strategy to integrate IPPs in the future power market, with the best possible mechanisms and PPA design to manage at the same time attracting private investors in generation, the smooth implementation of the Roadmap and mitigate the risk of future stranded costs.

It is expected that other related work may be carried out in parallel by the MOI, such as the IFC assisted IPP transaction and review of plans for the development of gas field and pipelines. Through MOI, the Consultant will receive information and updates as well as any particular concern or issue identified in other BOT related projects under MOI responsibility, for the Consultant to take them into consideration and, if necessary, incorporate adequate mechanisms or provisions in the framework and strategies to be developed in this Consultancy. However, it is not the purpose of this work to include provisions for a specific project or develop tender documents, but rather to develop a general approach that is both efficient and adequate for Vietnam conditions and that facilitates a transparent and competitive thermal generation IPP Program. This consultancy will require a very active interaction between the Consultant and the MOI counterpart, the BOT working group and, at certain stages, with other stakeholders through specific workshops as described later in the scope of work. The purpose is to ensure a thorough understanding by MOI staff that will have the responsibility of


implementing the results of this Consultancy, as well as achieving the necessary consensus building to facilitate the decision making and approval process of the IPP framework and strategy.


4. SCOPE OF WORK This section describes the tasks that the Consultant will have to carry out for the completion of this consultancy. The work is divided into several tasks, each task with specific activities and deliverables. Section 6 describes the timeframe for these activities and within which reports and deliverables should be submitted. Nevertheless, the Consultant may include in its proposal suggestions and improvements to these Terms of Reference, additional activities and deliverables which, based on its expertise and understanding of the general and specific objectives of this study, the Consultant considers necessary for a better implementation of the project and to achieve the objectives. Such proposals, if accepted, will form part of the Terms of Reference of the assignment.

4.1 TASK 1: ASSESSMENT AND INCEPTION REPORT

4.1.1 General Considerations As explained earlier, the MOI has the experience and understanding of the benefits and problems that had to be overcome in the international competitive tender for Phu My 2.2. The MOI is interested in establishing further successful international tenders for private investment in required new thermal generation. This has initiated with the MOI agreeing a mandate and contracting IFC for assistance in the assessment of the generation project, design of the tender process, preparation of tender documents, implementation and negotiation of an international tender for a thermal IPP transaction3. The purpose of this initial task is • Review and understand the current legal framework in Vietnam for the power

sector, private investment and BOT projects, and the decisions on the power market development and IPP participation, to ensure that the work prepared in this consultancy is fully consistent with legislation and the GOV policies;

• Assess relevant experiences in IPP programs, both international and in Vietnam, to identify issues that should be addressed and alternative approaches for competitive tenders of new thermal generation and for the integration of IPPs with future competitive power markets; and

• Assess the legal framework and regulations in Vietnam to identify procedures, clarification and gaps that should be covered in the thermal BOT tender framework and that should be addressed in the IPP market integration strategy.

4.1.2 Scope of Activities

• Activity 1, Assessment and Diagnosis of IPP Tenders: The Consultant will assess international experience in IPP competitive tenders for new thermal generation in relevant countries, to identify best practices and lessons learned. The Consultant will prepare a presentation for MOI and members of the working group to describe relevant international experiences and provide useful lessons, and to identify

3 As explained earlier, the initial expectation is a coal fired generation BOT project, but the final decision

on selected project has still to be made.


the issues that should be addressed to carry out successful IPP competitive international tenders. The Consultant will assess the legal framework in Vietnam for the power sector and for BOTs, and the experiences in IPP tender and international IPPs in Vietnam. The MOI will provide the required information and discuss with the Consultant on past experiences and current situation regarding IPPs and BOTs, to exchange ideas and views on expectations and special concerns for the case of Vietnam IPP program. The work should cover at least the following aspects:

− Review legal framework (laws, decrees, Prime Minister’s decisions and MOI instructions) and policies for the power sector, private investment and BOTs, and power market development, to identify and advice on any potential conflict of interpretation or problem that would need to be clarified in the thermal IPP tender framework.

− Review the GOV experience and approach in the competitive tender for Phu My 2.2 and the bankable contracts for IPP gas-fired power projects (Phu My 2.2 and 3), in view of changes in laws, new decrees and amendments, and decisions since those transactions.

− Propose alternative approaches to thermal IPP international tenders that are adequate to conditions in Vietnam and BOT legislation, in particular alternative approaches and mechanisms to in time reduce government contingent liabilities while maintaining developers / investors interest and the bankability of the generation project.

− Define the detailed scope of work and workplan to draft the framework for thermal IPP international competitive tenders.

• Activity # 2, Assessment of mechanisms to integrate IPP in the competitive power market:

The Consultant will review the sector structure and electricity trading arrangements that will develop from the implementation of the Roadmap, to identify expected changes and the requisites for the smooth implementation of the Roadmap and to attract private and foreign investors in new generation. The Consultant will assess current approaches to PPAs with IPPs and foreign BOTs in Vietnam, relevant international experiences in integrating IPPs with competitive power markets and on the transition from a Single Buyer market to wholesale competition, and identify issues that should be addressed. The Consultant will prepare a presentation for MOI to describe relevant international experiences, provide useful lessons and describe the key issues in the evolution to a competitive market. The Consultant will discuss and exchange information and views on the current IPP program, its expected future development, market design and the implementation of the Roadmap. The work should cover at least the following aspects:

− Review and describe relevant international experiences in the transit from integrated utilities to introducing IPPs and Single Buyer models, and the


transition to competitive wholesale power markets, to identify issues of concern and challenges that should be addressed.

− Review current approach in Vietnam to PPA design and international practices on bankable PPAs for IPPs, and evaluate potential impact in attracting private foreign investors, in avoiding stranded costs and in reducing government liabilities.

− Define the main concepts to be addressed in the strategy and mechanisms for IPP integration with the competitive power market, to minimize the risk of creating roadblock to the future development of the Roadmap and of possible stranded costs.

• Activity # 3, Inception Report and Workshop The Consultant will prepare an Inception Report with the results of the assessment, presentations and discussion with MOI during the previous activities. After delivering a preliminary version of the Inception Report, the Consultant will carry out a workshop to discuss the main findings and recommendations of this Task. The Consultant will prepare a presentation to inform the audience in the workshop on relevant international experiences and lessons learnt in IPP programs and their impact on competitive markets, as well as the first assessment on existing practices and conditions in Vietnam power sector. The main purpose of the workshop will be to build a common understanding on the why and how of IPP programs, the benefits and experiences in IPP competitive tenders s and the conditions, design of bankable PPAs for private generation investment and mechanisms that need to be addressed sufficiently in advance for the successful development of competitive markets. During the workshop, the Consultant will interact with participants and receive comments and concerns. Taking into consideration the results of the workshop and comments received from MOI, the Consultant will revise and deliver the final version of the Inception Report (Report # 1).

4.1.3 Deliverables

• Report # 1, Inception Report: − Assessment and diagnosis on IPP competitive tenders, and preliminary proposal

on approach for the framework on international tenders for thermal generation BOT projects.

− Assessment and preliminary recommendations on mechanisms to integrate IPPs in the future competitive power market.

− Detailed work plan for (i) thermal IPP competitive tenders as BOT projects; and (ii) the integration of IPPs in the future competitive markets in the Roadmap.

• Inception Workshop − The Consultant will prepare, organize and conduct the workshop described in

Activity 3 of this Task.


4.2 TASK 2: FRAMEWORK FOR INTERNATIONAL COMPETITIV E TENDERS OF THERMAL IPPS

4.2.1 General Considerations The need to attract private international financing and build sufficient capacity to supply load growth and support the economy has created a new urgency in Vietnam. Facing this challenge, there is a need to streamline and speed up the IPP program, while at the same time ensuring transparency, best possible prices and conditions for the efficient and adequate development of the power sector. Foreign IPPs are governed by the BOT Decree. The MOI is responsible for the implementation of the BOT Decree in the power sector, and can issue instructions for the implementation of foreign owned generation BOTs. The main objective of this task is to design a framework that complements existing legislation with the guidelines, principles and general procedures applicable to thermal generation BOT projects in the power sector, as required to implement international competitive tenders for new thermal IPPs. The scope of work does not include drafting model tender documents, but instead develop the guidelines and principles for the drafting of the tender documents and the design of the tender process for each future thermal IPP competitive tender to ensure that all share a common set of principles. The proposed procedures and principles should be fully consistent with the existing legal framework and establish the provisions for competitive tenders of thermal IPPs to achieve the target private investment, including among others the principles and mechanisms to maximize competition, to create predictability for foreign private investors, to streamline and standardize the thermal IPP tender process, and to achieve bankable and efficient tender documents.


• Activity #1, Conceptual design of the framework for competitive tender of thermal IPPs.

The Consultant will develop and propose a conceptual design and the general principles of the framework for competitive tenders of thermal IPPs as BOT projects. The purpose is to create reasonable predictability on the legal and regulatory framework, the steps and timing of IPP tenders, and to clarify the specific conditions that will apply to foreign private owned IPPs. The work should cover at least the following aspects:

− Based on Vietnam legal framework, review and design the structure for thermal IPP international tenders, clarifying roles and interactions between the MOI and other relevant government agencies who would be involved in tender documents or approval and permissions for thermal generation BOT projects (e.g. land lease, security packages, PPAs, etc.). The Consultant will prepare recommendations to, as far as possible, simplify and speed up the preparation and approval of the thermal IPP tender process.

− Based on the legal framework and PM Decisions on ERAV, design the structure of responsibilities and interactions between the Minister and ERAV.


− Assess experience in Vietnam on international competitive tender (Phu My 2-2 BOT project) and use it as the basis to avoid problems during future thermal IPP tenders and to maximize success.

− Assess risks that may be perceived by private foreign investors and lenders (credit worthiness, on going reform program, etc), and recommend conceptual approach and requisites (general design) to reduce and mitigate those risks.

The Consultant shall organize an internal workshop with MOI to present its findings and recommendations, and carry out discussions. The purpose will be to agree with MOI counterpart the conceptual design.

• Activity #2, Draft standard framework for competiti ve tender of thermal IPPs The Consultant will draft standard procedures and principles for international competitive tenders of thermal IPPs, to implement the BOT Decree in the electricity generation activity and set the framework for periodic future thermal IPP international; tenders, striving for transparency, reasonable allocation of risks, streamlined processes and maximizing competition as reasonable.

• The expected result is to establish standard principles and procedures, as streamlined as possible, well understood and repeatable to maximize the benefits of knowledge acquired in each tender, and to facilitate and speed up implementation of a series of periodic thermal IPP international tenders.

•

• The framework should include, among others: − Responsibilities and interactions between the MOI and other government

agencies in permissions and approvals; − List of tender documents (such as Request for Qualifications and Request for

Proposals, Power Purchase Agreement, Implementation Agreement, Fuel Agreement, Land Lease Agreement if applicable and any other recommended by the Consultant), and general principles and guidelines in the preparation of these documents;

− Principles and guidelines for the tender process; and − Principles and procedures to review and approve tender documents, and to

award the project and the PPA.

• Activity # 3, Report and Workshop on Framework for Competitive Tenders of thermal IPPs as BOT projects

The Consultant will prepare the Report “Framework for Competitive Tenders of Thermal IPPs” with the results from the work and meetings with MOI during the two previous activities. After delivering a preliminary version of the report, the Consultant will carry out a workshop to discuss the main findings and recommendations of this Task. The Consultant will prepare a presentation and organize the workshop to inform the proposed framework for thermal IPP competitive tenders as BOT projects. The main purpose of the workshop will be capacity and consensus building of the benefits for


generation investment in Vietnam and the initial challenges in transforming the IPP Program into a successful competitive process that attracts foreign private expert investors. During the workshop the Consultant will interact with participants and receive comments and concerns. Taking into consideration the results of the workshop and comments received from MOI, the Consultant will prepare and deliver the final version of “Framework for Competitive Tenders of Thermal IPPs” (Report # 2).

4.2.3 Deliverables

• Internal Workshop on Conceptual design and structure of Framework for Competitive Tenders of thermal IPPs as BOT projects − The Consultant will organize and conduct the workshop described in Activity 1

of this Task.

• Report # 2, “Framework for Competitive Tenders of Thermal IPPs”: − Conceptual design and structure of the framework for international competitive

tender of thermal IPPs as BOT project, including comprehensive description and justification.

− Draft standard framework (guidelines, principles and general procedures) to guide the implementation of international competitive tenders of thermal IPPs as BOT projects.

• Workshop on Framework for Competitive Tenders of thermal IPPs as BOT Projects: − Organize and conduct the workshop as described in Activity 3 of this Task.

4.3 TASK 3: STRATEGY TO INTEGRATE IPPS IN THE POWER MARKET

4.3.1 General Considerations The Roadmap for the power market moves through successive phases with increasing competition and changes in electricity trading arrangements. In this Roadmap, the electricity industry is expected to gradually move in stages of increasing competition by restructuring and multiplying the number of players (sellers and buyers) and by diversifying choice among buyers and sellers of electricity, to promote greater efficiency and innovation. This will naturally lead to an increase in the risks assigned to each electricity activity and market participant, and should reduce the risks and liabilities faced by the GOV. However, the current situation in Vietnam requires urgently attracting new IPPs to avoid shortages, and to support and strengthen economic growth. The IPPs and foreign investors BOT projects entering the sector during the next years will also operate and sell during future stages of the power market planned in the Roadmap, designed with greater levels of competition. Therefore, the PPAs to be signed in the next years with BOTs (in particular PPAs for thermal BOT tenders) need to include adequate provisions to attract efficient private investment and facilitate the future smooth transition of the sector through the stages of the power market.


Reciprocally, it is also necessary to assess and ensure that the future power market design facilitates timely and sufficient new generation investments and promotes an environment with efficient contracting, to protect security of supply and at the same time facilitate the evolution of the initial IPP Program and its PPAs to the Contract Market in the new competitive power markets. Success in combining the IPP program with the Roadmap will also require managing and reducing, as possible,

− the GOV contingent liabilities that result from either direct financial guarantees or government guarantees related to the BOT / IPP program; and

− the risk of stranded costs that may affect future tariffs or charges paid by consumers and society.


• Activity # 1, Mechanisms to integrate IPPs in future competitive power market. The Consultant will assess and propose alternative mechanisms, consistent with the initial need to attract foreign and private investment and the future development of the power market Roadmap, to ensure a long term benefit of the IPP program through a smooth, efficient and cost effective transition to a competitive power market. Such mechanisms would include, as possible, incentives for IPPs to support the introduction of a competitive wholesale market.

• Activity # 2, Strategy to administer the risk of stranded costs. The Consultant will propose a strategy with specific measures that can be implemented in Vietnam IPP Program and in the design and structure of Vietnam competitive power market to: • Minimize the future costs and possible negative impact on efficiency of the IPPs

entering the sector prior to introduction of wholesale competition; and • Create conditions for the development of effective competition and a level playing

field for private investors.

• Activity # 3, Model to evaluate impact of IPPs. The Consultant will develop and deliver to the MOI a model to assess the impact of design and pricing in PPAs before start-up of the competitive power market, under different scenarios (e.g. load growth, improvement in generation technology and efficiency, market prices, etc.), and evaluate possible over-the-market costs (stranded costs) when the competitive power market initiates. The model should be developed in Microsoft Excel, or other similar spreadsheet format to be agreed between MOI and the Consultant, and be simple and practical. The Consultant will deliver this software together with a printed document as a manual with description, instructions for use and data bases. The Consultant shall also provide a short training to MOI staff for its future use.


• Activity # 4, Report and Workshop on Strategy to Integrate IPPs in the Power Market.

The Consultant will prepare the Report “Strategy to Integrate IPPs in the Power Market” with the results of the work during activities 1 and 2 of this Task. After delivering a preliminary version of the Inception Report, the Consultant will carry out a workshop to discuss the main findings and recommendations of this Task. The Consultant will prepare a presentation and organize a workshop to inform the audience the proposed strategy and mechanisms, including provisions or design of PPAs, to integrate IPPs in the future power market, and to harmonize the IPP Program with the future market design. The main purpose of the workshop will be to build capacity and consensus on the benefits of adequate provisions in PPAs and market design, and the initial challenges in harmonizing attracting IPPs and the future successful development of a competitive power market. During the workshop the Consultant will interact with participants and receive comments and concerns. Taking into consideration the results of the workshop and comments received from MOI, the Consultant will prepare and deliver the final version of the Report “Strategy to Integrate IPPs in the Power Market” (Report # 3).

4.3.3 Deliverables

• Report # 3, Strategy to Integrate IPPs in the Power Market − Mechanisms to integrate IPPs in the future competitive power market. − Strategy to administer the risk of stranded costs.

• Model to evaluate risk of stranded costs − Model and documents as described in Activity 3 of this Task.

• Workshop on Strategy to Integrate IPPs in the Power Market − Organize and conduct the workshop described in Activity 4 of this Task.

4.4 TASK 4: ANALYSIS AND COORDINATION OF NEW GAS FI RED GENERATION WITH DEVELOPMENT OF NATURAL GAS RESOURCES.

4.4.1 General Considerations A significant proportion of planned new generation will be gas fired and, therefore, their successful development is inherently connected to the development of the natural gas sources and gas pipelines. Any incongruence, discordance or lack of coordination between the planning and development of natural gas projects and transportation and new gas fired generation projects could lead to undesired consequences, in attracting private investment and in avoiding shortages.


Currently both the power sector and natural gas are under the MOI, which also controls EVN, Vinacomin (the coal SOE) and PetroVietnam (the fuel SOE). Master plans for each sector are reviewed and approved by MOI. It is necessary to properly assess the risks associated in the planning and development (and investment) interface between the two sectors and to develop efficient coordination mechanisms. This is particularly important to attract foreign private investment in gas fired generation and ensuring generation adequacy for load supply, by planning and ensuring sufficient natural gas supply to new and existing thermal generation.


• Activity #1, Analysis and Coordination Mechanisms. The Consultant will propose mechanisms to analyze and coordinate the development of gas-fired generation with gas transportation/gas field development. The work will cover the coordination between power and natural gas planning and investment decisions, but will not include an assessment of natural gas availability. The MOI will provide available power master plan or planned gas fired generation investment, natural gas plans and expected availability that may be required by the Consultant for this activity. The Consultant will identify and assess the risks involved in natural gas development and the coordination issues between the planning and development of least cost generation expansion, the participation new gas fired generation in the power master plan and the planning and investments in the natural gas sector. The Consultant will propose mechanisms and principles to assess least cost generation planning and the efficient coordination of development and planning of new gas fired generation and gas field and/or pipelines. The work should cover at least the following aspects:

− Identify issues and make a general risk assessment on natural gas developments in Vietnam that could affect the planning of new gas fired generation and in particular to tender gas fired IPPs. The objective is to identify the matters and assumptions that need to be studied and evaluated in detail (including sensitivity analysis to different scenarios) prior to planning, deciding and then tendering gas fired thermal IPPs, such as gas availability and costs / prices probability, sensitivity analysis to optimistic and pessimistic scenarios on load growth and on availability in natural gas resources.

− Propose mitigation mechanisms and reasonable allocation of risks between government and investors.

• Activity # 2, Develop a case study The Consultant shall develop a case study based on a base scenario (that shall be determined in consensus with the MOI counterpart) and changes in variables identified as sensitive after the results of the previous activity. The Consultant will propose adequate indicators to represent and compare different risk conditions. The study should


specially evaluate consequences of deviations between natural gas availability (gas field and transportation development) and completion of new gas fired generation.

• Activity # 3, Report and Workshop on Coordination between New Gas-fired Generation and Development of Natural Gas Resources

The Consultant will prepare the Report “Coordination between New Gas-fired Generation and the Development of Natural Gas Resources” with the results of the assessment and studies carried out during the previous activities. After delivering a preliminary version of the Inception Report, the Consultant will carry out a workshop to discuss the main findings and recommendations of this Task. The Consultant will prepare a presentation and organize the workshop to inform issues and main concerns to efficiently coordinate the development of the natural gas planning and investments with gas fired generation, and the risks and variables involved. The main purpose of the workshop will be to discuss and build a common understanding on the need and conditions that would maximize the efficient use of energy resources and development of natural gas. During the workshop the Consultant will interact with participants and receive comments and concerns. Taking into consideration the results of the workshop and comments received from MOI, the Consultant will prepare and deliver the final version of the Report “Coordination between New Gas-fired Generation and the Development of Natural Gas Resources” (Report # 4).

4.4.3 Deliverables

• Report # 4, Coordination between New Gas-fired Generation and Development of Natural Gas Resources − Risks associated to the interface between the planning and development of gas

fields and pipelines, and the planning and investment in gas fired generation. − Mechanisms to coordinate the planning and development of gas-fired generation

investment with planning and investment in gas fields and pipelines. − Results of the Case Study, accompanied by a description of methodology,

assumptions, variables and indicators.

• Workshop on Coordination between New Gas-fired Generation and Development of Natural Gas Resources − Organize and conduct the workshop as described in Activity 3 of this Task.

TASK 5: FINAL REPORT The Consultant will prepare and submit a Final Report including: • An Executive Summary with the main conclusions and recommendation; and • The final version of all documents produced during the consultancy.


5. ORGANIZATION AND WORKPLAN

5.1 COORDINATION AND WORKING GROUP The counterpart of the Consultant will be the MOI. However, to ensure the required level of involvement and that information and comments are provided in time, a Project Coordinator from MOI will act as the main counterpart and the BOT working group will be involved in workshops, presentations and comments to the Consultant proposals. At the beginning of this Consultancy the MOI will inform to the Consultant the names of the Project Coordinator and the names and affiliations of the members of the working group. The MOI will act as the formal liaison with the Consultant, and be in charge of the communications between the Consultant and any other government agency. The MOI will ensure the active participation of the working group, with whom the Consultant will work closely. The Consultant is encouraged to organize its work promoting participation and involvement of the working group, to maximize capacity building. The proposed approach will be carefully considered at the time of selecting the Consultant. Thus the Consultant is encouraged to indicate how it plans to conduct its work and involvement of the working group.

5.2 WORKSHOPS The Consultant will prepare, organize and deliver workshops aimed at explaining and discussing the major findings, conclusions and recommendations, receiving feedback and comments, and pointing out all the decisions that need to be made either to proceed with the workplan or for the implementation of its final results and recommendations. The Consultant will be in charge of the necessary preparations and logistics of each workshop, including the printed material (in English and Vietnamese) and as necessary translators. The Consultant will include in its proposal the workshops described in the TORs, and any additional workshop the Consultant considers necessary. The actual date of each workshop will be agreed at least 2 weeks in advance. The MOI will inform the Consultant in advance the participants that will be invited. The estimated duration of each workshop is one full working day. The main objectives of the workshops will be:

− Disseminate the results of the study and capacity building; − Receive comments and observations from the participants; and − Promote consensus building around the matters under analysis

The Consultant will prepare the presentations for each workshop in Power Point format and send a softcopy of this presentation to the MOI at least three working days before


the workshop. The Consultant will prepare printed copies of the presentations for the attendees, in English and Vietnamese. Each workshop will include one or more sessions for discussions, questions and answers.

5.3 REPORTING The Consultant will submit the reports described in these TORs to the MOI in soft copies (Microsoft Office or compatible format as agreed between MOI and the Consultant) and in three printed copies. Each report will be first sent in a preliminary version no later than two weeks before the planned date for the workshop that will discuss its findings and recommendations. The final version of the report shall be submitted one week after the workshop, unless a longer period is agreed with MOI in view of the results of the workshop, taking into consideration the observations received from the MOI Counterpart until the day and during the corresponding workshop. In cases when the Consultant considers that some of the comments/requests received are not relevant or inadequate, an Annex of the report will list those comments and recommendations and clarify the reasons why they were not included in the final version of the report. The final versions of documents and reports delivered in each Task together with the main findings and recommendations will be integrated in the Final Report.

5.4 WORKPLAN The estimated duration of the assignment is 34 weeks. The Consultant shall propose the workplan to best deliver the described objectives and perform the required scope of work and tasks. The following page shows an indicative workplan, provided only for the purpose of guidance.


•

TASK 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34Activity

Kick Off

1

1 IPP Tender

2 IPP Integration

MOI Revision

3Workshop

Report final version)

2

1 Framework

Internal Workshop

MOI Rev/Decision

2 Draft Framework

MOI Revision

3Workshop


3

1 Mechanisms

2 Risk Strategy

Intermediate meet.

MOI Revision

M

o

d

e

l

1

Development

Intermediate meet.

MOI Revision

Model Final

Training

4Workshop


4

Coord. Mechan.

2 Case Study

Workshop3

Intermediate meet.

MOI Revision

References


5Draft

MOI Revision

Final Report

Report (preliminary version)

Time for MOI to revise

draftsMissions (meet, work) Report Final version

Consultant work at office Workshop

B-1


APPENDIX B: FINAL WORKSHOP PRESENTATION

This appendix presents the materials from the Final Workshop.

Ministry of Industry and Trade (MOIT) Public Private Infrastructure Development Facility (PPIAF)The World Bank

Vietnam: Framework for Thermal BOT Tenders & Strategy for Gas Coordination and Harmonization with Market Roadmap

Workshop No. 3

Hanoi, 1 & 2 April 2009

Vietnam BOT Framework – Workshop No. 3 Page 2

Agenda/contents – Day 1: BOT Market Integration & Tendering

1. Registration 7:30 – 8:00

2. Opening Remarks MOIT 8:00 – 8:10

3. Study Background & Objectives M. Crosetti 8:10 – 8:30

4. BOT Market Integration Issues & Options M. Crosetti 8:30 – 9:15

5. Market Integration Discussion 9:15 – 10:00

6. Break 10:00 – 10:15

7. Framework for BOT Competitive Tenders R. MacGeorge 10:15 – 11:15

8. Tender Framework Discussion 11:15 – 11:45

9. Lunch 11:45 – 14:00


Agenda/contents – Day 2: Gas & Power Coordination


2. Welcome to Day 2 MOIT 7:45 – 7:50

3. Gas Resources & Institutional Setting B. Cole 7:50 – 8:30

4. Risk Allocation Exercise Introduction M. Crosetti 8:30 – 8:45

5. Risk Allocation Exercise 8:45 – 10:00

6. Break 10:00 – 10:15

7. Gas Sector Issues & Options B. Cole 10:15 – 10:45

8. Discussion of Gas Sector Issues 10:45 – 11:15

9. Gas-Fired BOT Risks & Mitigation / Case B. Cole 11:15 – 11:45Study

10. Summary of Consultant Findings M. Crosetti 11:45 – 12:00

11. Wrap-up Discussion 12:00 – 12:20

12: Closing Remarks MOIT 12:20 – 12:30

13. Lunch 12:30 – 2:00


Opening Remarks from MOIT








6. Break 10:00 – 10:15



9. Lunch 11:45 – 14:00


Assignment Context

• High Demand Growth– PMP6 forecasts 11.6% ACGR energy demand growth rate now to 2025. (Demand

doubles every 6 to 7 years).– New sources of capital required to fund power sector investment

• Two Modalities for Non-EVN Generation: IPP and BOT

• Role of Generation BOTs– Legislative framework in place– PMP6 stipulates that 8,225 MW of BOT capacity will be commissioned before 2015,

with another 6,450 MW as either BOT or IPP capacity. Of the 8,225 MW defined as BOT, 5,350 MW has been designated for competitive bidding

– Phu My 2.2 and Phu My 3 in operation. New negotiated thermal BOTs enter mix starting 2011 (Vinh Tan 1 and Mong Duong 2). New competitively-tendered thermal BOTs enter mix starting in 2012 (Nghi Son 2)).

• Introduction of a Power Market– Competition to promote greater efficiencies � reduce the pressure to increase tariffs– Attract additional sources of investment at competitive prices � eliminate shortages

• Significant gas resources– Some 13 TCF of reserves– No formal power/gas coordination mechanisms for planning new development


Government Objectives for the Power Sector

• Ensure sufficient capacity and reliability

– Attract power sector investment both nationally and internationally

• Minimize the pressure to increase tariffs

– Capital allocation

• use of least-cost planning to identify new projects

• optimal designation of development modality (BOT, IPP, EVN)

• addressed for BOTs through the tendering framework

– Operating efficiency

• minimize stranded costs (the difference between what a BOT is paid under its PPA and what it would have been paid if it were participating in the market)

• minimize prices in market

• addressed for BOTs through the market integration mechanism

• Ensure a smooth transition from one market stage to the next

Stakeholder Interests


Assignment Scope

Against this background, the project aims to address three inter-related topics within a comprehensive framework

BOT projects excluded from scope:

• Existing projects (Phu My 2.2 and 3)

• Projects under development (Vinh Tan 1, Mong Duong 2, and Nghi Son 2)

• Projects prepared prior to implementation of this framework

Competitive tendering of

BOTs

Coordination of gas &

generation development

BOT integration in power market

Ensure BOTs are procured at lowest cost,

transparently, and in a timely manner

Ensure BOTs are contracted so as to minimize stranded

costs and electricity prices

Ensure efficient coordination of planning & development between the gas and power sectors. Identify risks & mitigation measures across the gas-to-power value chain

How can the Government of Vietnam ensure the succes s of its thermal generation BOT program?


Assignment Objectives

To assist the Government of Vietnam (through the Ministry of Industry & Trade) prepare a BOT Generation Framework resulting in:

• Timely & transparent competitive tendering of BOTs

– New supply at lowest possible prices

• Integration of these BOTs into the evolving power market

– recognize and balance interests of all stakeholders

• Coordination of gas-fired generation with gas development

– optimize resource utilization and investment


Workshop Objectives

• To provide an understanding of possible impediments to successful thermal generation BOT development and Vietnam, and mechanisms to overcome those impediments

• To seek your comment and feedback regarding those mechanisms so that we may finalize our recommendations accordingly

• To suggest next steps you would need to take to implement the recommended mechanisms


Structure of this Workshop

1. Market Integration Issues & Options

2. Framework for Competitive BOT

Tenders

3. Coordination of Gas & Power Sector

Planning

The BOT Tendering Framework must support the selected market integration mechanism and promote timely and transparent development of least-cost BOT generation.

The economic benefits and risks of future BOTs will depend at least in part upon how well they are integrated into the market

The success of generation development depends in large part on availability and pricing of upstream fuel supply. Coordinated planning between the gas & power sectors will help optimize investment & operations across the gas-to-power value chain.

Day 1

Day 2








6. Break 10:00 – 10:15



9. Lunch 11:45 – 14:00


Vietnam continues to seek IPPs and BOTs for power generation

• High Demand Growth– The Sixth Power Master Plan (PMP6) forecasts 11.6% ACGR energy demand growth

rate now to 2025 � Demand doubles every 6 to 7 years– New sources of capital required to fund power sector investment

• Currently EVN is the legacy, vertically-integrated national electricity company

– Produces nearly 80% of power through its subsidiaries (2007 data)

• Two Modalities for Non-EVN Generation: IPP (indepen dent power producer) and BOT (build-own-transfer)

– IPPs are non-EVN power plants that sell power to EVN/SB under PPAs• These PPAs may change as the nature of the industry changes• Do not meet requirements of Decree 78 (BOT Decree) and hence are ineligible for

Government support• Example of IPP: PetroVietnam’s Cau Mau complex (1,500 MW)

– BOTs also sell power to EVN/SB under PPAs• Utilize a traditional 2-part PPA• may also receive Government support per Decree 78 (BOT Decree)• Examples of BOTs: Phu My 2.2 and Phu My 3• PMP6 stipulates that 8,225 MW of BOT capacity will be commissioned before 2015,

with another 6,450 MW as either BOT or IPP capacity.


Vietnam is also introducing a power market (PM Decision 26/2006/QD-TTg)

Purpose of the market :

• Ensure stable power supplies

– ensure adequate investment is made to meet demand, drawing on all possible sources of investment

– Prevent abrupt changes to the structure or operation of the sector, which could lead to interruptions in investment

• Attract investment from new sources

– The sector should increasingly rely on investment from non-traditional sources and, in particular, from private and foreign sources

• Increase competition to improve efficiency and obtain reasonable prices

– The level of competition in the power market should be gradually increased to drive efficiency and restrain prices


The PM Decision provides a timetable for introduction of the market

Three-stage evolution :

• Competitive Generation Market (CGM) – Generators sell to Single Buyer. Cost-based gross pool with net settlement.

• Wholesale Competitive Market (WCM) – Generators sell to wholesalers, distributors and large consumers. Wholesalers and generators compete for distributors & large consumers.

• Retail Competitive Market (RCM) – Retail consumers may choose supplier

2005 2010* 2014 2016 2022 2025

Pilot internal EVN market

Complete Competitive

Generation Market (CGM)

Pilot Wholesale Competitive Market

(WCM)

Complete Wholesale Competitive Market

(WCM)

Pilot Retail Competitive Market (RCM)

Complete Retail Competitive Market

(RCM)* Updated ERAV schedule


PMP6 envisions the continuing implementation of BOTs during the market roll-out

• BOTs currently under development utilize traditional 2-part PPAs• Delays are likely in roll-out of market (e.g., CGM rules not yet finalized, procurement of market

infrastructure has not yet begun)

• Delays also likely in BOT operation (e.g. Vinh Tan and Mong Duong still under negotiation).

2005 2010* 2014 2016 2022 2025

Pilot internal EVN market

Complete Competitive

Generation Market (CGM)

Pilot Wholesale Competitive Market

(WCM)

Complete Wholesale Competitive Market

(WCM)

Pilot Retail Competitive Market (RMC)

Complete Retail Competitive Market

(RCM)

2011• Vinh Tan 1.1, 600 MW (CSG)• Mong Duong 2.1, 600 MW (AES)

2012• Vinh Tan 1.2, 600 MW (CSG)• Mong Duong 2.2, 600 MW (AES)• Nghi Son 2.1, 600 MW (bidding)• 1 project BOT or IPP, 600 MW

2013• 4 competitively bid BOT, 3150 MW• 2 projects BOT or IPP, 1200 MW

2014• 1 competitively bid BOT, 600 MW• 3 projects BOT or IPP, 1950 MW• 1 hydro in Laos, 475 MW

2015• 1 competitively bid BOT, 1000 MW• 3 projects BOT or IPP, 2200 MW

2016 onwardsNumerous BOTs

* Updated ERAV schedule


The 2-part PPAs traditionally used by BOTs do not fit well with markets

• Superimposed on markets rather than integrated to them

• Requires an “agent” (BOT Wholesaler) to bid the plant into a market in order to be dispatched.

• If market prices are above the equivalent fixed + variable price of the PPA, the BOT Wholesaler makes money, but if market prices are below, the BOT Wholesaler makes a loss that represents stranded cost .

• Puts all risks on the buyer , other than the risks of payment default and plant unavailability.

• Capacity fee is paid even if plant does not run. Once awarded, does not need to compete with other generation to provide equity returns.

• Any plant efficiencies that the generator achieves do not benefit the buyer or consumers. Benefits are retained exclusively by the generator.

• Developed to attract investment in cases where investors had no control over dispatch. Sellers provide buyers with capacity.

• Generator awaits dispatch instructions; indifferent as to whether or not dispatched

• Defined in terms of:– a fixed payment to cover debt service,

equity returns and fixed O&M costs– a variable payment to cover fuel and

variable O&M costs

– hydro may have energy-only contract

• A “physical contract”:– fixed component paid only if the plant is

available– variable component paid only if the plant

delivers energy.

Traditional 2-part PPA


Nonetheless, Vietnam can harmonize BOT development with the market

How can the Government of Vietnam

• continue to attract bankable BOT projects in the po wer sector

• ensure a smooth transition between market stages

• minimize the risks of high electricity prices or st randed costs that could result from these projects?

Vietnam can utilize collar CfDs (contracts for differences) to contract future BOTs*

BOTs can still be procured on a competitive

basis

The collar structure allows

the Government to limit risks of high prices or stranded costs

The collar structure allows BOTs to strike

acceptable balances of risk

& reward

CfDs aremarket-based

* BOTs that would be developed after this framework has been formally adopted

A CfD-based framework canaccommodate

market transitions


Terminology: The CfD

• If the market price is higher than the strike price during a given period, the seller pays the buyer the difference between the two prices for the contracted volume

• If the market price is lower than the strike price, the buyer pays the seller the difference for the contracted volume.

• “Two-way” because it can result in buyer paying seller or seller paying buyer

Generator A agrees to receive

Utility B agrees to pay

CfD payment

Spot market price

Generator A price

Utility B price

CfD strike price


Another view of CfDs

CfDs can also be designed so only one of the parties is obligated to pay the other.

• A “floor” CfD obligates the buyer to pay the seller the difference between the market price and the strike price whenever the market price is below the strike price.

• A “cap” CfD obligates the seller to pay the buyer for the difference between the market price and the strike price whenever the market price is above the strike price.

• A “two-way” CfD is a “floor” CfD together with a “cap” CfD when both have the same strike price

time

pric

e strike price

market price

CfD payments from seller to buyer

CfD payments from buyer to seller


The “collar” CfD

A “collar” CfD specifies a floor strike price and a separate cap strike price

• limits the losses that may accrue to the seller, but also limits the sellers upside

• the buyer will never pay more than the cap price, but will never pay less than the floor

time

pric

e

cap strike price

market price



floor strike price


The CfD is market-based

• Developed to hedge risks in markets. Provides sellers with certainty of revenue and buyers with certainty of cost regardless of market price.

• Generator bids into market for dispatch

• Defined in terms of:

– a contract energy price (the “strike price”)

– a contract volume & corresponding period

• Can incorporate indexing for fuel pricing, forex, etc.

• A “financial contract”. Payment obligation for differences exists regardless of whether plant is dispatched.

Contract for Differences (CfD)• The plant directly bids into the market. Does

not require an agent .

• By using a collar, higher cap prices can compensate for lower floor prices, hence minimizes the potential for stranded cost .

• Plant bears a greater share of risks .

– outside periods/volumes of CfD coverage

– if plant bids incorrectly

• Plant incentivized to be as efficient as possible , so as to maximize dispatch to earn additional producer surplus

• Plant efficiency gains may be shared with buyers for periods/volumes:

– when floor price is agreed that is less than price under traditional PPA

– outside of CfD coverage


Suitability of CfDs and Traditional PPAs in Markets

A CfD is preferable to a traditional PPA in most respects when operating in a market

Characteristic Collar CfDs Traditional PPAs

Ease of participation in the market

Generator participates directly Generator requires an agent to bid it into the market

Potential for high prices

Limited by cap price, which is likely to be higher than a PPA price

Limited by PPA price

Potential for stranded costs

Limited by floor price, which is likely to be lower than a PPA price

Stranded costs result whenever market price is less than PPA cost

Risk sharing Generator takes on market risks outside CfD coverage or if it bids incorrectly

Insulated from all risks other than payment default and plant unavailability

Incentives for efficiency

Incentivized to be as efficient as possible to maximize dispatch and producer surplus

Limited to improvements in heat rate against contract value, but cannot influence dispatch.

Sharing of efficiency gains

Generator shares gains from efficiency improvements with buyers under some circumstances

Generator retains exclusively any gains from efficiency improvements


A CfD-based framework can accommodate market transitions

A single contract can govern power purchase from the BOT throughout the evolution of the market.

• The CGM and WCM have not yet been implemented, but the procurement of new BOTs is ongoing

• Lenders and developers will demand a robust contractual framework that will provide revenue certainty regardless of the prevailing nature of the market

– Payments would be based on a traditional 2-part PPA if the WCM has not yet been implemented, or has been suspended

– Payments would be based on a collar CfD during the WCM

Traditional 2-part PPA Collar CfD

Conversion Triggers

Hybrid Power Purchase Agreement

Static Provisions


The collar structure allows both Government & BOTs to define their respective objectives

timepr

ice

cap strike price

floor strike price

Objective Mechanism

• Minimize stranded costs

Seek a minimum floor price

• Minimize electricity prices

Seek a minimum cap price

Objective Mechanism

• Ensure debt service Seek an adequate (high) floor price

• Achieve equity returns commensurate with risk assumed

Maximize cap price commensurate with an acceptable floor price and expected market prices

BOT Investor

Government

market price




Competitive procurement is key

• Competitive procurement yields the lowest generatio n prices

– Little benefit to a competitive power market (operational efficiencies) in the absence of competition for new build (capital efficiencies)

• The tender should limit the parameters the bidder w ill propose

– Traditional two-part PPA parameters:

• fixed costs (fixed O&M, debt service, equity returns)

• variable cost drivers: heat rate, variable O&M

– portion of fixed cost recovery the bidder is willing to put at risk in exchange for pre-defined upside potential once the market is introduced


Evaluating bids

• Tender evaluation should reward the acceptance of greater market risk by bidders

– levelized cost of power = costs of the traditional 2-part PPA over the period it is assumed to be in effect + value of CfDvolume at the bidder’s proposed floor price

– Bidder’s floor price = price required to recover plant fixed & variable costs assumed to prevail when the contract coverts to a CfD, less the amount of fixed cost recovery the bidder is willing to put at risk,

– cap price is a function, predefined by the Government, of the bidder’s proposed floor price relative to the bidder’s full cost recovery floor price.

• This approach allows discovery of the maximum market risk IPPs are willing to accept.

time

pric

e

cap strike price

floor strike price

y

x

Full cost recovery strike price, i.e. strike price for two-way CfD that yields same payment security to BOT as traditional 2-part PPA


1. Bid Documents

How it would work

Government BOT Bidder

For evaluation purposes:

• assumed date of WCM introduction

• fuel price trajectory

• discount rate

• etc

Contractual elements:

• a traditional 2-part PPA

• trigger conditions for conversion to CfD

• CfD parameters– volumes & methodology to define periods– collar cap price: function of floor price– methodology to determine floor price based on

prevailing variable costs, NPV of remaining fixed payments and amount of fixed payments the bidder is willing to forego in exchange for capped upside

• values for fixed and variable price components that would apply under the traditional 2-part PPA

• the portion of fixed cost recovery that the bidder is willing to forego upon conversion to a CfD � the more the bidder foregoes, the lower the floor price & higher the cap price

2. Proposal

3. Evaluation & Award• levelized price of power over the assumed period of

the 2-part PPA plus the period of the CfD, using the bidder’s proposed reduction for fixed price recovery


Proposed financial evaluation formula

The evaluated price is a levelized price calculated as follows:

Where T = the last year of the traditional PPAd = the discount rateFCi = fixed costs in year iVCi = variable costs in year i, a function of heat rate, variable O&M, assumed fuel costs, etc.N = the BOT lifetimeV = the CfD volumeFPi = the collar floor price in year i, which is a function of the portion of FCi the bidder seeks to protect and VCiEi = the energy produced in year i measured at the point of sale

∑

∑ ∑

=

= +=

+

•+

+++= N

iii

T

i

N

Tiiiiii

Ed

FPVd

VCFCd

P

1

1 1

)1(1

)()1(

1)(

)1(1


Conclusions

• BOTs can be integrated into markets . Hybrid power purchase agreements that convert traditional 2-part PPAs to collar CfDs upon certain trigger conditions can facilitate the integration of BOTs into markets.

• Collar CfDs can address concerns of both buyers and sellers . The use of a collar CfD can satisfy lender’s requirements for revenue sufficient to service debt, while satisfying Government desires to limit potential market price spikes.

• Risks demand rewards. The only way to minimize the risk of stranded costs when transitioning to a power market is to give generators upside potential in exchange for accepting market risk.

• Encourage bidders to maximize the market risk they a re willing to bear . By evaluating proposals for new generation in a manner that promotes maximizing the amount of fixed cost recovery generators put at risk upon conversion to the market, a competitive tender process for new generation can reveal in advance the maximum market risk those generators are willing to bear.








6. Break 10:00 – 10:15



9. Lunch 11:45 – 14:00


Thermal Generation BOT Framework

Objective:

• To create a Framework that maximizes competition, creates a predictable setting for foreign private investors, streamlines and standardizes the thermal generation BOT tender process, and achieve bankable and efficient tender documents.

Design considerations:

• Consistent with Vietnamese law

– BOT Decree 78

– Draft MPI Circular on implementation of BOT Decree 78 on investments under BOT, BTO and BT agreements

• Consistent with international standards

– UNCITRAL Model Legislative Provisions on Privately Financed Infrastructure Projects 2004

– Designed to be consistent with the IFI principles of procurement

• Improves efficiency and transparency of process

– Streamlines and standardizes the bidding process

– Aims to achieve bankable and efficient bidding documents

• Creates a predictable setting for foreign private investors

– Foreign direct investment is a global competition that favors those who create the most attractive investment conditions.

• Maximizes competition

– Generally leads to substantial reductions in price, improvements in service and greater innovation.


Benefits of Competition

• International studies on competition benefits are well recorded:

– Michael E. Porter, The Competitive Advantage of Nations

– David Card & Richard B. Freeman, what Have Two Decades of British Economic Reform Delivered?

– Clifford Winston, U.S. Industry Adjustment to Deregulation

• The CGM and WCM aim to maximize operational efficiency

• Operational efficiency depends in part on capital efficiency

• Maximizing competition in procurement maximizes capital efficiency.

• Competition can be maximized in procurement if the setting is clear, predictable, fair and conforms with international standards.

• The market integration mechanism requires competitive bidding due to the difficulty of benchmarking risk tolerance in a negotiated setting


Thermal Generation – Possible Exceptions to Competition

• When there is an urgent need, provided that the urgency was not foreseeable and not caused by the GOV’s poor performance;

• In certain cases of unsolicited proposals;

– If an unsolicited proposal has truly unique and new intellectual property, then the proposal might be negotiated.

– However, the GOV should also choose elements of competition (such as a Swiss challenge) to ensure that the unsolicited proposal is tested.

– A Swiss challenge is a form of procurement that requires a buyer that has received an unsolicited bid to invite third parties to match or exceed it.

– No more than one application made after issuing an invitation to pre-qualify or propose;

• Where the Prime Minister authorizes the Contracting Authority to exempt a Thermal Generation BOT Project from competitive procedures for “compelling reasons that are in the public interest”. Usually this means a project needs to be “fast tracked”, which is either due to deficient planning or a genuinely unforeseeable event.


Institutional Structure

• The GOV acts in a range of different capacities with regard to thermal generation BOT projects

• These are:

– Planning;

– Procuring;

– Contracting (BOT Agreement);

– Monitoring; and,

– Offtake (Power Purchase Agreement).

• Each of these roles is a discrete activity that ideally should be managed by GOV agencies, acting independently.


Institutional Structure (2)

• A series of “Authorities” might be designated to formalize the different roles played by different arms of the GOV.



• Who might play these roles?

• Current allocations could be improved to limit crossover and conflicts.

– EVN companies as generator, SO, SB

– Primary energy companies as IPPs

• IBWG could be bolstered with permanent resources.

Entity Planning Procuring Contracting Monitoring Offtaking Cons enting SupplyingMOIT P P PMinistry of Planning and Investment PInter Branch Working Group PERAV PEVN Subsidiary or Successor company acting as purchaser in PPA S S PPetroVietnam S S PVinacomin S S PThe Ministry of Finance PThe State Bank of Vietnam PMinistry/ Departments of Natural Resources And Environment (MoNRE/DoNRE) PProvincial Peoples' Committees S P PMinistry of Justice (MoJ) PDepartment of Labour, War Invalids And Social Affairs (DOLISA) PDepartment of Immigration PMinistry of Construction P

P = Currently Plays a Primary RoleP = Could Play the Primary Role

S = Currently Plays a Secondary Role

Role(s)



• Nature of the Offtake Authority (BOT Counterparty)

– Ownership � must be government owned

– Lifetime � a single entity over the life of the BOT (unless successor can demonstrate equivalent credit quality and any government support linkages remain intact)

– Creditworthiness �

• sound business

• government guarantee and credit enhancement likely required (while Offtake Authority is unable to attract an S&P, or equivalent, investment grade rating)

• stranded cost recovery strategy

• broader security for market settlements

– Structural relationship with other power sector entities � Offtake Authority separate from MO/SO

– Prevailing legislation � Roadmap Decision: Single buyer to be developed under EVN, then evolve into independent wholesaler under WCM

• Recommendation: Ring-fenced subsidiary of EVN evolving to independent status in WCM


Thermal Generation BOT Procurement Process


Project Identification and Designation (1)

• BOT developers cover a worldwide market, allocating effort to future, known, projects;

• They favour projects identified by single buyers, market operators and/ system operators using least-cost planning principles;

• Vietnam’s least-cost generation expansion planning uses STRATEGIST/ WASP and follows international practice.

• However, the process by which the resulting projects are designated for development by EVN, IPPs or BOTs is less clear.

• Potential BOT developers may therefore be wary that BOT projects are either:

– “residual” projects that were unwanted by domestic players;

– that the BOT status of the project could be arbitrarily changed;



• Considerations would ideally include:

– The availability of domestic capital and development capabilities;

– Given plans for a market, ensuring an adequate number of market participants;

– The prospects for synergies across the value-chain. Some projects may have obvious developers (e.g. the Ca Mau power complex, mine-mouth coal-fired plants);

– BOT investors might be considered once these factors are exhausted, but once a decision is made it should not change;

• In addition to the preparation of the least-cost expansion plan, MOIT could oversee the following steps in a transparent manner during the masterplanning process :

– Assess the availability of domestic capital to fund new generation;

– Assign projects to domestic developers based on “natural fit”;

– If domestic capital < “natural fit” projects, review un-assigned projects using “Value for Money” (VfM) criteria.



• If a thermal generation project:

– has not been identified for development by domestic participants

– would be most effectively risk-managed by the international private sector, and

– has the capacity to be financed using international sources of finance,

– then it should be considered as a BOT candidate.


Creation of a Procurement Committee

• Interbranch Working Group (IBWG) is an appropriate and effective Procurement Committee.

• Performance could be enhanced with addition of a permanent secretariat

• ERAV could join as an observer to ensure adequate and efficient flow of information between Procuring Authority and Monitoring Authority.

• Conflicts of interest that could result by virtue of EVN, Petrovietnam or Vinacominparticipation in IBWG should be managed

– Chairperson could be granted authority to exclude IBWG members from consideration of particular matters that could result in a conflict of interest

– Confidentiality agreements and procedures to be adopted and applied for IBWG members

– PVN and Vinacomin could be excluded from involvement in participating in tender process to ensure no conflicts arise.

– Similarly EVN could be excluded once SB function is unbundled or spun-off


Documentation Development

BOT DecreeThermal

Generation BOT Circular

Model Tender Documents

Model Project Agreements

Thermal Generation

BOT Framework

Project Contract

PPA

Direct Agreement

Fuel Supply Agreement

Payment Guarantee

Prequalification Documents

Invitation Letter

Instruction to Bidders

Issue of Prequalification

Criteria

Bidding Forms

Minimum Technical

Specification

Existing

To be developed – This Framework

To be developed – Future

Development depends on Fuel Supplier

Legend

Included in Bidding Package

Invitation to Prequalify

Prequalification Proceedings

Bid Package

Phase One Phase Two We are here:



Prequalification – Advantages and Disadvantages

Advantages

• If only qualified firms or consortia are selected for bidding then they are more likely to commit time, money and resources to their proposals.

• The buyer also obtains an insight into the level of interest in the project.

• Any conflicts with advisors and others can be exposed early.

• Low price or “wild card” bids from unqualified bidders can be excluded.

• Fewer evaluation resources are required for proposal evaluation because fewer proposals likely to be made compared to open tendering.

Disadvantages

• Potential to increase procurement lead times.

• Potential for collusion amongst bidders can increase

• Buyer can pick favorites.

Conclusions

• Large, complex projects should be subject to prequalification but the pre-qualification process needs to be robust, objective and streamlined to produce equitable and cost-effective results.

• As all Thermal Generation BOT projects are large and complex, prequalification should apply in all cases where competitive solicitation is sought.





Request for Proposals

• Request for Proposals (RFP);

– Draft Project Contract;

– Draft PPA;

– Draft Fuel Supply Agreement;

– Other draft project agreements;

– Minimum technical requirements of the Thermal Generation BOT Facility;

– A grid code and metering code; and,

– Other project information including draft generation license, feasibility studies, interconnection studies, environmental and social impact studies and so forth.

• Regarding the RFP specifically, it should include:

– An invitation letter;

– Instructions to Bidders; and,

– Bidding Forms including a financial template.






Two Envelope Method – Why Use it?

• A two envelope system separates the Technical Proposal from the Financial Proposal.

• The Technical Proposal is evaluated first, without the evaluation committee knowing price information.

• Technical Proposals are evaluated on their own merits, without pricing bias being introduced.

• Only bids with Technical Proposals that meet a certain threshold have their Financial Proposals opened.

• Those that fail the technical test have their financial proposals returned unopened.

• Overall: A two envelope system reduces bias




Evaluation Criteria – Three Stages

• First Stage – Responsiveness.

– Each proposal shall be reviewed for completeness and substantial responsiveness according to a test to be specified in the model Request For Proposal;

• Second Stage – Technical Evaluation.

– For those proposals that pass the First Stage, Technical Proposals shall be evaluated to establish whether they meet the requirements of the Request For Proposal, particularly regarding compliance with the minimum technical specification.

• Third Stage – Financial Evaluation.

– The Financial Proposals are those proposals that pass the Second Stage shall be opened publicly and evaluated.

– A score shall be calculated based on

• Levelized cost of production

• Price adjustments to capture deviations to preferred (not mandatory) clauses of project agreements or specification

– The Bidder that has the lowest evaluated price shall be invited to finalize the Project Contract.



Important Considerations for Future BOT Legislation (1)

• A Two envelope system should be adopted because it increases impartiality

• There should be no reference to BT projects– BOTs minimize whole of lifecycle costs. Suggestions of BT awards to developers to recover inadequate profits from previous projects does not promote competition and may not be transparent.

• Provision should be made for a probity auditor to ensure the procurement process is followed diligently

• Provision for an appeals process, which gives comfort to bidders that their concerns will be dealt with fairly, should be made

• There are arguments for discontinuing the distinction between BOTs and IPPs

• Legislation should not prevent a company from joining more than one consortium


Important Considerations for Future BOT Legislation (2)

• Bid preparation timeframe should be realistic, such as a 90 day minimum period

• Bid validity periods should reflect supplier pricing limits. A period of 90 days that is extensible by a further 90 days with bidder agreement is workable

• Detailed procedures for submission of bids have been proposed by the Consultant and it is recommended that these are adopted.

• Timeframes for evaluation of bids should be clearly specified

• If a levelized tariff calculation is used as a basis for price evaluation, it should be the sole measure (with possible adjustments to account for deviations to non-mandatory specifications), so that double counting is avoided.

• Direct selection of developers, if required under specific circumstances, should be objective and transparent. The Consultant has recommended detailed arrangements for this type of selection.








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00


Gas Resources of Vietnam

Four major gas resourcesCuu Long Basin

Nam Con Son Basin

Malay – Tho Chu Fields



• Oil production from the Bach Ho field commenced in 1986 with the associated gas being flared

• Associated gas collected and piped 117 km (2.2 bcm/year pipeline capacity) to processing plant at Dinh Co

• Processing plant produces LPG, condensate and pipeline specification gas

• Major end users are the Phu My complex, Ba Ra power station and major industrial customers such as the Blue Scope Steel rolling plant

• Spur pipeline now to Rang Dong fields

• 2P reserves of 119.5 bcm of which 97.8 bcm remained in 2005

• PMP gives gas price as USD2.20/million BTU escalating at 2%

Cuu Long Basin Development


Nam Con Son Basin Development

• Exploration commenced 1992

• Production of oil from Dai Hung field commenced in 1994

• Production of gas and condensate from Lan Tay field commenced in 2003

• Further gas discovered close by will be developed to ensure continuing supply

• Gas transported to Dinh Co by 370 km long pipeline (capacity 7.0 bcm/year)

• Nam Con Son gas mixed with Cuu Long gas in a common on shore transmission system

• Major end users are the Phu My complex, Ba Ra power station and major industrial customers such as the Blue Scope Steel rolling plant

• 2P reserves of 150.5 bcm of which 144.1 bcm remained in 2005

• PMP gives gas price as USD3.22/million BTU escalating at 2%


The Phu My Complex

• Major power generation and fertiliser development to utilise Nam Con Son gas

• Total of 3900 MW of generation on the Phu My site

• Phu My 3 was the first gas fuelled BOT generation project in Vietnam

- developed by consortium of BP, Sembcorp, Kyushu Electric and Sojitz

- gas supply contract with PVN

- electricity supply contract with EVN

- BOT contract signed 1995, GSA, PPA, and EPC contracts signed 2001

- commercial operation early 2004

• Phu My 2-2 was second BOT plant commissioned early 2005

• Phu My fertiliser plant produces 740,000 tonnes/year of urea


The Phu My 3 BOT Project Structure


The Malay – Tho Chu Fields

• Located in an area with a boundary with Cambodia, Thailand and Malaysia

• Production sharing agreement signed with Talisman Malaysia in 1993

• Oil production commenced in 1997 and gas production in 2003

• All initial gas went to Petronas – PVN have right to take their 50% later

• Gas transported to Ca Mau by 397 km pipeline (capacity 2.0 bcm/year)

• Major end users are the Ca Mau 1 and 2 power plants (1500 MW) and a fertiliserworks is under construction

• 2P reserves of 151 bcm of which 97.8 bcm remained in 2005

• PMP gives gas price as USD0.45xMFO



• These fields are typical of others in the Gulf of Thailand

• Production sharing agreement signed with Unocal (now Chevron) in 1996

• Reserves estimates have been approved by the Government

• Gas typically has 23% inerts

• Field development will require 450-500 wells and up to 31 wellhead platforms

• Gas pipeline 278 km offshore plus 102 km onshore or 262 km offshore and 148 km onshore depending on route selected

• Major end users will be the Tra Noc power station (183 MW) and the O Mon development

• 2P reserves of 113 bcm with potential for a further 30 bcm

• Gas price has been under negotiation for some years


The O Mon Development

• The next major gas fuelled power generation complex in Vietnam is to be built at O Mon

– EVN currently building O Mon 1a (300 MW) – conventional steam plant able to operate on fuel oil or gas and scheduled for 2009 operation

– O Mon 1b (300 MW similar to 1a) currently scheduled in the Power Master Plan (PMP) for 2010 operation

– O Mon 2 – competitively tendered 750 MW CCGT BOT scheduled in the PMP for2013 commissioning

– O Mon 3 – EVN owned 750 MW CCGT scheduled in the PMP for 2011 commissioning

– O Mon 4 – EVN owned 750 MW CCGT scheduled in the PMP for 2014 commissioning

• Negotiations over gas price ongoing


Governing Gas Legislation - Existing

• Focus of the legislation has been on oil development rather than gas

• Gas sector operates under Petroleum Law (revised 2000 and 2008) and Decree 48/2000

• No comprehensive legislative or regulatory framework for gas and no formal regulatory process

• Petroleum Law

– provides for the Government to prepare a Gas Master Plan

– provides for the Government to approve reserves and field development plans

– there are issues around PSC partners rights to export gas


Governing Gas Legislation - Planned

• Four issues under development

– Decree implementing the revised Petroleum Law

– Gas Distribution and Transport Decree: status unknown

– National Gas Master Plan: being developed

– Comprehensive overhaul of the Petroleum Law to cover upstream, midstream and downstream operations


Governing Gas Legislation – the PSC Regime

• Oil and gas development in Vietnam is undertaken under a Production Sharing Contract (PSC) regime

• For new acreage, PVN prepares block tenders

• Successful bidder enters into a PSC – international partner is the Operator and undertakes exploration at their cost

• In event of discovery PVN has right to participate in the development and has to date purchased all the gas

• Recent changes to make the PSC agreement more like international joint venture agreements, with greater PVN participation

• PVEP (under PVN) becoming more active as a Contractor and/or Operator


The Ministry of Industry and Trade (MOIT)

• MOI established in 2003 under Decree No. 55/2003/ND-CP, later becoming MOIT

• Manages the state’s interests in the industrial sector – that includes energy

• Two MOIT departments manage energy – Energy and Petroleum Department and the Electricity Regulatory Authority of Vietnam (ERAV)

– Energy and Petroleum Department responsible for the preparation of the Power Master Plan and the Gas Master Plan

– ERAV was established to manage the introduction of competition to the electricity market

• MOIT responsible for managing and directing implementation of the national energy strategy


Gas Industry Institutional Relationships



PVNWholesale


Non-Generation End Users

All gassales

Gas flow


LPG




PSCPartners


PSCPartners

Prime Minister



The Vietnam Oil and Gas Corporation (PetroVietnam or PVN)

• A state owned company established in 1975 to participate in oil and gas exploration, development, and production

• PVN is the Government partner in production sharing contracts

• Also operates in the property development, finance, fertiliser production and power generation fields

• Operates upstream in the oil sector

• In the gas sector PVN:

– explores, develops, produces

– owns and operates gas transmission

– owns and operates gas treatment

– owns and operates gas distribution

– retails gas

– is a major gas end user

• PV Gas, a subsidiary, operates and maintains the gas pipelines and processing facilities


The Gas Master Plan Process (1)

• Gas master planning only just becoming established

• A national Gas Master Plan is under preparation by Institute of Petroleum (IP), a subsidiary of PVN

• A draft Southern Gas Master Plan (SGMP) which is narrower in scope than the GMP has been prepared

• In preparing the GMP or SGMP:

– there is stakeholder consultation

– a gas demand forecast is prepared

– gas reserves data bases are developed

– external supplies (e.g. LNG or international pipelines) are investigated

– forecast supply/demand tables and graphs are prepared

– necessary transmission development plans are developed

• On completion of draft GMP or SGMP it is submitted to MOIT for review

• Following review and revisions the GMP or SGMP will be submitted to the Prime Minister for approval


The Gas Master Plan Process (2)

MOITAppoints IP


Forecast

PMApproves

GMP

MOITReviews Draft

GMP



Forecast


PSC ReservesReports


Plans





The Draft Southern Gas Master Plan

• Plan has not been approved by Prime Minister

• Demand forecasts developed for South East area, which is supplied by Cuu Long and Nam Con Son basins and for South West area supplied by the Malay-Cho Thu fields and the Blocks B, 52/97 and 48/95

• Supply forecasts developed for firm gas supply, probable gas supply and possible gas supply

• Dominant end use (around 80%) is electricity generation

• To meet demand in SE area beyond 2009 on a firm basis will require additional field development

• Supply-demand balance better in South West

• Briefly looks at and rejects imported LNG and international pipelines as alternative to indigenous gas

• Includes plans for a gas pipeline linking the three major producing areas


Existing Electricity Institutional Relationships



EndUsers

EVNTransmission

ERAV

Electricity flow

EVN

Sellelectricity

Buyelectricity

ManagesthroughPMPprocess

Regulation

Regulates retailtariffs. Tariffs approved by Minister MOIT



Prime Minister

Approves PMP


Electricity Generation in Vietnam

• Total system electricity sales of 51,530 GWh in 2006

• Load growth over period 2000-2006 in the range 13-17%

• System generating plant in table below

2006 MW % MWh %

EVN

Hydro 4,583 37.09 19,096 32.33

Coal Fired 1,245 10.08 8,808 14.91

Oil Fired 198 1.60 54 1.11

Diesel 285 2.31 54 0.09

Gas Turbine (Gas & oil) 3,107 25.14 17,906 30.31

Total EVN 9,418 76.22 12,550 78.75

IPP/BOT 2,939 23.78 12,550 21.25

Total 12,357 59,068


The Present Power Master Plan Process (1)

• Electricity planning processes well established with Sixth Power Master Plan (PMP6) covering 2006-2015 approved by Prime Minister

• MOIT contacts Institute of Energy (IE, a subsidiary of EVN) to prepare the Power Master Plan

• In preparing the PMP, IE:

– consults with stakeholders

– prepares a national load forecast

– develops fuel availability and price data bases from coal and gas masterplans and imports

– develops generating plant efficiency and cost data bases

– undertakes least cost generation expansion planning

– prepares a proposed generation plant expansion schedule

– develops the necessary transmission development plans

• PMP6 forecasts 11.6% annual compound growth rate (ACGR) in energy demand now to 2025. (Demand doubles every 6 to 7 years).

• Installed capacity (including imports) planned to increase from 9,700 MW in 2005 to 24,919 MW in 2010


The Power Master Plan Process (2)

MOITAppoints IE

IE PreparesCost Data

Bases

PMApproves

PMP

MOITDesignates

DevelopmentModality


Plan


IE PreparesDraft PMP

Hydro Plans

IE PreparesDemandForecast

RegionalElectricity

Plans

IE PreparesFinal PMP





The Power Master Plan Process (3)

• Draft PMP including the proposed generation plant expansion schedule is submitted to MOIT for review

• MOIT decides the modality for development of the individual stations in the generation plant expansion schedule – i.e. which are to be developed by EVN, IPP, BOT or others

• IE revises PMP, MOIT reviews and Prime Minister approves

• Capital investment needs under PMP6 are estimated at USD114 billion

• To tap additional sources of investment, PMP6 stipulates 8,225 MW of BOT capacity will be commissioned before 2015, with another 6,450 MW as either BOT or IPP capacity.

• ERAV now developing a planning code to set the procedures for least cost generation expansion modelling to ensure least cost contracting by the SB under the CGM








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00


The Gas-to-Power Value Chain

• Gas-fired power generation is the outcome of a process that begins with gas field development

• This process may be represented through a simple gas-to-power value chain such as the one shown below. (These steps are not necessarily sequential)

• Each step of this process performed by one or more parties, and may affect other parties

• The allocation of risks at each stage determines the willingness of / attractiveness to a party to perform that activity

7. Power Production

8. Power Sales

1. Gas Field

Development

2. Gas

Transmission Development

3. Gas

Production

4. Gas Sales

5. Power Plant

Development

6. Power Transmission Development

Activity performed by:

Activity also affects or involves:

PSC

PSC

PVNpossibly PSC

PVN PVN

PSCPVN as seller BOT as buyer

PSC

BOT

BOT

BOTTransCo*

SB*

BOT as seller SB* as buyer

BOT PVN, EVN

* EVN or its subsidiaries currently perform SB and Transmission functions


Gas-to-Power Value Chain – Contractual Framework in Vietnam


GasTransmission

PowerStation



Energy Flow

GasWholesaler

GTA

PPA

TCA

GSAGSPA





FinancingAgreements

GSPA – Gas Sale and Purchase AgreementGSA – Gas Sales AgreementGTA – Gas Transport AgreementPPA – Power Purchase AgreementTCA –Transmission Connection Agreement

BOTAgreement

Risks are allocated through the contracts that govern the relationships between the parties operating along the gas-to-power value chain


The depth of the gas market determines the degree of linkage between upstream and downstream development

• In Vietnam currently gas fuelled power generation projects are field specific and tightly linked

• This is a shallow gas market – there are currently no competing gas suppliers and limited end-user options

• In a deep gas market, such as US or UK, then:

� The power station developer can � buy gas on a long term, short term or spot gas supply basis from a number of

suppliers� purchase gas transmission to suit gas supply sources

� The gas field developer can� sell gas to a range of end users on a long term, short term or spot basis� purchase gas transmission to transport the gas to the market

In a shallow gas market, a complex family of contra cts covering the gas field development and the end user project must be comple ted as a package for the

two developments to proceed


Risks and Risk Mitigation – BOT Development Chain

• With two highly interlinked developments (gas field and power station) there are many risks that could cause delays or problems in reaching commercial operation

• Some of these risks are common regardless of the modality of development and some are a function of the BOT process

We are now going to break the participants in to 4 groups to identify the risks to a gas fired BOT project, the impact of the se risks, and to suggest measures to mitigate these risks. Each group will r epresent one of the following parties:

• PSC

• PVN

• BOT

• SB (currently EVN)

Each group should appoint a representative to prese nt the findings to the workshop


Risk Analysis along the gas-to-power value chain

Stage of Value Chain

Risk to Party You Represent

Degree of Risk (high, medium, low)

Risk Mitigation Measure

1. Gas Field Development

2. Gas Transmission Development

3. Gas Production

4. Gas Sales

5. Power Plant Development

6. Power Transmission Development

7. Power Production

8. Power Sales








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00


Principal Gas Sector Issues

1. Implementation of approved national energy strategy

2. Increased stakeholder consultation in plan development

3. Gas pricing framework

4. Pipeline gas specification

5. Improved coordination between gas sector and power sector planning

6. Gas industry restructuring


National Energy Plan (1)

• Prime Minister has approved the National Strategy of Energy Development up to 2020, Vision to 2050

• This outlines in broad terms the government’s strategy for Vietnam, but does not quantify energy sources

• Planning presently by way of a series of sectorial master plans – gas, coal, power etc

• This process does not adequately address resource allocation from a national perspective – e.gis it better to use gas for electricity generation, fertiliser production or transport?

• Such matters should be covered by a Quantified National Energy Plan

– provides indicative targets

– consolidates and ensures consistency between sectoral master plans

• Would also be very useful as a tool to implement greenhouse gas policy

• Implementation of approved national energy plan required to:

– Improve coordination between sectors in energy market

– Optimize project development

– Minimize cost to the national economy

– Prevent cross-sector difficulties in implementing energy policies



• A Quantified National Energy Plan should be prepared covering issues such as:-

– demand for all forms of energy across all sectors of the economy

– indigenous and imported energy resources to meet these demands

– prioritization of energy technologies

– energy conservation and efficiency

– energy security

– environmental impacts

– sustainability and carbon impacts

– accessibility and social impacts

– government funding and support across fuels and sectors

– energy pricing and policy



Recommendation

That a Quantified National Energy Plan be prepared to underpin the sectoral master planning process and the implementation of energy sector reforms


Stakeholder Participation in the Planning Process (1)

• Institute of Energy and Institute of Petroleum consult with stakeholders when preparing PMP and GMP respectively

• However some stakeholders perceive insufficient information flow as the planning process progresses

• Particularly when foreign capital is required, such as for the BOT projects and gas field development, it is essential that there is a free flow of information to the financiers and that they have confidence in the process

• A dynamic planning regime, as proposed later, will significantly enhance stakeholder communication

• We understand that the ERAV planning process also suggests regular stakeholder consultation for the PMP. Similar processes should be developed for the GMP.



• The number of stakeholders in gas and electricity industries is increasing as competition is introduced and industrialisation increases

• For GMP and PMP processes to be successful these stakeholders must be consulted and their views incorporated as appropriate

– hold a stakeholders workshop at the kick-off of the planning process

– hold an update workshop once before preparation of the draft master plan

– hold a workshop to present the approved master plan

– hold a consultation workshop at the commencement of the annual update process

• The planning code being developed for ERAV may well address this issue for the PMP, but it also needs to be addressed for the GMP

• Some of the key stakeholders are:

– MOIT/ERAV

– EVN

– PVN

– IPP developers

– BOT developers

– Distribution companies

– End use customers

– PSC partners

– Financiers

– Development agencies



Recommendation

That there be greater stakeholder consultation in the preparation of the PMP and the GMP and that a formal structure of stakeholder consultation through workshops be implemented


Gas Pricing (1)

• First gas supply developed was the associated gas from Bach Ho field – low cost of development and priced at USD 2.20/million BTU escalating 2%

• Next development was the Nam Con Son supply - from a good reservoir and negotiated price of USD 3.22/million BTU escalating at 2%

• Malay-Tho Chu development gas price negotiated at USD 0.46xMFO

• Blocks B, 48/95 and 52/97 are high cost developments and the gas price for O Mon has been under negotiation for some years

• New CGM is based on least cost dispatch, but not yet clear how the rules or the new planning code and the calculation of Best New Entrant (BNE) will cope with fluctuating gas prices

• PMP6 was prepared using low gas prices and this may have skewed the plant mix in favour of gas fuelled generation

• Gas prices are set by negotiation (e.g. allowable costs for recovery under PSC), but high cost dry gas field developments face difficulties in reaching agreement especially if high prices have not been anticipated during the electricity or gas planning process


Gas Pricing (2)

• There is no single “correct” way to establish the price of gas

• Gas price for an electricity generation project can be determined on the basis of:

– cost of production

– value of the gas for alternative uses

– cost of alternative generation

– negotiation

• During negotiations the gas price will rise to the higher of the value for alternative uses or the price where it is cheaper to use an alternative fuel for generation

• If gas prices rise above the willingness to pay level then the gas field may not be developed and alternative fuels will be utilised


Gas Pricing – World Gas Prices

Country Location

Price

Aug 2008

(USD/MMBtu)

Price

Jan 2009

(USD/MMBtu)

USA SoCalGas 7.64 7.37

USA Henry Hub 8.26 7.66

Japan Gas linked 12.12 14.61

Japan Oil linked 22.67 19.00

Netherlands Title Transfer Facility

11.19 10.15

UK National Balancing Point

10.31 10.43

Source FERC & Platts


World Gas Price Volatility


Gas Price Formation (1)

• Information from the gas industry is critical to the electricity planning process

• Information required includes:

– reserves quantity

– delivered gas price

– timing of gas developments

• In PMP6 low gas prices were utilised, increasing gas fired generation in the plant mix

• The next major gas field for development is Block B, and development has stalled due to the high cost of the Block B gas

• A two stage process, based around the Outline Field Development Plan and the Final Field Development Plan, is suggested to develop an indicative gas price

• This two stage process can then be used for least cost generation expansion modelling and for prices for the electricity planning process

• These prices are not intended to be used for the GSPA or the GSA, where the actual price will be established by negotiation



PSCDiscovery

Draft ReservesAssessment


GOV InitialApproval



GOV FinalApproval

ProjectDevelopment

GMP Preparation

GMP AnnualUpdate

Initial Price and ReservesInformation

Updated Price and Reserves InformationInformation

Initial GasPrice and ReservesInformation to PMP

Updated GasPrice and Reserves Information to PMP



Recommendation

That for new field developments a two stage indicative gas price formation process driven off the Outline Field Development Plan and the Final Field Development Plan be utilised to provide more accurate gas price information to the gas and electricity master planning process


Updating the Master Plans

• The GMP and the PMP are prepared under a 5 year planning cycle

• We understand reviews of the PMP are undertaken but the outcomes are not promulgated

• The GMP has not yet been approved

• To maintain relevance in the fast changing world energy markets, the PMP and GMP should be completed together and updated on a regular basis

• The planning process will become more complex with the introduction of the CGM and the associated Planning Code and the processes for calculating BNE

• We understand that the planning code being developed by ERAV will include annual updates of the PMP. Similar processes should be implemented for the GMP


Updating the PMP (1)

• A 5 year plan without published updates will not be effective in the rapidly changing domestic and international energy market

• PMP7 is now under preparation and once approved an updating supplementary plan should be published every year

• The annual update should include things such as:

– changes in demand forecasts

– changes in fuel prices

– changes in generating plant costs

– revised least cost generation expansion plan

– updated tables and graphs

• We understand that the draft planning code being developed by ERAV and international consultants may incorporate annual reviews of the PMP


Updating the PMP (2)

Recommendation

That a process of annual review and update be established for the PMP, and that the results of the annual review should be published as an addendum to the PMP.


Electricity Load Forecasting (1)

• Load forecasting is a critical part of the PMP process, and impacts on the GMP process

• PMP6 has very high load forecasts, that drive the very large new generation requirements

• There has been a major world economic downturn – has this affected electricity demand in Vietnam?

• PMP7 is now under preparation and will include new load forecasts

• Because the load forecast is so critical to the PMP process, an independent expert review process for this load forecast should be included in the PMP process


Electricity Load Forecasting (2)

Recommendation

That an independent expert review of the electricity load forecasts be undertaken to establish benchmark forecasts for the ongoing annual PMP review process


Least Cost Generation Planning (1)

• The least cost generation expansion planning model is at the core of the PMP process

• The output of the least cost generation expansion model is only as good as the inputs

• A critical input is fuel quantity and cost

• For PMP6 the fuel input assumptions were low, and a number of projects have stalled at the point of negotiating fuel supply contracts

• To help ensure a more robust process, the output of the two stage gas price formation process should be used as an input for the PMP process


Least Cost Generation Planning (2)

Recommendation

That the output from the two stage gas price formation process recommended for the GMP be used as an input for the PMP and CGM Planning Code processes.


Updating the GMP (1)

• GMP still being prepared

• It is assumed that GMP will be similar to the other master plans and follow a 5 year cycle

• A 5 year plan without published updates will not be effective in the rapidly changing domestic and international energy market

• To be effective the GMP should be prepared and approved quickly

• An annual update of the GMP should be prepared and an updating supplementary plan published every year

• The annual update should include things such as:

– changes in reserves

– timing of projects

– changes in gas prices

– revised supply/demand forecasts

– updated tables and graphs


Updating the GMP (2)

Recommendation

That the GMP be prepared and approved within a six month period, a process of annual review and update be established, and that the results of the annual review should be published as an addendum to the GMP


Pipeline Gas Specifications (1)

• Gas specification from the four fields developed and under development is different

• Gas from Cuu Long and Nam Con Son basins is treated and mixed – low level of inerts

• Gas from Malay Cho Thu fields is around 8% inerts

• Gas from Blocks B, 48/95 and 52/97 is 23% inerts

• No national pipeline gas specification

• If the four producing areas are to be linked then a national gas pipeline specification will be required and gas treatment will be required

• Major customers, such as a generating plant, may stay on the raw gas specification from the field but then won’t get the benefit of back-up sources of supply

• Linking the producing fields and introducing a national gas pipeline specification may allow better optimisation of field development


Pipeline Gas Specifications (2)

Recommendation

That the costs and benefits of developing a common pipeline gas specification for the country and the interconnection of the producing fields be investigated further



• The electricity industry is undergoing a major restructuring to introduce competition to the market

• The electricity restructuring includes the separation of the monopoly (transmission and distribution) parts from the competitive (generation and retailing) parts

• There are no such plans for the gas industry

• Properly formulated gas and electricity transmission pricing will give the right signals for comparing gas and electricity transmission costs when locating new generating plant

• An open access gas transport regime would help to promote competition in the electricity market and help accelerate gas development by eliminating the need for back-to-back negotiations between the PSC and PVN, and between PVN and the generator

• It is difficult to have competition in the electricity market when the gas supplier also owns the gas transmission system and is itself a major electricity generation plant developer

• A competitive gas “market” with transparent transmission pricing will give PSC partners confidence for their investment decisions


Gas Industry Restructuring (1)

• A road map has been prepared for the electricity industry restructuring that lays out a path to greater competition in the electricity market

• To achieve competition in the electricity market the gas market must be structured with an open access regime for gas transmission and competition for gas supply

• The gas industry is presently vertically integrated and controlled by PVN

• A road map for the gas industry, similar to that prepared for the electricity industry, would facilitate development of policy for the gas industry


Gas Industry Restructuring (2)

Recommendation

That a road map be prepared for the gas industry in Vietnam with the objective of introducing greater competition to the gas market








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00


BOT Development Risks

MOITProcures

BOT


NegotiateBOT

Agreement


NegotiatePPA

PowerPlant

Developed


Agreement

EPCContract


GasFieldDeveloped



1

Risks

2

3

4

5

6 10

9

7

8


Gas Specific BOT Development Risks, Impacts and Mitigation (1)

Risk No


5A

Unable to negotiate GSA

No contract, no project Thorough GMP process to ensure likely gas price allows a generation project to proceed

Indicative gas price in BOT tender documents

Draft GSA in BOT tender documents

5B

Protracted GSA negotiations

Project cost escalation As 5A above

Facility to update PPA contract for changes in EPC contract price

6A

Unable to negotiate gas transport agreement

No contract, no project Standard gas transmission pricing and access regime

Draft gas GTA in BOT tender documents


Gas Specific BOT Development Risks, Impacts and Mitigation (2)

Risk No Risk Impact Mitigation

6B

Protracted GTA negotiations


As 6A above


9A

Gas field development delayed

BOT developer unable to meet obligations under PPA and financing agreements

Liquidated damages clauses under the GSA contract

PPA provides for fixed cost payments to BOT if unavailability is not BOT’s fault

9B

Gas field does not deliver at the required rate or for the contracted time

BOT developer unable to meet obligations under PPA and financing agreements

Force majeure under the PPA and financing agreements

Liquid fuel back-up

Reserves estimates to international standards

PPA provides for fixed cost payments to BOT if unavailability is not BOT’s fault

10

Gas transport unavailable at commissioning


Liquidated damages in gas transmission contract

Liquid fuel back-up

Developer stake in gas transmission construction


Common BOT Development Risks, Impacts and Mitigation (1)

Risk No.


1A

Unable to agree PPA price and terms

No contract, no project Thorough PMP process to ensure project viability before BOT tender

Draft PPA in BOT tender documents

Indicative gas price and draft GSA in BOT tender documents

Use competitive tendering to minimize need for price negotiations

1B

Protracted PPA negotiations



2A

Unable to agree TCA price and terms

No contract, no project Standard electricity transmission pricing and access regime

Draft TCA in BOT tender documents



Risk No


2B

Protracted TCA negotiations



3A

EPC contract price varies

Increased cost to BOT developer

Efficient BOT process to keep period from tender to approval of BOT and other contracts short


4A

Unable to agree BOT contract terms

No contract, no project Standard BOT contract in BOT tender documents

4B

Protracted BOT negotiations





Risk No. Risk Impact Mitigation

7

Electricity transmission not available at commissioning


Liquidated damages in electricity transmission contract

Developer stake in electricity transmission construction as part of an end-to-end risk management

8

Power station commissioning delayed

BOT developer has to meet obligations under PPA, GSA, TCA and GTA

Liquidated damages clauses in EPC contract


Risk Allocation Exercise Summary

PSC BOT

Coordination /Project

Interdependency

Territorial dispute

Development costs

Market price & demand

Construction delay

Offtaker risks

Political / Country Risk

Good planning

Diplomacy Good regulation

Good planning & regulation indicates mitigation Government

can provide

indicates risks identified by working groups

Good documentation (e.g. BOT contract)

Good documentation (e.g. BOT contract)

Credit enhancement


Institutional Measures to Reduce Risk (1)

• Government (through MOIT) can reduce some of the BOT development process risks

– Planning risks – it is important to build confidence in the electricity and gas planning processes through a robust and dynamic planning process

Recommendation

Develop a robust process of gas and electricity planning to ensure that the projects that proceed through to BOT development are viable in the electricity and gas markets that prevail at that time


Institutional Measures to Reduce Risk (2)

• Government (through MOIT) can reduce some of the BOT development process risks

– BOT process risks – it is important that the BOT developer selection process is robust, transparent, and includes all possible information to reduce the developers risk

Recommendation

Spend the necessary time before the BOT tender documents are issued to prepare a comprehensive set of draft contract documents covering the BOT, GSA, PPA, GTA and ETA contracts


Case Study - Introduction

• Case study looks at the development process for O Mon and the Blocks B, 48/95 and 52/97

• Also looks briefly at experience in Thailand and Indonesia

• The planning processes suggested in this report may need to be modified to accommodate the new ERAV CGM Planning Code

• The O Mon project has been chosen as a case study as it has stalled due to some of the issues discussed earlier


Case Study – Existing Planning Processes (1)

• Existing processes are conducted are not sufficiently integrated or linked

– a gas reserves assessment process

– a field development plan process

– a GMP process

– a PMP process

• For the O Mon generation plant, the gas field development process didn’t signal to the PMP process that field development costs for a field involving 450-500 wells to produce dry gas would result in relatively more costly gas

• The GMP process was still in initial development, and the PMP process utilised a low gas price in the least cost generation expansion modelling

• The PSC must negotiate gas prices with PVN, who must then consider whether they can in turn sell that gas profitably to a BOT

• The result is protracted negotiations and project delays


Case Study – Existing Planning Processes (2)

GSPA, GSA, PPA, GTA, ETA, Negotiations

Discovery

PM Approval



PM Approval



MOIT Contracts IP

Draft GMP

MOIT Contracts IE


Draft PMP

MOIT Review

PM Approval


Demand Forecast

Gas Reserves Information Gas Price Information from previous projects


Demand Forecast


Case Study – Proposed Planning Process (1)

• Under the proposed planning processes the rigid 5 year cycle master plans will be enhanced to a dynamic process that includes greater coordination and annual updating of the PMP and GMP

• For new gas discoveries the two stage indicative gas price formation process will be utilised.

– Though final gas prices will depend upon agreement on allowable cost recovery, the Outline FDP and FDP provide the best available basis for price estimates.

• The objective of the two stage indicative gas formation process is to identify early the likely gas price from a new gas field. This prevents generating projects based on the new gas fields reserves being incorporated incorrectly in the least cost generation expansion planning model

• If a new gas field passes the first stage indicative gas price formation process then it can be included in the next iteration of the PMP and GMP, and the gas field developers will have greater confidence that there is a market for the gas

• For BOT projects it is essential that all the issues and risks are understood at the time of BOT tender, including gas pricing issues



Discovery

Is Indicative Gas Price

OK?

Initial ReservesAssessment


No

Yes


Costs



Is Updated Gas Price

OK?No

Yes


Costs

GMPProcess

GMPAddendum


Model


Model



GSPA, GSA, PPA, GTA, ETA, Negotiations

Discovery

PM Approval



PM Approval



MOIT Contracts IP

Draft GMP

Demand Forecast

MOIT Contracts IE


Draft PMP

MOIT Review

PM Approval


Demand Forecast



MOIT Review

PM Approval



• In the event that a project strikes problems there are a number ways that government can facilitate a project:

– special tax regime or other benefits for BOT developer

– special tax, royalty regime or production split for PSC partners

– provision of land, water supply, waste water and transmission connections

• The outcomes for the Block B – O Mon development might have been:-

– that O Mon was dropped from the least cost generation expansion plan and replaced by another gas plant having cheaper gas or a coal plant

– the field developers might have found an alternative higher value use for the gas

– O Mon may have retained its position in the least cost generation development plan


Thailand Experience – Energy Sector

• Energy sector undergoing reform to make more transparent and more competitive

• Energy sector dominated by two state owned companies – EGAT and PTT

• PTT corporatised and has completed an IPO. EGAT corporatisation stalled – now statutory corporation

• Ministry of Energy established 2002

• New Energy Act effective December 2007

• Energy Regulatory Commission established - covers gas and electricity regulation

• Draft regulations under Energy Act under preparation

• Thailand has conducted two solicitations for IPP bids

– in 1994 seven PPA contracts were signed and all projects obtained finance

– in June 2007 second solicitation and four developers selected for 4400 MW of capacity – the PPAs will be signed shortly

• Solicitation conducted by Energy Planning and Policy Office using an electronic process with standard PPA documents and clear evaluation procedures


Thailand Experience – Power Planning

• Three state entities involved in electricity sector

– Generation and transmission – EGAT

– Provincial distribution and retail – Provincial Electricity Authority (PEA)

– Urban distribution and retailing – Municipal Electricity Authority (MEA)

• Power Development Plan (PDP2007) approved by National Energy Policy Council (NEPC) and endorsed by Cabinet

• To cater for changes in market, revised plan (PDP2007 Revision 1) submitted to NEPC for approval

• PDP prepared by EGAT under policy framework of Ministry of Energy

• National load forecast prepared by Thailand Load Forecast Sub-Committee

• Growth rate around 6%, down from previous 13% rate

• PDP process includes least cost generation expansion modelling


Thailand Experience – Gas Planning

• Gas sector dominated by PTT which is vertically integrated

• Gas infrastructure more developed in Thailand than Vietnam, with interlinking of the gas fields and import from Malaysia and Myanmar

• Electricity uses 71% of gas sold

• PTT runs a gas pool process for all end users

• IPP pay gas pool price plus 1.75% supply margin plus a fixed transmission tariff

• Because PTT is vertically integrated gas planning is internalised within PTT


Lessons From the Thailand Experience

• It requires great political determination to carry through regulatory reform in the energy industry

• Separation of the functions of policy development, regulation and company operation is important

• Even if a degree of competition is developed in the energy markets regulation is still required, particularly for the monopoly aspects of the industry. One regulatory authority covering gas and electricity is an effective way of reducing overheads and ensuring that similar regulatory regimes are established for both energy types

• Open access regimes with regulated published tariffs are required for gas and electricity transmission

• The benefits to Vietnam of establishing a national gas quality standard, linking the various gas sources and establishing a gas pool price should be investigated

• Master Plans should not be fixed, but should be revised as market conditions change

• An open and participative process is required to develop the load forecast that underpins the PMP

• With well prepared standard contracts and fuel and electricity price information, a BOT tender process can proceed to signing quickly


Indonesian Experience

• Indonesian petroleum sector previously structured like Vietnam

– Pertamina, the Indonesian national oil & gas company, functioned like PVN

• functioned as mandatory partner to PSCs

• prepared acreage for tenders

• negotiated, signed and supervised PSC contracts

• purchased all gas production and maintained monopoly on all gas sales

– The President approved the selection of bidders for block awards, like the Prime Minister

• Indonesia’s Oil & Gas Law No 22/2001 totally restructured industry

– Pertamina treated like any PSC. Foreign PSCs no longer required to partner with Pertamina

– New body (BP Migas) established as Government counterpart to PSC

– New regulator (BPH Migas) for downstream activities

– Director General of Oil & Gas awards blocks

– Domestic gas sales conducted on direct basis between producer and consumer

– Introduced Domestic Market Obligation (DMO)


Previous Structure of Indonesian Gas Sector

Pertamina

Pertamina

Gas Producers

Gas flows

ConsumersOil and gas producers include:� Total FinaElf� ExxonMobil� VICO� BP� ConocoPhilips� Unocal� Caltex� PetroChina

Gas Producers

Gas Producers

Gas Producers

Foreign PSCs

LNG


“Migas”

Sets tariffsAwards & supervises PSCs; partner with all PSCs

President of

Indonesia

Approves block tender awards


Current Structure of Indonesian Gas Sector

Pipeline Companies, e.g.

PGN

Gas Producers

Gas flows

Consumers

Upstream Implementing Agency

“BP Migas”Signs & supervises PSCs; Appoints sellers of Gov’t share

Oil and gas producers include:� Total FinaElf� ExxonMobil� VICO� BP� Pertamina� ConocoPhilips� Unocal� Caltex� PetroChina

Gas Producers

Gas Producers

Gas Producers

Oil & Gas Producers

LNG

Downstream Regulator

“BPH Migas”


“Migas”

Sets pipeline & retail tariffs for small consumers

Develops sector policies, standards & processes; Offers

new blocks; Manages data

Energy Conversion Companies, e.g.

small power plants or LPG processors

Gas products (e.g. LPG) or Electricity


Development of the Indonesian Gas Sector

Domestic gas infrastructure and consumption have in creased steadily despite rising prices

Natural Gas Consumption

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Year

MMSCF

0

1

2

3

4

5

6

7

USD/MMBTU 1,000KMs

Domesticconsumption inMMSCFPrice inUSD/MMBTU

Pipeline length in1,000 KM

New Oil & Gas Law

Operationalization of new agencies

Typical gas prices prior to Law 22/2002

Typical current gas prices








6. Break 10:00 – 10:15







13. Lunch 12:30 – 2:00


Summary of Consultant Recommendations (1)

BOT Market Integration

1. Contract future BOTs using a hybrid PPA that converts from a traditional two-part PPA to a collar CfD upon introduction of WCM

2. Procure BOTs competitively to establish the amount of downside risk BOTs are willing to accept in exchange for upside potential

BOT Tendering Framework

1. Establish a competitive tendering framework for new BOTs consistent with international practice

2. Strengthen the IBWG and eliminate or mitigate potential conflicts of interest among members

3. Clarify to stakeholders how development modalities are assigned

4. Use prequalification

5. Put the time & effort into preparing thorough RFPs & documentation

6. Use a two envelope approach

7. Set & maintain realistic time frames

8. Establish a creditworthy BOT counterparty that will remain intact through evolution of the market


Summary of Consultant Recommendations (2)

Gas and Power Coordination

1. Prepare a Quantified National Energy Plan

2. Expand stakeholder consultation in the energy planning processes

3. Use a two stage process for indicative gas price formation driven off the field development plans

4. Investigate costs and benefits of a national pipeline gas specification and producing field interconnection

5. Update draft GMP and complete together with PMP7 and update the PMP and GMP on an annual basis

6. Undertake an independent expert review of the PMP demand forecast

7. Prepare a roadmap for the reform of the gas industry

8. Formulate and apply regulations that implement the above strategies and policies, particularly with respect to consistent pricing across the gas-to-power value chain.


Closing Remarks from MOIT

Date post:	04-Apr-2021
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